World Small Hydropower Development Report 2016

World Small Hydropower Development Report 2016

Disclaimer Copyright © 2016 by the United Nations Industrial Development Organization and the International Center on Small Hydro Power The World Small Hydropower Development Report 2016 is jointly produced by the United Nations Industrial Development Organization (UNIDO) and the International Center on Small Hydro Power (ICSHP) to provide development information about small hydropower. The opinions, statistical data and estimates contained in signed articles are the responsibility of the authors and should not necessarily be considered as reflecting the views or bearing the endorsement of UNIDO. Although great care has been taken to maintain the accuracy of information herein, neither UNIDO, its Member States nor ICSHP assume any responsibility for consequences that may arise from the use of the material. This document has been produced without formal United Nations editing. The designations employed and the presentation of the material in this document do not imply the expression of any opinion whatsoever on the part of the Secretariat of the United Nations Industrial Development Organization (UNIDO) concerning the legal status of any country, territory, city or area or of its authorities, or concerning the delimitation of its frontiers or boundaries, or its economic system or degree of development. Designations such as ‘developed’, ‘industrialized’ and ‘developing’ are intended for statistical convenience and do not necessarily express a judgment about the stage reached by a particular country or area in the development process. Mention of firm names or commercial products does not constitute an endorsement by UNIDO. This document may be freely quoted or reprinted but acknowledgement is requested. Suggested citation: The World Small Hydropower Development Report 2016: United Nations Industrial Development Organization, Vienna, and International Center on Small Hydro Power, Hangzhou. The digital copy is available on www.smallhydropower.org Cover image: Adobe Stock Copy-editing and design: Booksmith Productions

Table of Contents Foreword

1

Chen Lei, Minister of Water Resources, People’s Republic of China and Honorary Chairman, INSHP

Foreword

3

LI Yong, Director General, UNIDO

Acknowledgements

4

Executive Summary

6

Chapter 1

Africa

1.1 Eastern Africa 1.1.1 Burundi 1.1.2 Ethiopia 1.1.3 Kenya 1.1.4 Madagascar 1.1.5 Malawi 1.1.6 Mauritius 1.1.7 Mozambique 1.1.8 Réunion 1.1.9 Rwanda 1.1.10 South Sudan 1.1.11 Uganda 1.1.12 United Republic of Tanzania 1.1.13 Zambia 1.1.14 Zimbabwe

1.2 Middle Africa

40

1.3 Northern Africa

44 48 51 57 60 63 68 72 75 80 83 89 94 98

1.3.1 Algeria 1.3.2 Egypt 1.3.3 Morocco 1.3.4 Sudan 1.3.5 Tunisia

101

1.2.1 Angola 104 1.2.2 Cameroon 107 1.2.3 Central African Republic 111 1.2.4 Congo 113 1.2.5 Democratic Republic of the Congo 116 1.2.6 Equatorial Guinea 119 1.2.7 Gabon 121 1.2.8 Sao Tome and Principe 124

1.4 Southern Africa 1.4.1 Botswana 1.4.2 Lesotho 1.4.3 Namibia 1.4.4 South Africa 1.4.5 Swaziland

1.5 Western Africa 1.5.1 Benin 1.5.2 Burkina Faso 1.5.3 Côte d’Ivoire 1.5.4 Gambia 1.5.5 Tunisia 1.5.6 Guinea 1.5.7 Liberia 1.5.8 Mali 1.5.9 Nigeria 1.5.10 Senegal 1.5.11 Sierra Leone 1.5.12 Togo

127 130 133 137 141 144

147 150 152 155 158 161

165 169 172 175 178 181 185 188 192 195 200 203 206

Chapter 2

Americas

2.1 Caribbean

210

2.1.1 Cuba 213 216 2.1.2 Dominica 2.1.3 Dominican Republic 218 2.1.4 Grenada 221 224 2.1.5 Guandeloupe 2.1.6 Haiti 226 229 2.1.7 Jamaica 2.1.8 Puerto Rico 233 2.1.9 Saint Lucia 236 2.1.10 Saint Vincent and the Grenadines 238

2.2 Central America 2.2.1 Belize 2.2.2 Costa Rica 2.2.3 El Salvador 2.2.4 Guatemala 2.2.5 Honduras 2.2.6 Mexico 2.2.7 Nicaragua 2.2.8 Panama

240 244 248 251 254 257 259 265 268

2.3 South America

271

2.3.1 Argentina 274 2.3.2 Bolivia (Plurinational State of) 277 2.3.3 Brazil 282 2.3.4 Chile 285 288 2.3.5 Colombia 2.3.6 Ecuador 290 293 2.3.7 French Guiana 2.3.8 Guyana 295 2.3.9 Paraguay 298 301 2.3.10 Peru 2.3.11 Uruguay 305

2.4 Northern America 2.4.1 Canada 2.4.2 Greenland 2.4.3 United States of America

307 310 314 316

Chapter 3

Asia

3.1 Central Asia 3.1.1 Kazakhstan 3.1.2 Kyrgyzstan 3.1.3 Tajikistan 3.1.4 Turkmenistan 3.1.5 Uzbekistan

3.2 Eastern Asia 3.2.1 China 3.2.2 Democratic People’s Republic of Korea 3.2.3 Japan 3.2.4 Mongolia 3.2.5 Republic of Korea

3.3 Southern Asia 3.3.1 Afghanistan 3.3.2 Bangladesh 3.3.3 Bhutan 3.3.4 India 3.3.5 Islamic Republic of Iran 3.3.6 Nepal 3.3.7 Pakistan 3.3.8 Sri Lanka

324 327 330 334 338 341

345 348 353 355 359 362

366 369 372 375 378 382 385 388 392

3.4 South-Eastern Asia 3.4.1 Cambodia 3.4.2 Indonesia 3.4.3 Lao People’s Democratic Republic 3.4.4 Malaysia 3.4.5 Myanmar 3.4.6 Philippines 3.4.7 Thailand 3.4.8 Timor-Leste 3.4.9 Viet Nam

3.5 Western Asia 3.5.1 Armenia 3.5.2 Azerbaijan 3.5.3 Georgia 3.5.4 Iraq 3.5.5 Jordan 3.5.6 Lebanon 3.5.7 Saudi Arabia 3.5.8 Syrian Arab Republic 3.5.9 Turkey

395 398 403 406 409 413 417 421 424 427

430 434 437 440 445 448 451 455 458 460

Chapter 4

Europe

4.1 Eastern Europe 4.1.1 Belarus 4.1.2 Bulgaria 4.1.3 Czechia 4.1.4 Hungary 4.1.5 Republic of Moldova 4.1.6 Poland 4.1.7 Romania 4.1.8 Russian Federation 4.1.9 Slovakia 4.1.10 Ukraine

4.2 Northern Europe 4.2.1 Denmark 4.2.2 Estonia 4.2.3 Finland 4.2.4 Iceland 4.2.5 Ireland 4.2.6 Latvia 4.2.7 Lithuania 4.2.8 Norway 4.2.9 Sweden 4.2.10 United Kingdom of Great Britain and Northern Ireland

Chapter 5

466 470 472 476 480 483 486 491 494 500 503

508 511 513 516 518 521 524 527 530 534

4.3 Southern Europe

541

4.3.1 Albania 4.3.2 Bosnia and Herzegovina 4.3.3 Croatia 4.3.4 Greece 4.3.5 Italy 4.3.6 Montenegro 4.3.7 Portugal 4.3.8 Serbia 4.3.9 Slovenia 4.3.10 Spain 4.3.11 The former Yugoslav Republic of Macedonia

544 547 551 554 557 561 564 567 571 575 578

4.4 Western Europe

581

4.4.1 Austria 4.4.2 Belgium 4.4.3 France 4.4.4 Germany 4.4.5 Luxembourg 4.4.6 The Netherlands 4.4.7 Switzerland

584 588 591 594 596 599 602

537

Oceania

5.1 Australia and New Zealand 5.1.1 Australia 5.1.2 New Zealand

606 608 611

Technical Notes and Abbreviations List of abbreviations Technical abbreviations

5.2 PICT

614

5.2.1 Fiji 5.2.2 New Caledonia 5.2.3 Papua New Guinea 5.2.4 Solomon Islands 5.2.5 Vanuatu 5.2.6 Federated States of Micronesia 5.2.7 French Polynesia 5.2.8 Samoa

618 621 625 628 632 635 637 640

642

Foreword CHEN Lei, Minister of Water Resources, People’s Republic of China and Honorary Chairman, INSHP Hydropower is an internationally recognized source of clean and green energy, which has played an important role for the global energy supply. Driven by the increasing demand for energy and global climate change, many countries have given priority to hydropower development in the expansion of their energy sectors. Small hydropower has unique benefits – it is a mature technology which is economically feasible and has minimal impact on the environment. Small hydropower has greatly contributed to solving the problem of rural electrification, improving living standards and production conditions, promoting rural economic development, alleviating poverty as well as reducing emissions. Moreover, small hydropower is an economically efficient technology, and as such, has been highly favoured by the international community, especially by developing countries.

Currently, the Chinese economy has entered a “new normal” characterized by increasing energy demand, as well as ecological and environmental problems, and therefore faces the critical need to adjust the energy mix, improve energy efficiency and ensure energy security. The Government of China advocates for the development concepts of “Innovation, Coordination, Green Development, Opening Up and Sharing” and the energy strategy policy of “Conservation, Clean, and Safe”; it promotes a clean, highly efficient, safe, sustainable and modern energy sector, which is reflected in the Energy Development Strategy Action Plan 2014-2020. China has a great potential for hydropower, which is an important renewable energy source. The Government will actively promote further hydropower development while taking into consideration the environmental and resettlement issues. Meanwhile, SHP development will be incorporated into a poverty alleviation strategy, and will be adapted to local conditions. By 2020, the total installed hydropower capacity of China will have reached 350 GW, of which small hydropower will account for 81 GW.

China is the largest developing country in the world as well as the country endowed with the richest hydropower resources. The Government has promoted hydropower to a significant position. By the end of 2015, the total hydropower capacity of China reached 320 GW with an annual output of 1,100 TWh. Hydropower plays an essential role in the energy sector of China, contributing to the adjustment of the energy mix, emission reductions, as well as the economic development of the country, which has also promoted and led hydropower development worldwide. During the 12th Five-year Plan, the Government of China paid particular attention to the small hydropower sector, promoting the people’s “well-being, and safe, green, and harmonious” small hydropower development. To date, 4,400 SHP plants (up to 50 MW) have been upgraded and refurbished; as a result, installed capacity and annual output have increased by more than 20 per cent and 40 per cent respectively. Furthermore, 300 counties completed the objectives of the New Hydropower Rural Electrification County Programme by developing 5,150 MW of newly installed SHP capacity, which accounted for 50 per cent of the total increase in SHP capacity. Additionally, through the national programme Replacing Firewood with SHP, 592,000 households, totalling 2.24 million people, have been provided with access to electricity and 733,333 hectares of forest have been saved. The total installed SHP capacity of China has exceeded 75 GW, with an annual output of 230 TWh, thus, meeting the target set by the Medium and Long-term Renewable Energy Development Plan five years ahead of schedule.

The achievements of China in small hydropower development have received worldwide attention, representing a good example for other countries. Therefore, the establishment of the International Network on Small Hydro Power (INSHP) and the International Center on Small Hydro Power (ICSHP) in China, was a logical choice. INSHP is the first international organization headquartered in China. Following its mission of an international and non-profit organization and serving the host country, ICSHP is committed to South-South cooperation, global development of small hydropower and promotion of Chinese hydropower enterprises undertaking business activities abroad. The Center has made remarkable achievements in the past 20 years. It has created a unique triangular model of cooperation between international organizations, developing and developed countries. ICSHP has become the international hub for small hydropower, leading the development trend in the international small hydropower industry and disseminating the experience, knowledge and capability of China to countries all around the world. As the host country of INSHP, the Government of China has always supported the initiatives of INSHP and ICSHP, including cooperation with other international organizations such as the United Nations Industrial 1

small hydropower development. Other issues covered in country reports include information on the power grid structure, electricity tariffs, short-term projects planned by governments, incentives, policies and plans for renewable energy development. Every effort has been made by the authors, ICSHP and UNIDO to make WSHPDR 2016 more comprehensive, practical and authoritative.

Development Organization (UNIDO), and independent experts and scholars, in order to share the successful experience of the Chinese small hydropower industry with other countries and regions, and to promote the development of small hydropower worldwide. In December 2013, the first English version of the World Small Hydropower Development Report 2013 (WSHPDR 2013) was published by ICSHP and UNIDO. The WSHPDR 2013 was established with a global vision for small hydropower development: to provide baseline information and a strategic outlook for regional and international institutions as well as countries to develop their renewable energy plans and ensure integrated management of water resources. The report has become an important knowledge platform for global development of small hydropower.

Today, the world is entering a new era—an era of lowcarbon energy, characterized by dramatic changes in the energy supply-demand relationship. The Government of China is willing to share Chinese technological innovations in small hydropower with the international community, and to advocate the idea of green development of small hydropower, as well as to warmly welcome further exchange and cooperation in the field of small hydropower. To conclude, I would like to express my sincere hope that the publishing of WSHPDR 2016 will help make international small hydropower development inclusive and sustainable and will contribute to creating a beautiful life for all of mankind.

As an update of the first edition of 2013, WSHPDR 2016 comprises 160 national reports and 20 regional reports, with 11 new countries added compared to the previous edition. More than 230 experts and scholars in the field of small hydropower from related governmental institutions, research institutes, universities and colleges, as well as hydropower companies in those countries and regions, contributed to drafting country and regional reports. Analysis of the status of small hydropower development in each country included the following five aspects: electricity sector overview, small hydropower sector overview and potential, renewable energy policy and barriers to

2

Foreword LI Yong, Director General, UNIDO To address environmental challenges, energy security and volatile fuel prices, and to pursue inclusive and sustainable industrial and economic development, leaders are strategizing ways to shift the economies from relying on traditional energy sources to renewable ones. UNIDO, as a specialized agency of the United Nations, is promoting inclusive and sustainable development and realization of industry-related Sustainable Development Goals (SDGs), particularly SDG 9, on building resilient infrastructure, promoting inclusive and sustainable industrialization and fostering innovation. UNIDO understands that access to low-cost and reliable energy based on local renewable resources for productive uses can bring economic, social and environmental dividends, such as increasing industrial competitiveness, creating jobs for all and raising incomes.

This is in line with the objectives of the World Small Hydropower Development Report, namely, to promote the increase of the share of this valuable source of energy in the energy mix, through informing policy on energy planning and guiding investors in entering renewable energy markets, through information and knowledge sharing. Towards this objective, UNIDO’s Department of Energy collaborated with the International Center on Small Hydro Power (ICSHP) in 2013 to develop a small hydropower knowledge platform www.smallhydroworld.org and produce the World Small Hydropower Development Report. This flagship initiative of UNIDO is the first compilation of valuable information on global small hydropower. It serves as a crucial guide for policymakers and investors.

In this regard, small hydropower is an excellent renewable energy solution to meet the needs of productive uses and to electrify rural areas. It is a mature technology, which can easily be designed, operated and maintained locally. It has the lowest electricity generation prices of all offgrid technologies, and the flexibility to be adapted to various geographical and infrastructural circumstances.

In 2016, UNIDO and ICSHP, along with partners, launched this updated version of the Report and Platform, continuing our mission to inform world leaders on the status and potential of small hydropower development, and encourage stakeholders in the sector to share and disseminate this knowledge.

Despite these benefits, the potential of small hydropower in developing countries remains untapped.

I would like to congratulate the experts and institutions that have contributed to this Report, making it rich in content and accurate in presentation.

It is therefore paramount for UNIDO to foster uptake of small hydropower through awareness building, information dissemination and experience sharing on the use of renewable energy, such as small hydropower, in industries and in small enterprises, in particular. This will boost productivity, industrialization and regional economic development.

3

Acknowledgements

M.R. Ibragimova, Janis Irbe, Agustín Irizarry-Rivera, Michela Izzo, Sherab Jamtsho, Frantisek Janicek, Sergio Armando Trelles Jasso, Rim Jemli, Edy Jiménez-Toribio, Kurt Johnson, Morsha Johnson-Francis, Rán Jónsdóttir, Aaron Yancho Kaah, Furkat Kadyrov, Ramiz Kalbiyev, J.K. Kaldellis, Papias Karanganwa, Bryan Karney, Raul Pablo Karpowicz, Egidijus Kasiulis, Fredrick Kazungu, Nguy Thi Khanh, Harald Kling, Wim Klunne, John Korinihona, Igor Kovacevic, Juraj Kubica, Arun Kumar, Gianluca Lazzaro, Disashi Nyama Lemba, Zenkevich Zhanna Leonidovna, Jean-Marc Lévy, Patricia Lewin, Stelios Liaros, Roger Limoko, Galina Livingstone, Casper Lundbak, Esmenio Isabel Joao Macassa, Ewa Malicka, Ghulam Mohd Malikyar, Sharon Mandair, Ariel Marcheniagi, Miroslav Marence, Cayetano Espejo Marin, Ramon Garcia Marin, Rupeni Mario, Max Marten, Harrison Masiga, Petr Mastny, Anare Matakiviti, Leopoldo Mba, Nebiyu Bogale Mereke, Emmanuel Michael-Biririza, Lasten Mika, Jan Moravek, Conrado Moreno, Carine Mukashyaka, Tin Myint, Wimal Nadeera, N’guessan Pacôme N’Cho, Leonel Wagner Neto, Niels Nielsen, Robert Nyamvumba, Abdeen Mustafa Omer, Emna Omri, Efrain O’neil-Carrillo, Karim Osseiran, Daniel Paco, Milena Panic, Domingos Mosquito Patricio, Cláudio Moisés Paulo, Elsia Paz, Henrik Personn, Ana Milanovic Pešic, Mark Pickup, Vlad Florin Pîraianu, Jiri Pitron, Martina Prechtl-Grundnig, Nuwan Premadasa, Mairawesi Pulayasi, Peeter Raesaar, Faisal Rahadian, Mizanur Rahaman, Jorge Reyes, Lucas Rissatto, António Carmona Rodrigues, José Pablo Rojas, Irina Rotari, Vladimir Russo, Kamila Sakipova, Jorge Reyes Salazar, Alberto Sanchez, Sašo Šantl, Vahan Sargsyan, Ryspek Satylkanov, Martin Scarone, Ozturk Selvitop, Shamsuddin Shahid, Mahender Sharma, M. Hady Sherif, Manish Shrestha, Sangam Shrestha, Luciano José da Silva, Mundia Simainga, Christopher Simelum, Jérémie Sinzinkayo, Seming H. Skau, Paradis Someth, Eva Szabina Somossy, Marina Stariradeva, Janusz Steller, Phillip Stovold, Abdul-Ilah Younis Taha, Samiha Tahseen, Kati Takala, Ibrahim Ragab Mohamed Teaima, Stephan Theobold, Mikael Togeby, Petr Toman, Ernesto Torres, Bertrand Touaboy, Thierry Trouillet, Le Anh Tuan, Makhbal Tumenjargal, Eva Maate Tusiime, Philbert Tuyisenge, Jo Tyndall, Miranda Urbina, Marko Urošev, Peter Vail, Petro Vas’ko, Sandra Vatel, Carola Venegas, Akhomdeth Vongsay, David E. Weir, Harsha Wickramasinghe, Horace Williams, Mark Williams, Edmund D Wuseni, Kassius Klei Ximenes, Milena Yanuzova, Zhanna Zenkevich.

The World Small Hydropower Development Report 2016 was prepared under the overall guidance of Pradeep Monga, Director of the Department of Energy at the United Nations Industrial Development Organization (UNIDO), Cheng Xialei, Director General of the International Center on Small Hydro Power (ICSHP) and Liu Heng, VicePresident of Nanjing Hydraulic Research Institute. It is the result of two years of intense research efforts and close collaboration with the experts in the field of small hydropower. The Report was headed by Rana Pratap Singh, Industrial Development Officer at UNIDO. This lengthy and at times arduous endeavour was coordinated by Sidney Yeelan Yap at UNIDO; Wang Xianlai and Eva Kremere at ICSHP. The Report was backed by a talented and indispensable team of researchers at ICSHP including Nathan Stedman, Tom Rennell, Marcis Galauska, Oxana Lopatina and Gonzalo Lopez. The invaluable contributions and insightful comments received greatly enhanced the overall quality of the Report. These included authors and contributors: Fagan Abdurahmanov, Tcharabalo Abiyou, Donald Adgidzi, Lia Aghekyan, Engku Ahmad, Dennis Akande, Sameer Sadoon Algburi, Mohammad Hassan Al Zoubi, Gabrial Anandarajah, Viktor Andonov, Darlene Arguelles, Fredrik Arnesen, John Kobbina Arthur, Engku Ahmad Azrulhisham, Attila Bagi, Johor Bahru, Betsy Bandy, Sendi Baptista, Kemal Baris, Stefano Basso, Alexis Baúles, Hannes Bauer, Madhu Prasad Bhetuwal, Mme Sow Aissatou Billy, Guillaume Binet, Alaeddin Bobat, Nebiyu Bogale, Edilbek Bogombaev, Carlos Bonifetti, Roger Limoko Bosomba, Paul Bryce, Thomas Buchsbaum, Alfredo Samaniego Burneo, Ejaz Hussain Butt, Rodolfo Caceres, Martin Camille Cange, Sonya Chaoui, Piseth Chea, Zivayi Chiguvare, Gift Chiwayula, Karim Choukri, Nouri Chtourou, Romao Grisi Cleber, Bill Clement, Fred Conning, Dione Constance, Jovan Cvijic, Manana Dadiani, Vassish Dassagne, Eric Davy, Denise Delvalle, Johanna D’Hernoncourt, Sinalou Diawara, Paulo Alexandre Diogo, Pirran Driver, Khalil Elahee, Sylla Elhadji, Hussein Elhag, Mohamedain E. Seif Elnasr, Lambert Engwanda, Cayetano Espejo, Daniela Espinoza, José Fábrega, Nimashi Fernando, Soukaina Fersi, Geraldo Lúcio Tiago Filho, Sione Foliaki, Fombong Matty Fru, Tokihiko Fujimoto, Camila Rocha Galhardo, Ramon Garcia, Rinayu Garini, Carlos González, Erickl Gonzalez, Toon Goormans, Johannes G.Grijsen, Cleber Romao Grisi, Leo Guerrero, Mathias Gustavsson, Zvonimir Guzovic, Armin Hadzialic, Mohammad Hajilari, Randrianarivelo Jean de Dieu Luc Harisson, Eoin Heaney, Liu Heng, Deung-Yong Heo, Marcello Hernández, Sven Homscheid, Arian Hoxha,

Other contributing experts were Liu Deyou, Hu Xiaobo and Lara Esser from ICSHP, Lin Ning and Li Zhiwu from the Hangzhou Regional Center (Asia-Pacific) for Small Hydro Power (HRC). Deepest gratitude is also due to Guillaume Binet, Johannes Geert Grijsen, Sergio Armando Trelles Jasso, Kurt Johnson, Furkat Kadyrov, Bryan

4

Karney, Wim Klunne, Gianluca Lazara, Galina Livingstone, Miroslav Marence, Niels Nielsen, Janusz Steller, Phillip Stovold, who thoroughly reviewed numerous drafts and significantly improved several sections of the Report.

Social Commission for Asia and the Pacific (UNESCAP), Liu Heng, Nanjing Hydraulic Research Institute, András Szöllösi-Nagy, Institute for Water Education (UNESCOIHE), Tian Zhongxing, INSHP, Kuniyashi Takeuchi, International Centre for Water Hazard and Risk Management (ICHARM), Jeffrey Skeer, International Renewable Energy Agency (IRENA) and Geraldo Tiago Filho, Centro Nacional de referencia em Pequenas Centrais Hidreletricas (CERPCH); by members of the UNIDO Publications Committee – Augusto Luis Alcorta Silva Santisteban, Adnan Seric, Jacek Cukrowski, Steffen Kaeser, Frank Hartwich, Alois Mhlanga, Patrick Nussbaumer, Thouraya Benmokrane and Michele Clara, as well as other UNIDO colleagues at the Department of Energy.

The Report further benefited from constructive comments by members of the WSHPDR Editorial Board, specifically Linda Church-Ciocci, National Hydropower Association (NHA) and Hydro Research Foundation, Solomone Fifita, Secretariat of the Pacific Community (SPC), Motoyuki Inoue National Institute of Science and Technology Policy (NISTEP), Wim Jonker Klunne, Energy and Environment Partnership (EEP), Arun Kumar, Alternate Hydro Energy Center, Pradeep Monga, UNIDO, Hongpeng Liu, United Nations Economic and

5


Executive Summary

today with some 1.2 billion people—about 17 per cent of the world’s population—still lacking access to electricity (Figure 1). Clean energy and access to electricity have been recognized by the United Nations as key to development. As such, energy access is the seventh Sustainable Development Goal (SDG). Yet clean energy exists with other SDGs, including alleviating poverty, education, improving environmental conditions and combating climate change.

The World Small Hydropower Development Report (WSHPDR) 2016 is the result of an enormous collaborative effort between the United Nations Industrial Development Organization (UNIDO), the International Center on Small Hydro Power (ICSHP) and over 230 local and regional small hydropower (SHP) experts, engineers, academics and government officials across the globe. Prior to the World Small Hydropower Development Report (WSHPDR) 2013, it was clear that a comprehensive reference publication for decision makers, stakeholders and potential investors was needed to promote SHP as a renewable and rural energy source for sustainable development more effectively and to overcome the existing barriers to development. The 2016 edition aims to not only provide an update but also to greatly expand on the 2013 edition by providing improvements on data accuracy with enhanced analysis and a more comprehensive overview of the policy landscapes compiled from a larger number of countries.

In both developing and developed countries, the need for clean and sustainable sources of energy is growing more acute in the face of climate change while geopolitical and economic uncertainty over traditional fossil-fuel markets highlights the importance of energy diversification and independence. On a global scale, hydropower is the most widely utilized form of renewable energy, with over 1.2 TW of installed capacity spanning six continents. However, inadequate design and planning of hydropower projects can have a negative effect on the environment. In order to ensure sustainable development and operation of hydropower,

Energy remains one of the most critical economic, environmental and development issues facing the world

FIGURE 1

Electrification rates by country (%)

100 90 80 70 60 50 40 30 20 10

Source: Statistics from the World Bank

6

Global share of renewable energy (%) Geothermal power 1%

Bioenergy 5%

When supported by environmental protection policies and concrete supervision from the regulatory authorities, SHP can be an important renewable energy technology, contributing to rural electrification, socially inclusive sustainable industrial development as well as reduction of greenhouse gas emissions and deforestation. Therefore, it should be considered in national plans globally for development of sustainable green energy.

Solar power 11%

Wind power 22%

Large hydropower 54%

Small hydropower 7%

Global overview The globally installed SHP capacity is estimated at 78 GW in 2016, an increase of approximately 4 per cent compared to data from WSHPDR 2013. The total estimated SHP potential has also increased since publishing WSHPDR 2013 to 217 GW, an increase of over 24 per cent. Overall, approximately 36 per cent of the total global SHP potential has been developed as of 2016 (Figure 2).

Source: World Bank FIGURE 4

Leading countries in SHP development (%)

FIGURE 2

Global installed SHP capacity (%)

33% 51%

36% 16%

China

Remaining top 5 countries

Rest of the world

Source: ICSHP Installed capacity

Remaining

While the USA has developed a majority of its potential, reaching 57 per cent of its developed potential in 2016, Brazil has much of its SHP potential undeveloped, reaching only 30 per cent in 2016. Nevertheless, since the publishing of WSHPDR 2013, Brazil has increased its installed capacity by 34 per cent (up to 30 MW). The USA,

Source: ICSHP

SHP represents approximately 1.9 per cent of the world’s total power capacity, 7 per cent of the total renewable energy capacity and 6.5 per cent (< 10 MW) of the total hydropower capacity (including pumped storage). As one of the world’s most important renewable energy sources, SHP is fifth in development, with large hydropower having the highest installed capacity to date, followed by wind and solar power (Figure 3).

FIGURE 5

SHP by region ( 201 kWh

0.220

Commercial 1 (less than 2,500 kWh) 0-50 kWh 51-200 kWh

0.165 Minimum charge is 0.205 US$3.00

> 201 kWh

0.220

FIGURE 4

SHP capacities < 10 MW and < 30 MW in Belize (MW)

Commercial 2 (above 2,500 kWh) 0-10,000 kWh 10 001-20,000 kWh

0.215 Service charge is 0.210 US$57.50

> 20 ,001 kWh

0.205

< 10 MW 10.3 11.4

< 30 MW

Industrial Demand of 18 kVA Demand of 11.25 kVA Street lights

10.3 7.3

Capacity

Social rate 0-60 kWh

51.3

Installed

Tariff rates by type Tariff type

21.7

Capacity

54.5

25.9

0.0 20.0 40.0 60.0 80.0 100.0

0.155 Service charge is 0.135 US$57.50

Installed capacity

Additional potential

Sources: MESTPU,5 POYRY10

0.235

The installed SHP capacity of up to 10 MW comes from two operational SHP plants: the Chalillo Hydroelectric

Source: BEL9

246

Dam and Plant and the Hydro Maya Limited Facility (Table 1). Combined, they account for approximately 19 per cent of total hydropower capacity and approximately 7 per cent of the country’s total installed capacity.

One of the strategic priorities of Horizon 2030 is the promotion of green energy and energy efficiency and conservation, including the creation of an institutional framework for producing a viable energy policy. In February 2012, the government endorsed the National Energy Policy and Planning Framework. The Belize National Sustainable Energy Strategy 2012-2033 aims to institutionalize a countrywide infrastructure to collect data and assess the potential for converting solar, wind and hydropower to electricity, in order to identify feasible sites for development. One of its goals (Goal 5) is to increase hydropower up to 70 MW by 2033. It suggests a revision of the technical assessments of hydropower resource capacity to identify new sources, to determine the potential and to develop expansion plans.

While the country’s hydropower potential is relatively low, there are still potential sites for further hydropower development without the need to inundate large areas of rainforest for storage reservoirs, as stated in a 2006 study of the country’s hydropower potential.10 Sites with a potential of less than 10 MW listed in the study include: }} The Macal River Project, which has a potential capacity of 8.4 MW and is easily accessible and in proximity to lines of the national power network; }} Tributaries to the Macal River which have the right conditions to install a SHP plant with a capacity of 2 MW; }} Site along the Privassion Rio, which has a potential capacity of 1 MW.

To move forward, the government has conducted several studies that were not public at the time of publishing of this report. These studies will analyse the electricity sector and the needed development in the coming years.

There are also a number of other potential sites across the country. However, no data exists to provide accurate assessments of the potential capacity.10

Barriers to small hydropower development

There are no defined financial mechanisms for SHP projects in Belize, but certain incentives do exist. For example, funds or credits for clean energy investments can be applied for with Beltraide or the Development Finance Corporation (DFC). However, neither is specifically focused on SHP.11,12 Calls have also been issued for Power Purchase Agreements (PPAs) and similar incentives, like the recent call by the PUC in November 2013 to submit proposals to generate electricity to be sold to the government.

As Belize has no legal framework for renewable energy and grid feeding, the main barrier is the unregulated market, stemming from political considerations and interests. Belize has no Standard Offer Contract (SOC) for renewable energy generation. Investment security is also not automatically given to investors, making the renewable energy market unclear and unregulated. Additionally, Belize has no standards in the SHP sector, resulting in the possibility of technical instability. The skilled workforce for SHP is also very limited in Belize and needs to be explored from other sources. Targeted policy, regulatory, and financial interventions can overcome the barriers that prevent greater development of SHP in Belize, as well as targeted programmes with a focus on SHP.

Renewable energy policy The principles of sustainable development are embodied in a national development plan called Horizon 2030.

247

Central America

2.2

Costa Rica

2.2.2

Jose Pablo Rojas, CEGESTI

Key facts Population

4,870,000 1

Area

51,100 km2

Climate

Most of Costa Rica has two seasons: the wet season from May to November (winter) and the dry season from December to April (summer). Although the country lies completely within the tropics, elevation plays a role in the variations of its climate. Temperature is also determined by proximity to the coasts. The area known as the tierra caliente (hot country) in the coastal and northern plains experiences daytime temperatures of 29°C to 32°C. The tierra templada (temperate country), including the central valleys and plains, has average daytime temperatures from 24°C to 27°C. The tierra fría (cold country) composes the land above 1,524 m and has daytime temperatures from 24°C to 27°C, but night-time temperatures of 10°C to 13°C.9

Topography

Mostly flat, with swampy coastal plains and low mountains in the south, the highest point is Cerro Chiripo (3,810 m). The country is divided longitudinally into two hydrographic areas by a system of mountains. These are the Caribbean slope, which is humid and rainy, without water deficit throughout the year and the shed, drier Pacific Ocean, with a marked decline in low water flow.3

Rain pattern

During the rainy season, the country receives more than 300 mm each month.3

General dissipation of rivers and other water sources

The territory is divided into 34 major basins, 17 basins for each side, with sizes between 207 km2 and 5,084 km2. The Caribbean side is wet and rainy, with higher volumes of runoff per unit area without water deficit throughout the year, and the North Pacific has relatively dry basins, with decreased flow in the dry season. The San Carlos and Chirripó Rivers, located near the border with Nicaragua, commonly flood during the wet season, turning the surrounding landscape into swampy marshlands. The largest storage capacity is Lake Arenal (1.9 billion m3 of useful capacity), followed by Cachí (36 million m3), Pirris (30 million m3) and Angostura (11 million m3).3


Electricity sector overview

The Costa Rican Electricity Institute (ICE), which was created in 1949 as per Decree Law No. 449, is a state institution with the legal mandate to provide the electrical power the nation requires for its development. As such, it provides the vast majority of electricity to the country at 74 per cent of generated totals. The electricity sector as a whole is made up of seven public utilities and 30 independent power producers (IPPs). The National Power and Light Company (Compañía Nacional de Fuerza y Luz S.A., or CNFL), which is a subsidiary of ICE, is the principal distributor for the sector.4

In 2014, electricity generation in Costa Rica was 10,202 GWh (Figure 1), dominated by non-thermal renewable sources. It is remarkable that approximately 92 per cent of electricity generated in the country comes from renewable sources, with only 8 per cent coming from thermal generation.8 FIGURE 1

Electricity generation by sources in Costa Rica (GWh) Hydropower Geothermal

1,411

Thermal Wind power Biomass

In 2012, Costa Rica had a total installed capacity of 2,682 MW (Figure 2). The ICE, through power stations it operates, contributed 76 per cent of the total, while IPPs contributed 13 per cent. The remaining 11 per cent came from plants owned by the distribution companies. It should be noted that in the 1970s and 1980s, hydropower was essentially the only source for electricity generation. After a severe drought in 1994, the government diversified generation and began utilizing geothermal, wind, thermal, and recently solar sources to provide stable electricity generation.8

7,254

805 503 100

Source: ICE4

248

FIGURE 2

TABLE 1

Installed electricity capacity by sources in Costa Rica (MW)

SHP installed capacity In Costa Rica

Hydropower

1,662

Thermal

536

Geothermal Wind power Biomass

Public company site

187 134 53

Capacity (MW)

Private company site

Capacity (MW)

Alberto Echandi

4.7

Embalse

2.0

Anonos

0.6

Tapezco

0.1

Avance

0.2

Poas II

1.1

10.5

La Lucha

0.3

Birris #2

2.4

La Rebeca

0.1

Birris #3

4.3

Poas I

1.6

Brasil

2.8

Montezuma

1.0

Cacao

0.7

Cano Grande

2.8

2

San Gabriel

0.5

Chocosuelas

8.1

Zuerkata

3.0

Electriona

5.8

Quebrada Azul

0.3

La Joya

0.3

El Angel S.A

3.7

Los Lotes

0.4

Matamoros

3.8

Nuestro Amo

7.5

Hidrovenecia

3.4

PTO.Escondido

0.2

La Esperanza

5.5

Rio Segundo

0.3

Rio Segundo II

0.5

Rio Segundo 2

0.5

—

—

Ventanas

10

—

—

Belen

Source: ICE4 Note: Data from 2012.

Costa Rica still utilizes thermal plants for electricity production. During rainy season the generation is minimal, but during the dry season and in times of drought, the thermal plants can keep production matching demand. The electrification rate in Costa Rica is considerable, with 99.4 per cent of households having access to electricity.8

Carrillos

Costa Rica participates in the Central American Electricity Market, a regional interconnection of six national markets in a consolidated regional market. Currently the interconnections operate on 230 kV lines. Once the installation of the SIEPAC (Electrical Integration System for Central American Countries) line is finished, member states will be able to have energy exchanges of up to 300 MW.5 The distribution and commercialization of Costa Rican electricity is guaranteed by eight public companies. However, the electric system is managed and is under the responsibility of the ICE. The electricity tariffs in Costa Rica are set by the regulatory authority for public services, ARESEP.6

Source: ARESEP6 Note: Corresponds to 2009 data.

increased, but the available data from the ICE continues to demonstrate the capacity of 91 MW (Table 2) from 2009. FIGURE 3

Electricity tariffs rose 142 per cent from 2005 to 2015 (US$0.07/kW to US$0.17/kW). At the lower levels, Costa Rica had among the cheapest electricity in the world. In December 2015, the government announced a reduction of 6.7 per cent of the ICE´s average distribution tariffs for 2016. The reduced rate will affect almost 800,000 consumers, including residential, industrial and preferential sectors.12

SHP capacities in Costa Rica (MW), 2013-2016

Potential capacity 2016 2013

Installed capacity

N/A N/A 91 91

Small hydropower sector and overview Sources: ICE,1 WSHPDR 201311 Note: The comparison is between data from WSHPDR 2013 and WSHPDR 2016.

In Costa Rica, there is no definition of small hydropower (SHP). However, plants with installed capacity up to 20 MW are considered to possess limited capacity. For the purposes of this report, the definition will remain as 10 MW or less. Traditionally, the ICE had a monopoly on hydropower production, but IPPs and cooperatives can now invest and operate SHP systems up to 20 MW (Table 1).

Costa Rica has massive theoretical hydropower potential, estimated at over 4,000 to 7,000 MW, yet the potential for SHP remains unidentified. While this number suggests the possibility to greatly increase the capacity, the technical and economically feasible potential is lower due to environmental and geographic restrictions. Roughly 1,700 MW of potential are in areas with protected species habitats and another 780 MW are in national parks. While

In 2009, the installed capacity was 91.25 MW, as reported in the World Small Hydropower Development Report (WSHPDR) 2013 (Figure 3). Since that time, the capacity has likely 249

Central America

2.2


proposed plans), to include interest in developing hydro and wind units of less than 20 MW.8

TABLE 2

Proposed RE installations in Costa Rica Year

Site

Type

Capacity (MW)

2016

Capulin

Hydro

49

2016

La Joya 2

Hydro

38

2016

Eolico C1 C1a

Wind

50

2016

Orosi

Wind

50

2017

Eolico C1 C1b

Wind

50

2017

Eolico C1 C2

Wind

20

2017

Hidro C1 C1

Hydro

4

2017

Hidro C1 C2

Hydro

50

2019

Pailas 2

Geot

140

Total

Legislation on small hydropower However, independent producers have a cap to production. Per Law No. 7200, the percentage that IPPs can hold of total generation is 15 per cent. With new government RE policies, though, the cap can be raised to include an additional 15 per cent if the production is wholly renewable. This is beneficial for IPPs wishing to develop several SHP sites. There are recommendations in the Plan for the Expansion of Electricity Generation 2014-2035 issued by the Costa Rican Electricity Institute, with goals and incentives to be implemented in order to cover Costa Rica’s electricity needs. The project has put a strong emphasis on RE, in particular one large geothermal plant and several hydropower plants (see Table 2 for a list of projects 2016-2019).

451

Source: ICE 8


the former is not prohibited per se, the government must seek concessions with local communities.6

The first barrier regards the difficulties for private investors to develop SHP plants, as well as other renewable energy sources. Currently, the legislation (Law No. 7200) only allows the private sector to generate up to 15 per cent of the installed capacity. Newer policies have increased generation to 30 per cent if it is fully renewable. However, the drawbacks could leave some IPPs without connections to the national grid when that limit is reached.5

In 1990, Act 7200 was adopted, allowing private-sector participation in electricity generation from renewable energy (RE) sources. This law had limited private participation (up to 15 per cent) in the national electric power system. After an amendment by Act 7508, the private-sector participation project limit was raised from 20 MW to up to 50 MW under the Build, Operate, and Transfer modality, which must be executed through tenders by ICE. Importantly, under this law, all projects must use RE.8

Barriers to SHP development in Costa Rica are common to barriers encountered by other RE sources. Private developers of electricity generation projects must go through a number of administrative procedures in order to fulfill several documentation requirements of prefeasibility and feasibility, in addition to obtaining resource use and building permits. They must also sign power purchasing agreements, making the ICE the only possible buyer. The institutional complexity involved in meeting the above-mentioned requirements creates great barriers to the private sector, particularly for small developers.

Renewable energy policy The Ministry of the Environment and Energy is the state entity for the country’s energy planning through the Energy Sector Management Directorate. One of the basic objectives is to diversify the energy mix through the use of renewable energies available at a commercial level. In the National Energy Plan from 2008-2021, one of the strategic objectives is to promote the use of renewable and indigenous (biomass) energy for electricity generation.10

All hydropower projects, small or large scale, are considered to have potentially high environmental impact and therefore require a full environmental impact study, which is the most complex of the currently existing requirements.7

The Government of Costa Rica is heavily invested in the renewable energy sector and has become a world leader in electricity generation through renewable sources. The government is dedicated to having the country become carbon neutral by 2021.

Another problem relates to the establishment of rates for feed-in tariffs. Costs, rules and tariffs were established in 2002, and were stipulated specifically for hydropower plants. Therefore, any technology or alternative energy source must adjust to this reality. Both private developers and the different government authorities are aware of this situation, but have still not reached a consensus on how best to fix it.

According to the Plan for the Expansion of Electricity Generation 2014-2035, distribution companies have proposed plans for developing another 327 MW of hydropower, 67 MW of wind, 10 MW of geothermal and 10 MW of solar, all to be completed by 2018. IPPs currently are eligible for 930 MW (out of 1,250 MW of

250

2.2.3

El Salvador Rodolfo Caceres, Consejo Nacional de Energia; Nathan Stedman, International Center on Small Hydro Power


6,107,706 1

Area

21,040.79 km2

Climate

El Salvador has a tropical climate with an annual average temperature of 24.9°C. The maximum temperature is 26.4°C in April and drops to a minimum of 23.8°C in December and January due to the northern winds. In the mountainous regions average temperatures range from 10°C to 16°C.2

Topography

Roughly 15 per cent of the country is located on the low-lying Pacific coastal region. The remainder of the country is divided into two geographic types, mountains and plateaus. The Sierra Madre mountain chain forms the northern border with Honduras. The western border contains Santa Ana, which is the highest peak (2,365 m). The southern mountains are mostly volcanic. The central plateaus comprise nearly 25 per cent of the territory, and is home to most of the major cities.3

Rain pattern

There are essentially two seasons: the dry season from November to April and the rainy season from June to September. The average annual precipitation is 1,800 mm. During the dry season, crops need to be irrigated as only 20 per cent of the annual rainfall occurs during that period.2


The country is divided into 10 hydrographic regions that drain into the Pacific Ocean and Lempa River. The biggest is the Lempa Basin, which composes half of the country’s area. There are four main storage reservoirs, the largest is Cerron Grande (135 km2) and the smallest is November 5 (16 km2). Five per cent of the territory is wetlands.2


America Electrical Interconnection System (Sistema de Interconexión Eléctrica de los Países de América Central, or SIEPAC). Imported oil is the main source of energy for the transportation sector, and for domestic consumption wood is used in rural areas and electricity within cities.

In El Salvador, Unidad de Transacciones (UT) acts as the Independent System Operator responsible for the management and control of the electric transmission grid. The electric distribution grid is privately owned by AES El Salvador. Energy policy is implemented by the National Energy Council (CNE) and regulation of the electricity sector is exercised by the Superintendent of Electricity and Telecommunications (SIGET), both under UT. The regulatory body is the Regional Commission of Electricity Interconnection (CRIE) based in Guatemala City. The Regional Operating Agency (EOR) based in the city of San Salvador is responsible for the dispatch and exchange of energy between countries.4

FIGURE 1

Electricity generation in El Salvador (MWh) Thermal

2,404

Hydropower

1,768

Geothermal Cogeneration Biomass

In 2014, total installed capacity was 1.583 GW, where thermal (diesel and fuel oil) took the largest share with 47 per cent (755 MW), then hydro with 30 per cent (487 MW), geothermal with 13 per cent (204 MW), cogeneration with 8 per cent (129 MW) and biomass with the remainder. In the same year, total generation was 5,876 GWh. Thermal was again highest with 40 per cent of generation, hydro constituted 30 per cent, geothermal 25 per cent, cogeneration around 4 per cent and biomass with the remainder (Figure 1).5 Recently, energy imports have played an important role through the Central

1,443 232 28

Source: CEPAL5 Although El Salvador has an installed capacity of 1,583 MW and maximum demand is 1,035 MW, demand and electricity generation varies with the season of the year. Hydropower constitutes the principal source of energy during the rainy season (50 per cent). By contrast, oil serves as the main generation source (50 per cent) during the dry season. The use of geothermal energy is relatively 251

Central America

2.2


steady throughout the seasons, at about 20-22 per cent of total generation. With an installed capacity of 50 MW, biomass supplies electricity through private sugar mills. However, production is limited to the harvest season from November to April of each year.5 The electrification rate is approximately 93 per cent, with 99 per cent access in urban areas and 76 per cent in provincial or rural areas (Figure 2).7,8

SIGET is responsible for the implementation of the General Electricity Law to promote free participation and competition in the electricity market in order to gain access and competitive electricity prices for all users. A recent achievement was the tendering and contracting of 94 MW of power and energy from non-conventional renewable energies, including solar PV, valid for 20 years.7

FIGURE 2

Rates remain the same for different types of generation. Every three months, the rates are set by SIGET for each distribution company. Within that period, contracts between such companies and industrial and household consumers may be established. There are neither preferential electricity tariffs nor regionally differentiated prices. Different rates are determined by marketing costs and customer service costs of the different distribution companies across the four regions of the country. In addition, long-term contracts exist between generators and distributors where a constant sales rate is fixed for a determined period. The Government of El Salvador, through the National Investment Fund for Telephone and Electricity (FINET) and financed by CEL, maintains an allowance for end users up to 200 kWh per month.7 The final consumer price of electricity consists of: }} The price of energy in the wholesale market; }} Marketing costs of the electricity distributor; }} Customer service costs.

Electrification rate in El Salvador

Rural 76 %

Total 93 %

Source: CNE,7AES8 Due to the seasonal fluctuations in production, El Salvador varies between an electricity importer and exporter through the SIEPAC network. Guatemala is traditionally the largest exporter of electricity; during the months of January to June, El Salvador is the second largest exporter with a monthly average of 34 GWh, which is roughly 25 per cent of the total exports for that period in SIEPAC. However, El Salvador is also the largest importer of electricity, with roughly 44 per cent of the annual SIEPAC total imports. This is especially true for the months of November and December, where the country contributes roughly 75 per cent of SIEPAC monthly totals.5

Small hydropower sector overview and potential In El Salvador, the total installed hydropower is 487.55 MW and the potential capacity is upwards of 2,258 (which could result in generating 7,705 GWh/year). The country’s definition of small hydropower (SHP) is less than 20 MW, although there are some differences with regulations for 5 MW and 3 MW. The total SHP installed capacity is 35.35 MW (15.55 MW of less than 10 MW capacity), and the potential capacity is 180.8. MW.10 WSHPDR 20139

In 1998, reforms through the General Electricity Law transformed the electricity sector from a state monopoly to a competitive market, thus separating the generation, transmission and distribution of electricity. The Lempa River Hydroelectric Executive Committee’s (CEL) thermal and geothermal high voltage plants were sold to private entities. The high-voltage (115 kV) transmission network is owned by an independent company under regulation (natural monopoly) and electricity distribution is concessional, forming four regions held by private investors. In addition, a regional network of electrical interconnection (230 kV) has been set up as the Regional Electricity Market. The law further allows the creation of smaller distribution companies that integrate under UT and are regulated by SIGET.6

FIGURE 3

SHP capacities in El Salvador (MW), 2013-2016

Potential 2016 2013

180 180

Capacity Installed Capacity

36 36

Sources: CNE,10 WSHPDR 20139 Note: The comparison is between data from WSHPDR 2013 and WSHPDR 2016.

CEL, as a state company, oversees generation of electricity operations through four hydropower plants with a combined 427 MW installed capacity located in the Lempa Basin. The company continues to conduct studies and develop energy projects namely in the area of nonconventional renewable energies such as photovoltaic energy, wind energy and biofuels.

Since the World Small Hydropower Development Report (WSHPDR) 2013, installed capacity and potential capacity has remained unchanged (Figure 3). This indicates that only 20 per cent of potential SHP has been developed.9 252

Legislation on small hydropower

As of a recent revision to the 2012 Master Plan for Renewable Energy, there have been feasibility studies conducted which identified 209 sites for SHP, most of which were identified in the western regions. After taking into account of environmental concerns and protected areas (SANP), 123 sites have been selected for the Master Plan implementation from 2012-2027. The expected total capacity by the end of phase III in 2027 will be 162.7 MW with a total generation of 671.3 GWh/year.10

Article 22 of the Environmental Law (Decree No. 579) stipulates that MARN will make classifications on activities and determine the documentation needed to submit proposals. For proposals with moderate to high environmental impact (Group B, Category 2), the investor must submit an Environment Impact Assessment (EIA) to MARN. In addition to the EIA, project holders may have to submit an Environmental Management Plan, to ensure environmental protection during construction of the project and after completion.7

TABLE 1

SHP in El Salvador (> 20 MW) Hydro plant

Location

Guajoyo

Santa Ana

19.80

Cucumacayán

Sonsonate

2.30

Río Sucio

Santa Ana

2.50

Milingo

San Salvador

0.80

Bululú

Sonsonate

0.70

Atehuasías

Ahuachapán

0.60

Cutumay-Camones

Santa Ana

0.40

Sonsonate

Sonsonate

0.20

San Luis I

Santa Ana

0.60

San Luis II

Santa Ana

0.74

Nahuizalco

Sonsonate

2.80

La Calera

Sonsonate

1.50

Papaloate

Sonsonate

2.00

La Chacra

Morazán

0.02

Carolina

Morazán

0.05

El Junquillo

Morazán

0.01

Miracapa

Morazán

0.03

The Environmental Law (Articles 78-81 and 85-95), also stipulates protected natural areas. This law was implemented to protect ecosystems and biological diversity and gives the authority to MARN to declare protected areas. As of 2012, there were 69 protected areas, some of which were located in the sites identified for SHP development.7

Installed capacity (MW)

Land Use Decree 855 governs the appropriation and use of land in metropolitan San Salvador. However, local municipal governments refer to the legislation when deciding on land use in the regional areas. Additional permits may be required per this decree. In total, it was estimated to take between 440 and 470 days to receive approval of an EIA from MARN, which would include time needed obtaining other permits.7 It should be noted that the procedure is the same for all types of projects concerning construction, there is no variation for different RE technologies. Barriers to small hydropower development While the country moves forward with the Master Plan for RE, including increasing the role of hydropower in the energy mix, there are still political, institutional and implementation barriers that impede the development of SHP, particularly in the hands of private project holders. }} Lack of basic framework for the development of RE; }} Lack of formalized incentives to promote RE; }} Need to implement technology-specific permits from MARN; }} Lack of MARN experts on RE; }} Expensive environmental studies; }} Inadequate land zoning prevents proper testing; }} Community opposition to projects; the 66 MW El Chaparral and the 261 MW Cimarrón hydro projects have faced considerable opposition, which has hindered development.11

Source: CNE10

Renewable energy policy The Ministry of the Environment and Natural Resources (MARN) is the responsible institution in the Central Government for socio-environmental aspects, and as such is the largest factor in renewable energy (RE) policy making. In addition to MARN, the Attorney General, National Registry Center, the CNE, SIGET and municipal governments and courts all play a role in the RE policy development and implementation. To date, the most significant policy is the 2012 Master Plan for Renewable Energy.7

253

Central America

2.2

2.2.4

Guatemala Marcis Galauska, International Center on Small Hydro Power


14,918,999 1

Area

108,889 km2 1

Climate

Guatemala can be divided into three climactic zones. Daytime temperatures in the tropical lowlands can reach as high as 40°C and temperatures at night rarely drop below 20°C. The temperate zone extends from approximately 1,000-2,000 m above sea level with daytime temperatures rarely exceeding 30°C. The cool zone daytime temperatures are only slightly lower than in the temperate zone, but the nights are fairly cold and temperatures drop below freezing occasionally.2

Topography

A tropical plain averaging 48 km in width parallels the Pacific Ocean. A piedmont region rises to altitudes of 90-1,370 m. Above this region lies nearly two-thirds of the country, in an area stretching north-west and south-west and containing volcanic mountains, the highest of which is Tajumulco (4,211 m). To the north of the volcanic belt lies the continental divide and, still farther north, the Atlantic lowlands.3

Rain pattern

There are dry and wet seasons: the dry season from May to October and the wet season from November to April. The average precipitation varies from approximately 100-500 mm per month.4


The country can be divided into three major areas. The Pacific Rim has 18 river basins. The coast on the Caribbean Sea has 10 basins and includes the most important river, the Motagua. The Gulf of Mexico region also has 10 basins, which are home to the most abundant rivers in the country.5


in increasing electricity access, the Inter-American Development Bank has approved a loan of US$55 million to improve and expand coverage of the national electricity service. The programme is expected to raise the electrification coverage to 92.9 per cent by 2019, through investments in the grid and the installation of isolated systems using renewable energy sources, which will make it possible to connect an additional 6.6 per cent of the population.7 Guatemala is connected via the Central American Electrical Integration System (SIEPAC) to Honduras and El Salvador. Several communities are located in areas where access to electricity might be delayed due to relief barriers in government assistance programmes, low capacity to pay for the services and lack of transmission infrastructure.8

In 2013, electricity generation was 9,920 GWh, with 313 GWh imported and 669 GWh exported, making an overall domestic electricity supply of 9,564 GWh. Of the domestic production, 4,654 GWh was generated from hydro, 1,797 GWh from biofuels, 1,691 GWh from oil, 1,566 GWh from coal and 212 from geothermal sources (Figure 1).6 World Small Hydropower Development Report 2016

FIGURE 1

Electricity generation in Guatemala (GWh) Hydropower

4,654

Biofuels

1,797

Oil

Geothermal

The power market in Guatemala is unbundled, with state and private players acting in generation, transmission, energy trading and distribution segments. The Ministry of Energy and Mining oversees planning for the electricity sector, while the National Electricity Commission (Comisión Nacional de Energía Eléctrica) is in charge of regulation. Additionally, the Wholesale Market Operator (Administrador del Mercado Mayorista), a private organization, organizes the system’s dispatch based on marginal cost of generation.8

1,691

Coal

1,566 212

Source: IEA6

Installed capacity was 3,170 MW. The total electrification rate is approximately 86.3 per cent, while the rate in rural areas is approximately 82 per cent. To assist

254


The National Indicative Plan 2008-2022 has set a number of projects to increase power generation, including both non-renewable and renewable sources. Amongst the non-renewable sources, investment is expected in nineteen different power generation plants that include gas and vapour turbines. The average electricity rate in Guatemala is US$0.26/kWh.9,10

For SHP project licensing, the operator must obtain temporary water rights from the Ministry of Energy and Mines (MEM) after completing prefeasibility studies. Following the approval, feasibility studies, including hydrology and geology assessments as well as project design and cost estimates, must be carried out and submitted. An environmental impact assessment is also required before the MEM will approve a grid connection study. Final authorization for project implementation is granted by the National Electrical Energy Commission. For projects with capacities up to 5 MW, the water rights staking process consists of registering the project at the Ministry of Energy and Mines. For projects with capacity higher than 5 MW, a 50-year water rights claim must be submitted to the Ministry of Energy and Mines. A safety study is required before construction may begin for all projects with a dam, which must be approved by the National Electrical Energy Commission.14

Small hydropower sector overview and potential The definition of small hydropower (SHP) in Guatemala is up to 10 MW. The installed capacity of SHP is 84 MW,11 while the additional potential capacity derived from the Ministry of Energy and Mines Plan for Generation and Transmission (2016-2030) is 93.36 MW.17 Between the World Small Hydropower Development Report (WSHPDR) 2013 and WSHPDR 2016, both installed capacity and potential capacity increased by significant rates (Figure 2).

Renewable energy policy

FIGURE 2

SHP capacities 2013-2016 in Guatemala (MW)

Potential 2016 2013

177.4

Capacity

62.7

Installed Capacity

The Energy Policy 2013-2027 is the general energy development plan for Guatemala. It includes plans for the promotion of renewable resources in electricity generation. One of the goals is to diversify electricity generation by prioritising renewable resources; the long term goal is to generate 80 per cent of electricity from renewable resources. The planned actions are: }} To update studies about renewable resource potential of the country; }} To promote hydropower, geothermal, solar, wind, biomass energy as well as other new and renewable energy sources; }} To promote technological innovation and technological development of human capital in the energy sector.

84.0 35.6

Sources: IRENA,11 Ministry of Energy and Mines,17 WSHPDR 201314 Note: The comparison is between data from WSHPDR 2013 and WHSPDR 2016.

According to the International Renewable Energy Agency (IRENA), installed capacity of SHP in 2014 was 84 MW.11 Data from ministry records indicate there are approximately 82 hydro plant projects under 5 MW.12

The other objectives are to promote investment in production of 500 MW of renewable energy, as well as to create a Master Plan for renewable energy development.15

The estimated technically feasible hydro potential is 5,000 to 10,800 MW. While data on countrywide potential is not available, the Plan for Generation and Transmission 2016-2030 has a roadmap for developing hydropower over the period of 2016 to 2030; the potential derived from the plans indicates an overall hydropower potential and planned capacity of 3,550 MW, of which 93.36 MW are SHP, indicating a SHP potential of at least that amount.

Estimates of geothermal power potential in Guatemala vary from 400-4,000 MW, biomass potential can be estimated at approximately 500 MW, another 5 MW can be generated by waste products. PV can be developed at a rate of 20 MW per year between 2019 and 2022.16 Barriers to small hydropower development SHP development in Guatemala is strongly hindered by social-institutional barriers, comprising land rights issues between local communities and private developers in natural resource management. Inadequate benefit sharing mechanisms coupled with limited conflict resolution mechanisms have created a significant barrier for SHP development.18,19

The Central American Bank for Economic Integration has granted a US$669,000 partial credit guarantee to Financiera de Occidente S.A. to hedge financing for development of SHP generation in Guatemala. The investment anticipates estimated annual generation of 2,751.3 MWh.13

255

Central America

2.2


In addition, Guatemala currently portrays the second lowest Human Development Index in Central and Southern America. The need for rural electrification is thus clear. However, rural electrification is stalled due to ethnic disparities and poverty, which in turn provide a lack of incentive for private investors who are unable

to justify high-energy investments within communities with low energy demand and income, thus creating a financial and market barrier to SHP development. SHP development also faces investment barriers, as domestic financing is difficult to obtain due to Guatemala’s high interest rates and short loan terms.18,20

256

2.2

Honduras

Central America

2.2.5

Gonzalo Marzal Lopez, International Center on Small Hydro Power


8,762,000

Area

112,491 km2

Climate

The climate is sub-tropical in the lowlands and temperate in the mountain areas. The warmest month is May, with an average temperature of 25°C, while the coolest month is January, at 22°C.1

Topography

The terrain is mostly mountainous in the interior with narrow coastal plains. The highest point is Cerro Las Minas, at 2,870 m. About 80 per cent of the territory is 600-2,850 m above sea level, and 15 per cent is between 150 and 600 m above sea level. About 20 per cent consists of low coastal valleys of the Caribbean Sea and the dry plains of the Pacific coast.1

Rain pattern

The average annual rainfall is 1,470 mm. The rainy season is from May to November, with regional variations. Hurricanes and floods are common along the Caribbean coast.2


Honduras is a water-rich country. The most important river in Honduras is the Ulúa, which flows 400 km to the Caribbean through the economically important Valle de Sula. Numerous other rivers drain through the interior highlands and empty north into the Caribbean. These rivers are important, not as transportation routes, but due to the broad fertile valleys they produce. Rivers also define about half of Honduras’ international borders. The Río Goascorán, flowing to the Golfo de Fonseca, and the Río Lempa define part of the border between El Salvador and Honduras. The Río Coco marks about half of the border between Nicaragua and Honduras.2


FIGURE 2 Electricity generation in Honduras in 2014 by sources (GWh)

In 2014, the installed energy capacity in Honduras was 1,850 MW, which consisted of oil (899.1 MW), hydropower (623.45 MW), wind (151.7 MW), biomass (153.55 MW) and coal (20.35 MW). The total generation of electricity in 2014 was 8,141.6 GWh. The generation by sources was as follows: diesel and oil generated 4,713 GW, hydropower generated 2,597 GWh, wind power generated 398 GWh, biomass generated 317 MW and coal generated 113 MW of electricity.2

Diesel and oil Hydropower

623.5 151.7

Biomass

153.6

Coal

Biomass

317.0 113.0

under which there is the National Commission for Energy (CNE) the regulatory authority for the electric energy sub-sector. The national electric power company, the National Company of Electric Energy (ENEE), is owned by the Government and it is in charge of the generation, transmission and distribution of electric energy. It comes under SERNA authority, but is regulated by CNE.12

899.1

Wind power

398.0

Source: AHPER2

Electricity installed capacity in Honduras in 2014 by sources (MW)

Hydropower

2597.0

Wind power

Coal

FIGURE 1

Oil

4713.0

The Ley General de la Industria Electrica (General Law of the Electric Industry) was issued on 20 January 2014. This law allows for the liberalization of the electricity market in Honduras. It allows for the export and import of energy, creating new business opportunities. Moreover, it allows direct sales of electricity to qualified consumers. The Regulatory Commission of Electric Energy was appointed in June of 2015.3

20.4

Source: AHPER2

The highest authority in the country is the Energy Cabinet. Its main task is to formulate energy policies. SERNA is the government institution in charge of the energy sector, 257


As of the 2012 data provided by the World Bank, the total electrification rate in Honduras was 82.2 per cent.9

intends to reverse the structure of the electricity sector by 2022 to a ratio of 60 per cent renewable and 40 per cent fossil fuel, thus complying with the provisions of the Country Vision and National Plan Law constituted into State Policy by Decree No. 286-2009.6 The government recognizes the potential of renewable energy technologies to improve industrial, commercial, and residential access to a reliable and affordable grid-connected power; and it is eager to develop these opportunities to enhance the sustainability of energy services in rural areas. Currently, the government’s priorities are to scale-up the access to electricity services in rural areas, and to promote rural access to clean energy cooking solutions.

Small hydropower sector overview and potential The total small hydropower (SHP) installed capacity in Honduras is 74.95 MW.12 The total SHP potential is approximately 385 MW, with an estimated potential generation of 470.2 GWh/year.4 There are 21 SHP plants in operation, with a total capacity of 74.95 MW. Moreover, there are 30.13 MW plants of SHP under construction. Currently, there are seven operational SHP plants including the following: Mangungo I (1.2 MW), Mangungo II (1.3 MW), Matarras I (1 MW), Matarras II (2.3 MW), Masca I (1.7 MW), Masca II (1 MW), and Rudiosa I (4 MW).12

The Honduras Scaling-Up Renewable Energy Program in Low-Income Countries (SREP) is giving US$30 million in grants and near-zero interest for a diverse programme of investment plans aimed at creating a more conducive environment for the renewable energy sector. Specific activities financed under the SREP include: a gridconnected renewable energy programme; a rural electrification strategy to accelerate the electricity access in remote areas; promoting access to improved and appropriate cooking technologies; and a policy along with a regulatory reform initiative intended to improve the conditions for development of the country’s renewable energy sector.7

The total hydropower installed capacity is 623.5 MW and the total hydropower potential is 1,284.2 MW. The Industrial and Commercial Bank of China granted US$299.7 million to the Government of Honduras in order to build the Patuca III project. FIGURE 3

SHP capacities 2013-2016 in Honduras (MW) Potential 2016 2013

385.00 385.00

Capacity

Legislation on small hydropower Installed Capacity

74.95 54.10

Following the energy crisis of 1994, the Government of Honduras negotiated with the European Commission (EC) in order to promote electricity generation from renewable sources and to encourage energy conservation. In January 1996, a financing agreement was established between the EC and the national electricity utility ENEE. After an initial two-year project, the EC donated EUR 250,000 to create a revolving fund called Fondo de Preinversión Hidroeléctrica (Hydroelectric Pre-investment Fund) that grants loans to the private sector. Since 1999, this ENEE Pre-Investment Fund has helped finance feasibility studies for SHP plants of installed capacity of up to 5 MW.6

Sources: WSHPDR 2013,11 CIF,4 IJHD12 Note: The comparison is between data from WSHPDR 2013 and WSHPDR 2016.

Renewable energy policy The 1998 Legal Framework and Reforms of the Energy Sector Law and its Incentives Law for Renewable Energy Generation have provided incentives for the development of renewable energy. Coupled with Decrees No. 85-89 and No. 267-98, they promote the implementation of renewable energy plants via mechanisms such as tax breaks or tariffs equivalent to short-term marginal costs experienced by the system.4 In 2007, the Honduran Government issued Decree No. 70-2007 (the Law to Promote Electricity Generation by Renewable Resources), implementing a preferential tax policy and a preferential sales policy for natural and juridical persons who develop and operate renewable energy projects according to the Act 81 of the Environment General Law.5 It grants additional benefits such as tax exemptions in the forms of import duty and income tax, and improvements in Power Purchase Agreements signed with ENEE to operators who generate electricity from renewable resources.

Barriers to small hydropower development The equity capacity by private investors in Honduras is concentrated in the larger, fossil-fuel-fired energy projects. It is not common for domestic commercial banks to provide equity to renewable energy projects. Market research indicates that given sound fundamentals (technical viability of project, good contracts, positive and adequate technical studies, competent sponsors) and a resulting reasonably low risk expectation, there are abundant international equity investors and sovereign investors that would be interested in providing equity to renewable energy projects in Honduras.2

With all these initiatives, the Government of Honduras

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2.2

Mexico

Central America

2.2.6

Sergio Armando Trelles Jasso, Mexican Institute of Water Technology


121,005,8151

Area

1,964,375 km2, including 5,127 km2 of islands.2

Climate

There is a great diversity of climate in the country due to its extension and relief. It is dry in most of the centre and north (28.3 per cent of the country), very dry in the north-west (20.8 per cent), warm and humid in the south (4.7 per cent), warm and sub-humid along the coasts (23 per cent), temperate and humid in the mountains of the south (2.7 per cent), and temperate and sub-humid in the mountains near the coasts (20.5 per cent).3

Topography

The main topographic features evolve from the activity of four tectonic plates. The Peninsula of Baja California is a 1,200 km-long mountainous chain. The Western Sierra Madre is a mountainous chain parallel to the Pacific coast with a length of some 1,400 km, ranging in altitude from 2,000 to 3,000 m. The Eastern Sierra Madre runs parallel but is separated by vast plains from the Gulf of Mexico over some 600 km, ranging in altitude from 1,200 to 3,000 m. The Sonora and Chihuahua Deserts are in the north-west near the border with the USA. The Central High Plateau ranges from 500 to 2,600 m. The Neovolcanic Axis runs from the west coast to the east coast, south of Mexico City, with a peak altitude of 5,747 m. The Southern Sierra Madre extends over 1,200 km and is very close to the south-western coast, with a peak altitude of 3,850 m. The Sierra Madre of Oaxaca in the south-east is about 300 km long, with peaks of about 3,000 m. The Peninsula of Yucatan in the south-east is a relatively flat karst formation with almost no streams or rivers.4,5

Rain pattern

From 1971 to 2000, the average precipitation for the country was 760 mm per year. The spatial distribution varies widely from 100 mm in the north-west to 2,350 mm in the southeast. Every year, between July and October, there are tropical storms and hurricanes that reach both littorals. From 1970 to 2012 there were 200 such events, most of them on the Pacific coast, but they were the strongest on the Atlantic coast. The rainy season from May to October accumulates 83 per cent of the annual rainfall.6


The country is divided in 37 hydrologic regions, which are further divided into 158 river basins and 976 sub-basins. The total mean runoff is estimated at 379,000 hm3 per year. The five hydrologic regions with the largest runoff are in the south-east: Grijalva-Usumacinta (shared with Guatemala), Pánuco, Papaloapan, Costa Chica de Guerrero and Coatzacoalcos. The five hydrologic regions with the largest extension but with lesser pluviosity than the previous group are: Bravo (shared with the USA), Sonora Sur, Lerma-Santiago, Balsas and Sinaloa.4


The total electricity generation in 2014 was 258,277 GWh of electricity, distributed by sources as in Figure 2.8

The total effective capacity in June 2015 was 55,086 MW of electricity, distributed by sources as in Figure 1.7

The overall availability of base generation units was

FIGURE 1

FIGURE 2

Installed electricity capacity in Mexico (MW)

Electricity generation in Mexico (GWh)

Thermal Hydropower Coal 5,378 Nuclear 1,510 Geothermal 847 Wind 699 Solar 6

34,352

Thermal Hydropower 38,145 Coal 17,466 Nuclear 9,677 Geothermal 6,000 Wind 2,077 Solar 13

12,294

Source: SENER8

Source: Secretariat of Energy (SENER)7 259

184,899


}} Regulatory Commission of Energy (CRE); }} National Centre of Energy Control (CENACE); }} Secretariat of Environment and Natural Resources (SEMARNAT); }} National Water Commission (Conagua); }} National Commission for the Efficient Use of Energy (CONUEE).

85.5 per cent in 2014. There was a margin of operating reserve of 17.0 per cent for the same year.9 The overall energy mix in 2014 was 82.1 per cent from fossil fuels, including thermal, coal and nuclear. The renewable energy (RE) sources, including solar, wind, geothermal and hydropower amounted to 17.9 per cent of the total. The national electrification rate in 2014 was 98.4 per cent; ranging from 99.6 per cent in the states of Aguascalientes and Coahuila, to 95.6 per cent in Oaxaca.10 There are rural communities that remain without electric service, mainly due to their dispersion in mountainous areas, that could be served by RE and micro hydropower in particular.

As a consequence of the Energy Reform: }} The CFE and the National Oil and Gas Company (PEMEX) are now State Productive Enterprises that are required to compete with private companies. }} The CFE will be restructured and several affiliated and subsidiary entities will be separated from the core institution in 2016. }} The CFE and the PEMEX are allowed to form publicprivate associations. }} Private companies can generate and sell energy, capacity and associated products; excepting nuclear generation and supply to domestic users. }} There will be a new Wholesale Electricity Market (MEM) supervised by CENACE in January 2016. }} There will be a spot market with short-term transactions. }} There will be electricity auctions with long-term contracts. }} Qualified users of energy with a starting threshold of 2 MW in 2016 will be able to buy from the spot market, from energy vendors or directly from the generators. }} A new type of actor, the energy vendor companies, will be able to intermediate. }} Clean energy certificates will be issued and traded starting in 2018. }} There will be a minimum percentage of RE for generators to participate in MEM transactions. }} Private companies will be allowed to participate in the expansion and operation of the transmission and distribution networks. }} The price scheme for the electric transmission service will be changed to reduce subsidies.

In December 1992, the then existing Law of the Public Service of Electric Energy (LSPEE) was amended to allow private participation in generation of electricity for self-supply, cogeneration, external producers, small producers, import and export. The use of transmission networks was also permitted with a simplified low price scheme. Private energy generators were not allowed by law to sell their production to the public, but exclusively to use it for self-supply, to sell to the Federal Commission of Electricity (CFE) or to export. The private generators were allowed to form a project specific enterprise including a pool of industrial, commercial and municipal end-users. These new entities were considered to fulfil the condition of self-supply. There are 28 power plants belonging to the external producers’ category that entered in operation in 2000 or after, with 12,851 MW. These include 23 combined cycle plants in different states and five wind power plants in Oaxaca. These plants generated 33.19 per cent of the total electricity in 2014, mostly from combined cycle.11 In 2013, a large process of radical reforms of the legal and institutional framework within energy sector started in Mexico. The reforms mainly focused on the oil and gas industry, but also included the electricity sector. On December 20, 2013, Articles 25, 27 and 28 of the Constitution were amended. Previously, only the nation had the right to generate, transmit, transform, distribute and supply electric energy for public service. The change enabled the State to control the planning and authority of the national electric system, as well as the public service of transmission and distribution of electricity. However, private companies are now allowed to participate in the remaining activities of the electric industry. Following the constitutional reform, 12 national laws were amended and nine additional laws were established. The changes entered into force on 11 August 2014.12 The corresponding bylaws are being adjusted or promoted.

The National Electric System is organized in nine regions. Seven of them form the National Interconnected System (SIN), which covers most of the territory with dense electric transmission and distribution networks. The Peninsula of Baja California has two regional networks. There are capacity restrictions in some nodes of the SIN that impose limitations or delays to the addition of new plants. Since there is a margin of operating reserve, the shortage of electricity on a regional or seasonal scale normally does not occur. However, some outages of electric supply of short duration and limited extension may occur. The average interruption time per user in 2014 was 36.7 minutes.13

The roles of the main public institutions of the electricity sector were adjusted accordingly, including: }} Secretariat of Energy (SENER); }} Federal Commission of Electricity (CFE);

260

A transmission line of 103 km at 400 kV linking Mexico and Guatemala started operation on 22 April 2010. It had an initial capacity of 200 MW towards Guatemala and 70 MW in the opposite direction.14 This strategic project allows energy transfers to the SIEPAC countries to serve the Regional Electric Market of Central America. Mexico is connected to Belize by a transmission line with capacity of 65 MW. To the north, Mexico has 11 interconnections with the States of Texas and California in the USA, with capacities ranging from 36 to 800 MW.

}} Reduction of electricity tariffs. The tariffs for industrial, commercial and domestic users started to decline by the end of 2014 as a result of the decreased use of costly fuel oil, the increased use of natural gas,the descent in international oil prices and the increment of hydropower generation. }} Implementation of the Energy Reform. The legal procedure to become a State Productive Enterprise was completed and CENACE was separated from the CFE on 28 August 2014.

The total gross demand of energy in 2014 was estimated in 284,382 GWh. This included sales by the CFE, remote self-supply, exports, energy savings, reduction of energy losses, and the CFE’s internal consumption. The expected annual rate of growth of demand of capacity in 20132028 is 4 per cent. This means that some 44,000 MW of additional capacity will be needed in the next 15 years, 80 per cent more than the present. The expected annual rate of growth of demand of energy from 2013-2028 is 3.8 per cent. It is foreseen that there will be an additional annual demand for energy of some 213,300 GWh in 15 years, which is 75 per cent more than the present.15

The CFE has an electricity tariffs structure that considers: level of tension, category of use, region, season, required and used demand, required continuity, type of energy (base, intermediate and peak), day of the week, level of consumption and hour of consumption. This gives rise to more than 40 tariffs. The electricity tariffs are charged in Mexican Pesos and are indexed monthly. The following chart shows tariffs of five user categories and the global average from in 2015. The global tariff in August 2015 was US$82.0/MWh.17 FIGURE 4

Electricity tariffs in 2015 (US$/MWh)

The total energy sales of CFE in 2014 were 208,015 GWh, distributed by user category as follows.16

Commercial

FIGURE 3

Industrial

Energy sales by user category 5% 4%

Medium industrial

7%

Domestic 38 %

21 %

168.2

Municipal

Large industrial

152.2 76.7

Domestic

72.0

Global

82.0

Agriculture

32.4

Source: SENER17

Commercial

The exchange rate considered in the previous charts was MXN16.32/USD on 6 August 2015. In general, the highest prices were in Baja California and Baja California Sur regions. The lowest prices are those of the north, north-east and north-west regions.

Agriculture 26 %

Services

Source: SENER16

The monthly distribution of aggregated energy sales in 2014 had its peak of 19,463 GWh in August and its valley of 15,293 GWh in February. The total exports of energy in 2014 were 2,653 GWh, with 72 per cent to the USA and the rest to Guatemala and Belize. The total imports of energy in 2014 were 2,124 GWh, with 99.8 per cent from the USA and the rest from Guatemala.

The tariffs of the CFE have been used as a reference in the negotiation of PPA within the self-supply scheme. Until now, this procedure has been attractive for private investors. However, there has been a decline in the tariffs since September 2014 of 15 per cent. Small hydropower sector overview and potential

Energy prices in the neighbouring countries are higher than they are in Mexico, mainly in Central America, where there are countries that suffer shortages.

The definition of small hydropower (SHP) in Mexico is up to 30 MW of electricity. The installed capacity of SHP was 470.2 MW in May 2015. Between the World Small Hydropower Development Report (WSHPDR) 2013 and WSHPDR 2016, installed capacity has increased by approximately 4 per cent (Figure 5).

The strategic vision of CFE incorporates the following elements: }} Reduction of generation costs, mainly by decreasing the proportion of fuel oil plants in favour of natural gas and RE plants. }} Reduction of energy losses. The total losses in 2014 were estimated in 14 per cent, including physical (6 per cent) and commercial (8 per cent) losses.

A hydroelectric generation facility is considered eligible for incentives aimed at RE projects when its capacity is lower than 30 MW, or when it has a Power Density of 10 W/m2, which is the ratio of installed capacity to reservoir 261

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2.2


be studied, it is logical to assume with good confidence that once a systematic and exhaustive assessment of SHP potential is carried out, thousands of feasible sites will appear instead of hundreds. The total capacity will also be counted in the order of tens of thousands MW.

FIGURE 5

SHP capacities (MW) in Mexico, 2013-2016 Potential 2016 2013

capacity Installed capacity

N/A N/A

In terms of installed capacity, in May 2015, hydropower amounted to 89.5 per cent of the total amount of RE. In terms of annual generation, in 2014 it was 82.5 per cent of the total amount of RE.7,8 The total capacity of 31 SHP plants in operation belonging to CFE is 284.7 MW. Their mean annual generation is 1,084 GWh. The average plant factor is 46.3 per cent. The total capacity of 17 SHP plants in operation belonging to private owners is 185.5 MW. Their mean annual generation is 748 GWh. The average plant factor is 37.6 per cent. CRE has issued 79 hydropower generation permits since 1992, when the LSPEE was amended.23 The combined capacity is 1,411.3 MW, ranging from 0.4 MW to 165 MW. The estimated annual generation is 5,815 GWh, with an average plant factor of 57.5 per cent. The number of hydropower plants with permits and the total capacity by status are as follows:

470.2 453

Sources: WSHPDR 2013,26 SENER17 Note: The comparison is between data from WSHPDR 2013 and WSHPDR 2016.

surface.25 This can be considered as the definition of SHP in Mexico. There has never been a nationwide study of SHP potential and its value remains unknown. The CFE has conducted planning studies in the majority of river basins for several decades, looking for specific sites with expected production greater than 40 GWh/year. In 2012, its inventory had 585 such sites, including 73 plants presently in operation. The combined capacity of the remaining 512 sites was estimated in 41,132 MW, with a generation of 114,754 GWh/year, and an average plant factor of 32 per cent.18

}} }} }} }}

In 1995, a global estimate close to 3,250 MW for the SHP potential of Mexico was published by CONAE, considering plants with capacity from 2 MW to 10 MW.19 It was based on an inference from data of 18 countries. Later on, the author stressed the urgent need to conduct a real assessment of national SHP potential.20 Nevertheless, many official and academic documents continued until present to cite the figure of 3,250 MW as a fact. There have been several official studies of SHP potential assessment in natural streams of some river basins that cover a very small portion of the national territory. These studies have a widely varying degree of hydrological and topographical precision. In the low end of precision, there is a pioneering study requested by CONAE in 1995 of six watersheds on the Gulf of Mexico coast, covering 26,376 km2, where a total of 100 SHP sites were identified using simplified techniques and data.19 In the high end of precision, there are studies requested by CFE in 2007 of three watersheds, covering 29,259 km2, where a total of 3,118 micro, mini and SHP sites were identified using advanced techniques. This included 110 SHP sites.21

17 plants are in operation at 195.4 MW; 27 plants are in construction at 736.1 MW; 34 plants are to start construction at 459.8 MW; One plant is inactive at 20 MW.

Developers are currently facing uncertainty as to how and when the new institutional and regulatory framework will take effect. The Convention No. 169 of the International Labor Organization (ILO), ratified by Mexico in 1991, sets the obligation to obtain on good faith the free, prior and informed consent from the indigenous and tribal peoples about new projects in their territory. The Law of the Electric Industry reinforces it in Art. 119. Systematic opponents to hydropower projects are prone to misuse this obligation by attempting to manipulate the inhabitants of distant communities. Legislation on small hydropower The licensing process includes the following main procedures: }} Legal incorporation of the company (15 days) obtained by the developer. }} Environmental Impact Assessment (EIA) authorisation (20 or 60 days) issued by SEMARNAT. Three options with increasing levels of complexity, depending on whether the project includes a preventive report, a particular or a regional EIA. }} Water authorization (60 days, for a period of 5-50 years) issued by Conagua, which grants the concession to use surface water. There are exemptions if the project is eligible as a RE project permit to use federal zone and a permit to build hydraulic infrastructure.

Facing the need to estimate the small-scale hydropower potential under 30 MW as input for planning purposes, SENER has published a total probable SHP potential of 2,629 MW.22 This value is combined capacity of 469 sites picked from the 512 in the inventory of CFE, after raising the plant factor to 100 per cent and reducing the height of the dams. Another estimate using a plant factor of 80 per cent yielded a total possible hydropower potential of 6,300 MW. These estimates are largely uncertain. Taking into account the rugged relief and heavy rain pattern in vast river basins of Mexico that have yet to 262

}} Feasibility studies by the CFE, consisting of a study on grid connection (30 days) and a feasibility study on transmission (20 days). Contracts issued by the CFE also need to be obtained, including a contract on grid connection (90 days), a contract to buy/sell RE to CFE, an agreement of electric backup and an agreement of transmission. }} Permits for electric energy generation, issued by the CRE (20 to 50 days). }} Municipal Permits for construction, issued by the municipal governments involved.

SENER and Conacyt have allocated funds to four Energy Innovation Centres focused on wind, solar, geothermal and ocean RE sources. With regard to the emissions of 2000, the General Climate Change Law has set the indicative goal of reducing CO2 equivalent emissions by 30 per cent in 2020 and by 50 per cent in 2050. On 27 March 2015, Mexico presented before the United Nations Framework Convention on Climate Change (UNFCC) its goals and commitments to reduce GHG by 22 per cent in 2030, compared to the levels of 2013. Barriers to small hydropower development


Mexico is a land of opportunity for RE development. The vastness of its hydropower potential remains to be assessed and harnessed. There is an enabling regulatory framework and the Energy Reform tends to improve it with the new Wholesale Energy Market unfolding. However, there are barriers to overcome so that the country can attain in the next decades its goals of a cleaner energy matrix amid an ever-growing demand of electricity. In the next 15 years, an additional annual demand for energy of 75 per cent more than the present is expected. A large portion of its supply could come from hydropower and other renewable sources. These details are detailed as follows:

The National Strategy for Energy Transition and Sustainable Use of Energy sets objectives, lines of action and goals for 2024 for the Federal Government to promote the greater use of RE and clean technologies. From 1992 until the Energy Reform, there were a number of incentives for RE including the following: }} Zero import duties for equipment that prevent pollution and for research and technological development; }} Accelerated assets depreciation for infrastructure projects that use RE sources; }} Contract of interconnection for intermittent RE sources with favourable provisions.

Renewable energy sector: }} Clear preference by policy makers to promote the expansion of the oil and gas industries over RE sources, considering the amount and investments and political support. }} Clear preference by policy makers for other RE over SHP, mainly wind and solar power.

In 2008, the Law for the Use of Renewable Energies and the Financing of the Energy Sector Transition (LAFERTE) was issued, which included economic, financial, fiscal, administrative, electric connection and technological incentives for RE projects.24 Likewise, in 2008, the Law for the Sustainable Use of Energy (LASE) was issued. This law also provides the National Programme for Sustainable Energy (PRONASE) and the National Commission for the Efficient Energy Use (CONUEE). SENER is legally bound since 2008 to assess, update and publish the national inventory of potential of RE.

Technological: }} Absence of a national hydropower potential inventory that is detailed and reliable. }} Hydrological uncertainty due to lack of adequate meteorological and hydrometric series. }} Studies tend to focus on local projects, rather than on entire river basins to systematically assess all feasible projects. }} Absence of prospective studies of water resources scenarios by watersheds to assess the impact on SHP projects in the long term. }} Technical deficiencies in SHP project formulation, due to rudimentary methods applied in the early phases of prospection and prefeasibility studies resulting in low success rate. }} Insufficient technical documentation of SHP projects, which adds to the difficulty and duration in the promotion phase. }} Limited local manufacturers of turbines.

The new Law of Energy Transition (LTE),25 which entered in force on 24 December 2015, to promote RE in the context of the Energy Reform replaced the two laws mentioned above, LAFERTE and LASE. The main goals of LTE are the following: }} Set goals for the clean energy portion in the generation matrix of 25 per cent in 2018, 30 per cent in 2021, and 35 per cent in 2024. The same proportion was 25 per cent in 2014. }} Provide instruments for the distributed generation and sale of energy by any person or enterprise. }} Provide for the strengthening and expansion of the transmission and distribution networks through the Programme of Smart Electric Grids. }} Strengthen the institutions charged with promoting energy efficiency. }} Create the National Programme of Sustainable Management of Energy to achieve energy efficiency goals.

Social: }} Legitimate social and community concerns regarding hydropower projects, often based on lack of education and objective information. }} Ideological and political opposition induced against 263

Central America

2.2


to generate energy, rather than for the energy produced. }} Inadequate or incomplete assessment of SHP project flows of costs and benefits. }} Difficulty of valuation of positive externalities of RE sources.

hydropower projects, private participation and foreign investments. }} Disproportionate expectations of local communities regarding compensations to remedy regional underdevelopment and lack of services. }} Delays or blockage of projects due to environmental and social opposition. }} Regional insecurity and delinquency.

Commercial: }} Saturation of the consumer market for self-supply. }} Low credit rating of prospective energy consumers. }} Low prices of energy delivered to the national electric system. }} Risk of gradual or sharp decline in energy prices due to energy bids. }} Difficulty to access mechanisms of payment for GHG emissions reduction.

Regulatory: }} Requirement to complete elaborate, costly feasibility studies, prior to having the assurance to obtain all the permits for the project. }} Complex and multiple licensing procedures with federal, state and municipal authorities, due to lack of a one-stop/single window scheme. }} Restrictions to issue water use permits for generation in river basins with extraction regulation or ban, even if hydropower is non-consumptive. }} High restrictions on projects proposed in protected areas, without objective balance of positive and negative impacts. }} Difficulty to license SHP projects in existing hydraulic urban and irrigation infrastructure. }} Requirement to connect to the electric grid in higher tensions. }} Exposure to risk of issuance of new concessions for different water uses or diversions upstream of the hydropower project. }} Delays in the consultation to get the consent of indigenous population due to lack of personnel and funds in the involved public institutions. }} Period from one to three years for licensing processes.

Financial: }} Lack of financing options for the prospection and prefeasibility phases. }} Limited funds made available by commercial banks in the country for SHP projects. }} Terms of commercial credit are not conducive to project implementation. }} Requirement to augment the ratio of equity capital to debt. }} Difficulty to access equity capital for some developers. }} Requirement to structure syndicated loans for larger projects. }} Difficulty of access to mezzanine funds, clearly subordinated to principal debt. }} Condition to disburse equity capital prior to using debt capital. }} High requirements of banks to assess the specific track record and financial solvency of the project developers. }} High requirements of financial guarantees, beyond the project expected cash flows, including: –– Long term power delivery agreements; –– High credit rating of energy consumer partners; –– Construction and supervision contracts with highly ranked and costly firms (EPC); –– Operation and maintenance contracts during the loan term; –– Requirement of opinions from independent experts. }} Difficulty in accessing mechanisms of partial guarantees of the loan. }} Difficulty in accessing mechanisms of guarantees against cost overruns of projects.

Legal: }} Risk of legal project interruption due to social or environmental pressures. }} Risk of legal challenge by another developer for a site that is under prospection or licensing process. }} Long period of contract preparation for structuring projects. Economic: }} Limited coverage and maintenance of roads in areas with high hydropower potential, requiring major investment in access roads. }} Limited coverage and capacity of electric grid in some areas with high hydropower potential, requiring major investment in interconnection lines. }} Generation and transmission electric networks that have privileged concentrated over distributed generation. }} Charges or duties for the volume of water used

264

2.2

Nicaragua

Central America

2.2.7

Marcis Galauska, International Center of Small Hydro Power


5,907,8811

Area

130,370 km2 1

Climate

The climate is tropical in the lowlands and cooler in the highlands, with two distinct seasons, wet and dry. The wet season lasts from mid-May to November, with May and October being the wettest. Temperatures in this season usually range from 27°C to 32°C. The dry season lasts from December to April, with April being the hottest and driest month. Temperatures during the dry season usually range from 30°C to 35°C but the weather can be very dry and windy.2

Topography

The Caribbean coast consists of low, flat, wet, tropical forest, extending into the pine savannas 80-160 km inland. The coastal lowland rises to a plateau covering about one-third of the total area. This plateau is broken by mountain ranges extending eastward from the main cordillera to within 64-80 km of the Caribbean coast. The mountainous central area forms a triangular wedge pointed south-east, rising at its highest to some 2,000 m. The highest peak is Pico Mogotón at 2,106 m. The plains and lake region, in a long, narrow structural depression running north-west to south-east along the isthmus, contains a belt of volcanoes rising to 1,500 m and extends from the Gulf of Fonseca to Lake Nicaragua.3

Rain pattern

The average annual rainfall along the Caribbean coast reaches 2,540-6,350 mm as a result of easterly trade winds blowing in from the Caribbean; the highlands also have heavy rainfall. Managua receives 1,140 mm while the Pacific coast averages over 1,020 mm a year.4


General dissipation of rivers and other water sources All of the major rivers run into the Caribbean. The Rio Grande, along with its tributaries, is the most extensive river system, while the Escondido provides a major transportation route between the Pacific and Caribbean coasts. The Coco runs along the border with Honduras and is the country’s longest river at 680 km. The San Juan begins in Lake Nicaragua and forms part of the border with Costa Rica.5


FIGURE 2

Electricity import/export in Nicaragua (GWh)

In 2013, electricity generation in Nicaragua was 4,163 GWh. An additional 52 GWh of electricity was imported and 16 GWh was exported, making overall domestic supply 4,199 GWh. 1,984 GWh was generated by coal, 679 GWh from geothermal, 562 GWh from wind, 482 GWh from biofuels, and 456 GWh from hydro sources (Figures 1 and 2).6

Diesel and oil Hydropower

The total installed capacity was 1,275 MW. National electricity is subdivided into two concession areas, covering only the western part of the country. More than half of the country on the Caribbean and Atlantic coasts remains outside of these concession areas.7 The overall electrification rate in Nicaragua is approximately 77.9 per cent, although the rural electrification rate is much lower.15

Electricity generation in Nicaragua (GWh) 1,984

Geothermal Wind Biofuels Hydropower

16

Source: IEA6

FIGURE 1

Coal

52

679 562 482

Electricity generation can be contracted via tenders organized by distributors or through bilateral contracts between generators and distributors and/or large consumers. The Instituto Nicaragüense de Energía (Nicaraguan Energy Institute, or INE) regulates the

456

Source: IEA6

265


electricity sector, where transmission and distribution are subject to regulated tariffs and generators can compete freely in the market. The Comité Nacional de Despacho de Carga (CNDC) is the electricity market operator, while the Ministry of Energy and Mines (MEM) oversees energy policy and planning.8

There are 18 SHP plants currently in operation. These are Samaria (7 kW), Aguas Rojas (5 kW), Las Piedrecitas (7kW), Las Brisas (5 kW), Los Milagros (10 kW), Kasquita (25 kW), Castillo Sur (24 kW), Kuskawas (50 kW), Ocote Tuma (30 kW), San Luis (50 kW), Campo Real (12 kW), San Vincente (42 kW), Malacotoya (13 kW), Bilam Pi (340 kW), Rio Bravo (180 kW), El Bote (900 kW), El Naranjo (240 kW) and Salto Negro (220 kW).

The National Development Plan in 2013 called for 94 per cent of the country’s electricity to be sourced from RE by 2017. The plan was ambitious and the country will not reach this goal by 2017. However, Nicaragua has been achieving many of its energy goals, specifically with wind farms and geothermal plants. Such achievements have already allowed it to reach its current share of nearly 75% of the gross domestic primary energy supply, and about 50 per cent of the total electricity supply, according to the INE.16 As a result, the government has since adjusted its aim from 94 per cent in 2017 to 91 per cent in 2027.16 A key part of the plan has been the 82 MW San Jacinto project, a massive 3,965 ha geothermal power plant built on the San Jacinto-Tizate geothermal area,10 widely considered to be one of the most productive volcanic reservoirs in Latin America. The plant is an essential component for the country’s continued infrastructure development, and in 2013 it generated revenue of US$46.2 million and 424,000 MW of net power.9

There are seven small hydro projects under construction. These are El Roblar (13 kW), La Laguna (23 kW), Valle los Meza (32 kW), Cano Los Martinez (20 kW), San Antonio de Yaro (14 kW), Dipina Central (25 kW) and El Zompopo (15 kW). There are 10 planned small hydro projects. These are El Corozo (300 kW), El Golfo (230 kW), casa Quemada (425 kW), Salto El Humo (200 kW), Salto Labu (210 kW), Salto Pataka (120 kW), El Hormiguero (250 kW), Salto Putunka (600 kW), Tunky Ditch (160 kW) and Ayapal (200 kW).11 Legislation on small hydropower Most of the projects are financed by private investors or international organizations (European Investment Bank, Inter-American Investment Bank etc.). The Nicaraguan Government provides its investors with tax based incentives such as income tax and import duty tariffs to support the implementation of clean energy projects. Furthermore, local micro finance institutions portray a robust system with 10 organisations providing green finance at an average cost of 1.5-28 per cent.

Small hydropower sector overview and potential The definition of small hydropower (SHP) in Nicaragua is up to 10 MW. The installed capacity of SHP is 2.2 MW while the potential is estimated to be 40 MW, indicating that approximately 5 per cent has been developed. Between the World Small Hydropower Development Report (WSHPDR) 2013 and WSHPDR 2016, installed capacity has decreased while the estimated potential has not changed (Figure 3).

The Nicaraguan Government has declared hydropower development to be an important part of its energy policy. A favorable legal framework and an attractive incentive structure have been established for hydropower plants with capacities below 5 MW. The necessary environmental permits are obtained from the Ministerio del Ambiente y los Recursos Naturales, generation of licences from Instituto Nicaragüense de Energía (INE), and water concessions from the Ministerio de Fomento, Industria y Comercio (MIFIC).14

FIGURE 3

SHP capacities 2013-2016 in Nicaragua (MW)

Potential 2016 2013

40 40


Law 476 for the Promotion of Hydroelectric Sub sector stipulates that hydropower schemes below 1 MW do not need a water concession. Instead producers will get a permit for 15 years. For schemes with capacities of 1-5 MW, a simplified procedure applies to obtain a water concession from MIFIC. Law 217 General Law of the Protection of Environment and the Natural Resources stipulates that projects with capacities below 5 MW do not need an environmental impact assessment.14

2.20 2.95

Sources: WSHPDR 2013,12 IJHD11 Note: The comparison is between data from WSHPDR 2013 and WSHPDR 2016.


The total installed capacity of SHP, approximately 2.2 MW, produces 0.0245 GWh/year. A further 142 kW of SHP is under construction, with another 2.7 MW planned for the next ten years. The total amount of SHP under construction is expected to generate 49 MWh/year and planned SHP is estimated to produce 9.4 MWh/year.

The principal legislation governing RE generation in the country is Law 532 for the Promotion of Electric Generation from Renewable Sources. It promotes the following:

266

}} Full exemption from taxes on the sale of carbon bonds; }} Exemption from all taxes that might exist for the exploitation of natural resources for a maximum of five years after the start of operations; }} Exemption from payment of customs duties and value added tax (VAT) on imports, machinery, equipment, and all materials intended solely for the pre-investment (and construction of) the subtransmission line for the national interconnection system.13

wind and 200 MW for biomass, the goal is to reach 91 per cent of electricity generation from renewable resources by 2027. Barriers to small hydropower development }} Difficulty in accessing finance because of the high initial cost of projects. Commercial finance is needed for the long term, but in general, financial assistance is short-term and hence shows high interest rates. }} Requirements and costs for permits are the same for large and small projects. The cost per MW for small projects is very high and the concession process is very slow, often lasting several years. }} Power purchase agreements are too short to motivate SHP project development. Therefore, it is difficult to take long-term investment decisions. }} The approved fiscal incentives for hydropower projects do not yet create a level playing field for hydropower development in general compared to thermal projects, since the latter continue to be highly subsidized.12

In addition to the above, a high-level government entity for the country’s energy sector was created in 2007, the Ministry of Energy and Mines (MEM). Its mandate is to allocate resources to resolve the energy crisis in the country, and create an energy sector consistent with the country’s long-term sustainability plan. One of MEM’s main obligations is to oversee the formulation, coordination and implementation of the strategic plan, as well as the public policies, covering the energy sector. MEM also oversees the operation and administration of companies operating in the RE sector. There is a great potential for development of RE, approximately 2,000 MW for hydro, 1,500 MW for geothermal, 800 MW for

267

Central America

2.2

Panama

2.2.8

José Fábrega, Alexis Baúles and Denise Delvalle, Universidad Tecnológica de Panamá


3,657,0241

Area

75,420 km2

Climate

It has a tropical climate with two seasons, dry and rainy, with variations depending on the region and the altitude. Winter is the wet season (May to November) while summer is the dry season (December to April, with March and April normally being the warmest months). The temperatures on the coast regularly reach 35°C, but the temperature drops 1°C for every 150 m.

Topography

Panama has rugged mountains to the west and towards the Caribbean Sea and rolling hills along with large plains to the Pacific Coast. The lowlands in Panama cover around 70 per cent of the country. The highest point in Panama is the Volcán Barú, which rises to 3,475 m.

Rain pattern

From 1971 to 2002, Panama had a yearly average precipitation of 2,924 mm.2 The Pacific region shows a wet season pattern from May to November. For the Atlantic region, precipitation is continuous throughout the year.3


There are around 500 rivers in Panama in 52 watersheds, with 70 per cent of rivers running to the Pacific side (longer streams) and 30 per cent to the Atlantic side.4


It is worth mentioning the role of the Panama Canal Authority. The Panama Canal Authority is the biggest independent producer (auto generator) in Panama, with an installed capacity of 258.6 MW (71.8 per cent comes from thermal plants and 28.2 per cent from mini and small hydropower (SHP)).7 The main objective of the Panama Canal Authority is to assure the performance of the canal. Even though there is a favourable legal framework for the development of SHP plants, a local financial framework supporting the investment of SHP plants is still lacking.

The energy generated in 2014 was approximately 9,256 GWh, from which only 4.7 per cent came from renewable sources.5 The consumption of electricity in 2014 was 7,822 GWh. Panama exports its energy surplus to neighbouring countries like Colombia. Thus, the government aims to make Panama an energy hub in Latin America.6 FIGURE 1

Installed electricity capacity in Panama (MW) Hydropower


Thermal power Wind power Solar power

The National Department of Energy, created by Law 43 on 23 April 2011, is in charge of the energy sector.9 The Rural Electrification Office (Oficina de Electrification Rural, or OER) is responsible for providing energy in the rural and isolated areas that are not connected to the national grid. The OER has a goal to increase the electrification for rural areas by using photovoltaic energy and building electricity grids for short distances (10 km). From November 2013 to October 2014, up to 109 projects were completed in the provinces of Colon, Darien, Coclé, Bocas del Toro and Indigenous territories. Approximately, 25,000 inhabitants received access to electricity.10 The OER is supervised and budgeted by the Ministry of the Presidency. However, all project ideas have to be proposed by rural communities in order to be included in their planning.

1,623.4 1,147.8 55.0 2.4

Source: SNE-ETESA5

Electricity generation in Panama comes mainly from hydropower, thermal generation and renewable energy sources like wind and solar power. The installed capacity in Panama by the end of 2014 was 2,828.6 MW, which was 6.1 per cent more than in 2012. Hydropower represents 1,623.4 MW (57.4 per cent) and thermal represents 1,147.8 MW (40.6 per cent). Furthermore, 55.0 MW (1.9 per cent) came from wind farms and 2.4 MW (0.08 per cent) from solar energy (Figure 1).5

The energy sector is regulated by Law No 6 introduced 268

on 3 February 1997 (and its later amendments) as well as by Decree Law 22 of 1998.9,11,12,13 The transmission of energy is carried out almost entirely by the Empresa de Transmision Electrica S.A. (ETESA). Currently, the electricity grid of Panama consists of two main transmission lines. There is a transmission systems modernization and expansion plan financed by the LatinAmerican Development Bank for the period of 20142017. The plan expects to carry out the following by the end of 2015: }} The modernization of the electricity transmission system, through increasing the capacity of transmission of electricity in the National System of Interconnection; }} Extend the coverage of the network; }} Improve the quality of the service.6

MW,19 the legal framework in Panama considers plants up to 10 and even 20 MW.20 OLADE’s definitions on SHP is as follows:19 }} Small hydropower: 500-5,000 KW. }} Mini hydropower: 50-500 KW. }} Micro hydropower: up to 50 KW Figure 2 shows the increase in SHP potential and installed capacity from 2013 to 2016 (as of January). Potential capacity is defined as concessions granted for SHP plants. FIGURE 2

SHP capacities 2013-2016 in Panama (MW) Potential

The construction of a third transmission line is needed and it is foreseen to become part of the national grid in a few years.14

2016 2013

147.6 122.3


The total electricity consumption considering all sectors (private, commercial, governmental, industrial and public electrification facilities) in Panama was 7,401 MWh in 2014. This number represents a per capita consumption of 1,735 kWh and is double the average consumption rate in Central America (848 kWh per person).15 According to a statement issued in 2014 by the Department of Energy, the demand of electricity is going to increase approximately 4.8-7.4 per cent for the next 15 years. In order to alleviate the energy shortage of 300 MW, several thermoelectric power plants have been contracted in 2015.16

86.6 38.8

Sources: ASEP,21 WSHDR 201322 Note: The comparison is between data from WSHPDR 2013 and WSHPDR 2016.

Since 1970, the Government of Panama has shown interest in the development of SHP plants. The government, in collaboration with the US Agency for International Development carried out a study in the country and identified 40 potential SHP sites. In the framework of these studies, the following micro hydropower plants were built: La Tronosa (60 kW), La Pintada (30 kW), Pueblo Nuevo (50), Buenos Aires (10), Entradero de Tijeras (50 kW) and El Cedro (35 kW). These micro hydropower plants were built with the support of the Government and the communities.23

In Central America, the Central American Electric Interconnection System has been set up in order to create an integrated electric market within the six countries of the region: El Salvador, Guatemala, Honduras, Costa Rica, Nicaragua and Panama.17 For instance, in 2012, an interconnection was planned with Colombia. The planned line has an extension of 614 km (including an underwater line of 55 km, with 44 km in Panamanian territory). However, this project was stopped for two years after the President of Panama disapproved of the costs. In 2014, however, the President of Panama, along with his Colombian counterpart, agreed to restart the project and projected a completion date for 2018.27 After the privatization of the public electricity service in 1998, the ETESA was charged with dispatching and transporting electric energy in an efficient, safe and reliable way— through adequate planning for the expansion, the construction of new amplifications and the reinforcement of the transmission grid.18 The remuneration for the services carried out by the ETESA is regulated by Law 6 of 1997.11

In Panama, a self-generation producer is defined as an entity producing and consuming electricity in the same place in order to attend its own needs. These kinds of energy producers do not sell or transport energy to third parties. However, they can sell the energy surplus to other energy agents.7 Renewable energy policy The starting point for the promotion of renewable energies is included in Chapter II, Title VIII of the Law 6 of 1997.11 Renewable energy sources are defined in this law as geothermal, wind power, solar energy, biomass and hydropower. The high prices and the high levels of energy consumption led to the promulgation of the Law 44 of April 2011;18 this law aims to promote mostly wind power and the diversity in the renewable energy sources. The application of the model Long-Range Energy Alternative Planning is used to determine the possible scenarios of combination in between energies, i.e. hybrid systems. It is a way for developing scenarios created by Shwartz in the context of economic and energy models.24

Small hydropower sector overview and potential Although the Latin American Energy Organization’s (OLADE) definition of SHP for Latin America is up to 5 269

Central America

2.2


According to the National Energy Plan,25 incentives are being applied in order to comply with the Kyoto Protocol. However, these incentives might need to be adapted to the new agreements made in the 2015 COP 21 held in Paris.26 The Panamanian Government and private investors are working on developing SHP, wind farms, solar energy, and biomass generation.

20 MW receive exemptions for the first delivered 10 MW for 10 years, there are fiscal exemptions for importing equipment, machinery, materials and others and there are fiscal incentives for projects up to 10 MW and with up to 25 per cent of CO2 emissions per year. Barriers to the small hydropower development

Small hydropower legislation

Although there is a favourable legal framework granting fiscal incentives in order to develop SHP plants, the SHP sector development is not significant. The most important barrier is the lack of a solid financial framework in order to support the investment in SHP plants. It is also worth noting that the OER does not include the development of SHP plants in its future plans.

The government established a legal framework in 2004 by enacting Law 45, with incentives for hydropower generation and other renewable energy sources with an extended scope for the SHP definition (up to 20 MW).20 Law 45 provides incentives for small and mini hydropower plants: SHP plants up to 10 MW are not charged for selling energy directly or indirectly, small projects of 10-

270

2.3 South America Cleber Romao Grisi, WHITEnergy Bolivia

Introduction to the region

FIGURE 1

Share of regional installed capacity of SHP by country

South America is the fourth largest subcontinent on Earth with a total land area of approximately 17.8 million km2. It is bordered by Central America and the Caribbean Sea to the northwest, the Atlantic Ocean to the east and north and the Pacific Ocean to the west. The South America region comprises 12 sovereign countries: Argentina, Bolivia, Brazil, Chile, Colombia, Ecuador, Guyana, Paraguay, Peru, Suriname, Uruguay and Venezuela, as well as several dependent major territories: French Guiana administrated by France, the Falkland Islands and the South Georgia and South Sandwich Islands under the British Government. This report covers 10 countries and one territory, of which eight have an installed capacity of small hydropower (SHP), with Brazil having 83 per cent of the regional total (Figure 1). This report also covers Paraguay and Guyana, which were not included in the World Small Hydropower Development Report (WSHPDR) 2013.1,3,9

Ecuador, 1.4%

Peru, 3.8%

French Guiana, 0.1%

Argentina, 1%

Colombia, 3.7%

Bolivia, 0.3%

Chile, 6.5% Brazil, 83%

Source: WSHPDR 201610

about 30°C and rainfall can exceed 5,000 mm a year.6 There are approximately 418.5 million inhabitants; most of this population lives near the continent’s western and eastern coasts, while the interior and the far south are sparsely populated.2 Approximately 83 per cent of the total population lives in the urban areas.7 In South America, almost 87 per cent of the rural population has electricity access. The urban electrification rate is about 98 per cent.5

South America can be divided into three physical regions: river basins, coastal plains, as well as mountains and highlands. Coastal plains and mountains and highlands generally run in a north-south direction, while highlands and river basins generally run in an east-west direction. The western part is dominated by the Andes mountains, where temperatures fall below 0°C, and the Pacific coast, where rainfall can be as low as 1 mm per year (Atacama Desert). The eastern region is ruled by tropical rainforests and vast grasslands, where the average temperature is

Electricity is produced from different sources where the dominant technologies are hydropower and thermal.

TABLE 1

Overview of countries* in South America (+ % change from 2013) Country

Total population (million)

Rural population (%)

Electricity access (%)

Electrical capacity (MW)

Electricity generation (GWh/year)

Hydropower capacity (MW)

Hydropower generation (GWh/year)

Argentina

42.6 (+5%)

8.2 (+0.2pp)

95 (-2.2pp)

37.6 (+11%)

131,205 (+2%)

10,700 (+6%)

40,663 (+1.8%)

Bolivia

10.0 (+1%)

31.5 (–1.5pp)

87 (+9.5pp)

1.61 (+11%)

7,836 (+28%)

477 (0%)

2,233 (–42%)

202.7 (+6%) 14.3 (+1.3pp) 99.7 (+0.7pp)

142 (+21%)

624,300 (+17%)

92,159 (+12%)

407,200 (+1%)

19 (+8%)

69,897 (+11%)

6,410 (+7%)

23,871 (0%)

98 (+4.4pp)

15.5 (+7.5%)

N/A

10,919 (+12%)

38,714 (0%)

16.2 (+12%) 36.3 (+3.6pp) 97.2 (+4.1pp)

5.10 (0%)

23,258 (+13%)

2,237 (0%)

11,048 (+20%)

Brazil Chile

18.0 (+5%)

10.5 (–0.5pp) 99.6 (+1.1pp)

Colombia

48.3 (+4%)

23.6 (–1.4pp)

Ecuador French Guiana

0.24 (+4%)

15.6 (–8.4pp)

N/A

0.29 (0%)

N/A

119 (–7%)

N/A

Guyana

0.76

71.4

79.5

0.18

771

0

0

Paraguay

6.55

40.3

99

8.83

55,582

8,834

55,276

21.4 (–1.6pp) 90.3 (+4.6pp)

12.25 (+30%)

48,066 (+209%)

4,166 (–5%)

23,300 (–4%)

3.12 (+16%)

10,515 (6.3%)

1,538 (0%)

3,125 (–61%)

— 245.5 (+22%)

971,430 (+15%)

137,559 (+18%)

605,430 (+12%)

Peru Uruguay Total

31.15 (+7%) 3.40 (+1%)

4.7 (–3.3pp)

379.9 (+8%)

—

99 (+0.7pp)

Source: WSHPDR 2013,9 WSHPDR 2016,10 Geohive7 271

South America hosts the Amazon, Orinoco, and Paraguay/ Paraná River basins, covering almost 7 million km2, 948,000 km2 and 2.8 million km2, respectively.6 These watersheds make this continent attractive and suitable for hydroelectric development of varying capacities.

FIGURE 2

Net change in installed capacity of SHP (MW) for South America, 2013-2016

The total hydropower installed capacity in South America, including large, medium and small facilities, is about 103 GW. Hydroelectric production has increased since 2013 for all countries in South America, except in Bolivia where thermal (natural gas) energy has replaced hydropower production.

67

78

18

1

_

_

40

_

Chile

Colombia

Ecuador

French Guiana

Guyana

Paraguay

Peru

Uruguay

_ Brazil

_

Bolivia

1,413

Argentina


Regional overview and renewable energy policy

Other sources include nuclear, wind and biomass. Installed capacity and energy production have increased in all South American countries since 2013. Five countries have increased their share of SHP resources (Figure 2).

Countries in South America started to develop SHP projects to feed small towns or the national grids since 1970. However, project development is slow due to the higher costs compared to large or medium scale hydropower schemes, the lack of appropriate regulations related to taxes, tariffs, subsidies and concessions, environmental permits and due to social acceptance.9,10 However, since 2013, potential capacity for SHP in South America has increased by 14 per cent and the installed capacity has increased by 31 per cent. Table 3 gives an overview of SHP in South America.

Sources: WSHPDR 2016,10 WSHPDR 20139 Note: The comparison is between data from WSHPDR 2013 and WSHPDR 2016.

TABLE 3

SHP in South America (+ % change from 2013)

SHP definition The definition of SHP varies across the countries in South America. In most cases, there are no limits for categorizing small, micro and pico hydropower. In some countries, SHP remains undefined (Table 2).

Country

Potential (MW)

Planned (MW)


Annual generation (GWh)

Argentina

430 (0 %)

30

66 (0 %)

N/A

50

50

21.3 (0 %)

N/A

Brazil

250,000 (+11 %)

429

5,518.5 (+34 %)

26,400

Chile

17,000 (+57 %)

423

435 (+18 %)

N/A

Colombia

25,000 (0 %)

N/A

250 (+46 %)

N/A

383 (+29 %)

49

94.92 (+24 %)

474.13

French Guiana

N/A

7

6.3 (+15 %)

N/A

Guyana

24.17

N/A

0

0

N/A

0

0

0

Peru

1,600 (–)

N/A

391 (+11 %)

N/A

Uruguay

232 (+111 %)

N/A

0

N/A

63,544 (+99 %)

988

6,783 (+291%)

Bolivia TABLE 2

Classification of SHP in South America Country Argentina

Small (MW)

Mini (MW)

Micro (kW)

Pico (kW)

≤3

50 to < 500

5 to < 50

—

0.5 to < 30

—

< 500

—

Brazil

1 to < 30

—

—

—

Chile

< 20

—

< 300

—

Colombia

0 to < 10

—

—

—

Ecuador

10 to < 20

—

—

—

French Guiana

—

—

—

—

Guyana

≤5

—

—

—

—

—

—

—

≤2

—

—

—

< 50

100-1,000

< 100

5 MW

9.60

10.56

13.21

14.53

Hydro < 10 MW

7.17

—

Hydro > 10 , < 30 MW

6.88

—

Hydro > 30, < 50 MW

6.21

—

SHP capacities 2013-2016 in Ecuador (MW) Potential 2016 2013

296.6


South America

}} }} }} }} }}

regulation of and planning for the entire electrical sector of the country. This law also promoted the creation of the Electricity Regulation and Control Agency, replacing the previous National Council of Electricity.4

383.0 94.0 76.5

Geothermal

Source: Consejo Nacional de Electricidad6 Note: The comparison is between data from WSHPDR 2013 and WSHPDR 2016.

Source: INAMHI3

The former Ecuadorian Institute of Electrification performed in-depth studies related with the vast hydropower potential of the country during the 1970s and 1980s.

Moreover, Regulation No. 004/011 issued by the National Electricity Council of Ecuador (CONELEC) in 2011 and valid until December 2012, specified the requirements for renewable energy projects, the prices of the energy depending on the source, the time period during which the prices will be valid, and the preferential dispatch to the grid. These prices (Table 2) will be valid for 15 years for renewable energy projects and the preferential energy dispatch.

Until the national grid was built and came into operation, there were only SHP generation projects that provided electricity to their nearest communities during the 1960s, 1970s and into the 1980s. Once the national interconnected grid became operational, many of those communities were connected to the network and received better quality services. After this, SHP plants were gradually abandoned.

TABLE 2

Energy prices in Ecuador (Regulation No. 001/013), 2013-2014 (US$ cent/kWh)

The Ministry of Electricity and Renewable Energy of Ecuador (MEER) and the Association of Mechanical Engineers of the Pichincha’s province developed an inventory of all those projects in 2008 and evaluated the feasibility to return them to service. A total of 10 aged SHP projects with an accumulated installed capacity of 9.42 MW were considered eligible for restoration.8

Type of plants

In addition, MEER developed design studies of six SHP plants up to 20 MW with the support of the National PreInvestment Institute: }} Huapamala (5.2 MW);

Continental territory

Galapagos Island

Wind

11.04

12.91

Solar

25.77

28.34

Biomass or Biogas

11.08

12.19

Geothermal

13.81

15.19

Hydro < 10 MW

7.81

—

Hydro > 10 ,< 30 MW

6.86

—

Hydro > 30, < 50 MW

6.51

—

Source: INAMHI

3

291


}} Pre-feasibility study of the project, developed by the interested party under the standards established by CONELEC for this purpose. The study must consider the optimal use of the resources, not reduce the potential of other projects having a direct relationship with the new project, and which can be developed in the near future. The information must be presented in hardcopy and digital format. }} Intersection (coordinates) Certification issued by the Ministry of Environment for whether the project is inside the national system of protected areas. If the project is located inside protected areas, it is required to present Authorization for use from the Ministry of Environment.

Besides that, Regulation No. 001/13 issued in 2013 by the National Electricity Council of Ecuador (CONELEC), which was valid until March 2014, established new prices for energy generated from renewable sources depending on the source, but the preferential period and the preferential energy dispatch did change from the previous Regulation No. 004/011. Regulation No. 001/13 was modified in 2014 obtaining the following prices for energy generated from nonconventional sources: TABLE 3

Energy prices in Ecuador for energy generated from non-conventional sources (Regulation No. 001/013; 2014-2015) (US$ cent/kWh) Type of plants

Continental territory Galapagos Island

Biomass

9.67

10.64

Biogas

7.32

8.05

6.58

—

Hydro ≤ 30 MW Source: INAMHI

Barriers to small hydropower development While hydropower has played a key role in the energy sector of Ecuador for a long period, SHP saw its share in the energy mix decrease as the national grid was extended. More recently, SHP has had resurgence within the mix, and will continue to do so as the abandoned SHP sites are rehabilitated and new installations become operational. Despite this, there are several barriers to the development of SHP in the country: 9,10 }} Lack of tax incentives for private investors. With the new regulations, the investors of renewable energy projects will have a preferred price for each kWh sold to the grid and the certainty that the electricity generated will always be bought by the State. However, there is no definition of a process for qualifying renewable energy projects with other government institutions (SRI, ARCONEL, Ministry of Environment, etc.) to obtain incentives in the tax reporting as stated in the Code of Production on the sustainability of production and its relationship to the ecosystem. }} Large projects receive all the attention. Ecuador has eight emblematic hydro projects under execution, which constitutes the biggest advance promoted and developed by the National Government. The nine electrical projects are: Coca Codo Sinclair (1,500 MW), Minas San Francisco (270 MW), Delsitanisagua (180 MW), Manduriacu (60 MW), Mazar Dudas (21 MW), Toachi Pilatón (254.4 MW), Quijos (50 MW), Sopladora (487 MW). These projects will efficiently and sustainably exploit sources of hydropower by applying clean energy and reducing pollution. These emblematic projects are the perfect example of a country, a new Ecuador, advancing and reaching historic levels of productive, energetic and social development.1 Thus investment in the construction of these projects has received important contributions of the Ecuadorian State, leaving aside the investment of SHP projects, opening the possibility for private investments and development of small projects. This is because inaccessible sites are expensive to develop since they necessitate the construction of access roads, and transmission lines over large distances. These expenses reduce the indicators for profit and performance of the project, even making some unfeasible.11

3

Today, with the creation of the Electricity Regulation and Control Agency (ARCONEL) the regulations producing incentives for this type of projects are under review and will be updated. Regulation No. 002/13, issued by CONELEC, is applicable to all projects with power not exceeding 1 MW. The developers of the projects will not need a license to operate. Instead they have to register the project with CONELEC after getting a permit from the National Water Resources Secretariat (Senagua) to use the water for industrial purposes, and a certificate from the Ministry of Environment that certifies that the project is not located inside a National Protected Area. For all projects with power exceeding 1 MW, the project developer must meet the mandatory requirements listed below:9 }} Company incorporation document, where electrical power generation is considered as the main activity of the company, and registration of foreign companies in the country; }} Certificate of compliance with obligations and legal status issued by the Superintendent of Companies (Superintendencia de Compañías); }} Certified copy of the appointment of a legal representative; }} Payment to the solicitor, equivalent to 200 US$/MW of the declared capacity; }} Feasibility check of the connection to the transmission or distribution system; }} Detailed project proposal, including the general specifications of the equipment to be installed, type of power plant, location, general layout, characteristics of the transmission or interconnection line, if applicable. The information must be presented in hardcopy and digital format.

292

2.3

2.3.7

South America

French Guiana Marcis Galauska, International Center on Small Hydro Power


243,000 1

Area

83,534 km2 1

Climate

French Guiana has a tropical monsoon climate with a short dry season. It is hot all year round, with cooler nights. The average temperature is 27°C.2

Topography

French Guiana is situated on the northeast coast of South America, and is bordered by Brazil to the south and east and by Suriname to the west. The southern Serra Tumucumaque Mountains are part of the eastern frontier while the rest is formed by the River Oyapock. Suriname is to the west along the Rivers Maroni-Itani and to the north is the Atlantic coastline. Along the coast runs a belt of flat marshy land behind which the land rises to higher slopes and plains or savannah. The interior is mostly equatorial jungle. Off the rugged coast lie the Iles du Salut and Devil’s Island. The highest peak is Bellevue de l’Inini (851 m).2

Rain pattern

The average annual rainfall is approximately 2,500-3,000 mm. The dry season runs from August to December and the rainy seasons are December to January and April to July.


French Guinea is a land of rivers, many of which flow north from the southern mountains. The major ones include the Maroni and Lawa, forming its (disputed) border with Suriname; the Oyapok, forming a long natural border with Brazil; and the Approuaque, Camopi, Mana and Tompok.3


The power system can therefore be characterized by its disparities, fragility and the major role that fossil fuels play in power generation. In French Guiana, electricity costs twice as much to produce in relation to the price it is sold at, and it is subsidized by a national solidarity fund. Even when the inland areas do have a power supply, they suffer from frequent power cuts.5

Installed capacity in 2014 was 290 MW (159 MW from renewable sources and 131 MW from fossil fuels). Of the total capacity of renewable energy, 119 MW was hydropower, 38 MW solar power and 2 MW biomass (Figure 1). In 2011, 838 GWh of electricity was generated in French Guiana and fed into the grid.4

Small hydropower sector overview and potential The definition of small hydropower (SHP) in French Guiana is up to 10 MW. Installed capacity of SHP is 6.3 MW. Between the World Small Hydropower Development Report (WSHPDR) 2013 and WSHPDR 2016, the installed capacity has increased by approximately 15 per cent.

FIGURE 1

Installed capacity in French Guiana (MW) Fossil

131

Hydropower

119

Solar power Biomass

FIGURE 2

38

SHP capacities 2013-2016 in French Guiana (MW)

2

Source: IRENA4

The main player in the electricity generation sector is Électricité de France (EDF), which mainly focuses on gas and hydropower resources. This is done primarily via the Petit-Saut dam, which produces 50-70 per cent of electricity used by French Guiana. Isolated inland towns are powered by large electric generators,5 and 35 per cent of the population lives in remote villages without an electricity supply.

2016 2013

Potential

N/A

capacity

N/A

Installed capacity

6.3 5.5

Sources: WSHPDR 2013,5 Voltalia7 Note: The comparison is between data from WSHPDR 2013 and WSHPDR 2016.

293


There are two SHP plants in operation: La Mana with an installed capacity of 4.5 MW, and Saut-Maripa with a capacity of 0.88 MW.6 In 2014, the company running the hydropower plant on the Mana River received authorization to increase the capacity of its existing hydropower plant from 4.5 MW to 5.4 MW (a 20 per cent increase).7 From all installed hydropower capacity, approximately 5 per cent is a SHP. Countrywide potential hydropower capacity is unavailable, but sites have been identified on the Mana, Compté and Approuague Rivers, which would make it possible to produce 7-15 MW in the next few years.8

exemplary programmes, specific to each department, shall subsequently be developed with the end goal of achieving energy independence by 2030.5

Special conditions prevail in non-interconnected power systems in areas described as ‘islands’ by the European Community. These areas do not allow the emergence of a competitive market in the energy sector. Therefore, French Guiana, as an overseas territory of France, has an exemption specially set by the European Community in favour of ‘small isolated systems’. As a result, utilities in French Guiana are not required to separate their network management from their business. EDF continues to integrate all electrical trade to ensure public service. As such, they are committed to generate electricity in competition with other producers and purchase all electricity produced in the territory. They also run 24 hours to ensure a power system balance between customer demand and supply of electricity producers, as well as for transportation and distribution of electricity to all customers.8

For over thirty years now, photovoltaic solar energy has been used to supply remote houses and villages. More recently, solar units have also been used to directly generate electricity for the grid. Within the next few years, 40 MW of capacity is expected to be installed. This is as much as the network can handle without disruption, given that this is an intermittent and fluctuating energy source. The wind in French Guiana is of average strength. Nevertheless, the fact that it is regular and there are no cyclones means that a wind farm of 12 MW with large 2.5 MW wind turbines is a possibility.8

French Guiana has a large supply of biomass resources, especially forests. The greatest potential lies in waste from the clearing of agricultural land and logging. A first biomass factory producing 2 MW at Kourou is in operation and some other projects are underway. By 2020, it should therefore be possible to produce over 20 MW from biomass stations, with the advantage of constant levels of production and a guaranteed power output.8

Barriers to small hydropower development The trepidation of a re-occurrence of the El Niño phenomenon plays a crucial role in the government’s decisions to increase dependence on small hydro and as a whole as an energy source. The geographical barrier stems from the specialty of French Guiana, which has a vast landmass with clearly separated coastal and inland areas, coupled with a flat topography, making it more difficult to develop SHP. However, French Guiana is faced with other challenges that strongly hinder the development of SHP, more so than natural climatic variations. The most important factors that impede development are geographical isolation and high demographic growth. Borders with Brazil and Suriname suffer from a lack of control, which results in high crime rates. This prevents foreign investment in the region.6 In addition, a lack of incentives and technical standardization as well as the low population density makes it difficult and less attractive to develop SHP.5

Renewable energy policy French law is applicable in French Guiana. However, it can be altered to meet its specific characteristics (on the basis of Article 73 of the Constitution). As a result of this, the Climate Plan to reduce GHG emissions by a quarter by 2050 has also been applied to French Guiana. The National Assembly voted for the Grenelle de l’Environnement (Environmental Forum) law in October 2008. This law applies to the French overseas departments, of which French Guiana is a part. The law states that energy independence shall be achieved by reaching an objective of 50 per cent of final energy consumption in French Guiana, Guadeloupe, Martinique, and La Réunion from renewable sources by 2020, and that

294

2.3

Guyana

South America

2.3.8

Sven Homscheid; Morsha Johnson-Francis, Ministry of Public Infrastructure; Mahender Sharma, Guyana Energy Agency; Horace Williams, Hinterland Electrification Company


763,893 2

Area

215,000 km2

Climate

It has a tropical climate, with temperatures of around 25°C and with little variation throughout the year.3

Topography

The terrain is mainly tropical rainforest with flat areas at the coastline and some mountainous areas in the hinterland.3

Rain pattern

It has generally high precipitation of 1,500 mm to over 4,000 mm with a pronounced rainy season from May to August and a shorter one from December to January.3


Guyana is called the ‘Land of Many Waters’ due to the abundance of streams, rivers and creeks. The largest waterways are the Corentyne, Berbice, Essequibo and Demarara Rivers. Particularly in the southern and relatively unpopulated part of the country, there are many falls along the rivers while the rivers’ gradients decreases towards the more densely populated areas at the coastline.3


FIGURE 1

GPL supplied electricity in Guyana (GWh)

The electricity system in Guyana is an integrated network on the coast that supplies about 80 per cent of the national population, with various clustered island systems in the Hinterland supplying individual smaller communities and mines. While the electrification rate at the coast is high, most of the Hinterland communities do not have a regular electricity supply.

Thermal Biomass

658 53

Source: Guyana Power and Light Incorporated1

The country’s primary electricity utility is Guyana Power and Light Inc. (GPL), a wholly government-owned, vertically integrated utility company whose license will expire in 2024. In many smaller Hinterland communities such as Lethem, Mahdia and others. Government-owned electricity companies provide supply to the public institutions and households. In some cases, this is provided on a 24 hour basis and in others, for several hours daily.

Transmission voltage level is 69 kV and feeder and distribution voltage level is generally 13.8 kV or 11 kV, domestic supply voltage is 110 V at a frequency of 60 Hz. The infrastructure in the GPL system is aged and causes frequent service interruptions resulting in many businesses operating off-grid or using their own diesel generators as backup. Also, in the Hinterland, electricity systems supply is rather erratic and mostly only for several hours per day. The combined technical and nontechnical losses of the coastal system are approximately 30 per cent.1

Electricity is generally generated with diesel and heavy fuel oil generators, with the exception of a small cogeneration portion from bagasse and grid connected and off-grid solar systems. In 2013, GPL supplied its customers in the coastal area with 711 GWh of electricity, of which about 53 GWh was from biomass through an independent power producer (IPP) (Figure 1).1

In the Hinterland electricity systems, various private electricity providers have been established, foremost in conjunction with mining operations that supply the nearby communities with electricity. The Public Utilities Commission regulates the electricity sector. No effective policy or sector regulation is in place to effectively encourage the participation of independent power producers (IPPs). The Guyana Energy Agency (GEA) is mandated to advise the energy minister in matters related to energy, execute studies, establish energy policies, and regulate the import of petroleum products, but has no general role as electricity or energy

GPL’s installed capacity in 2013 was about 148 MW, while the available capacity was about 119 MW. Together with the 26 MW HFO based generation capacity added in 2014 and the generators in the Hinterland electricity supply systems, the installed capacity was about 180 MW. The peak demand in the coastal area system is approximately 110 MW. 295


sector regulator. Besides the GEA, there is the Hinterland Electrification Company Inc. (HECI) that is attached to the Ministry of Public Infrastructure and is responsible for the electrification of the rural communities. The office of the minister responsible for energy, currently the Minister of Public Infrastructure, issues licenses for IPPs and electric utilities.

offer following a market due diligence, an operational assessment of GPL, and financial due diligence of GPL done by a British consulting firm. At the same time, rising prices for commodities and financing have increased the project cost significantly.6 Furthermore, the existing—but non-operational—500kW hydropower plant Moco-Moco, close to the town of Lethem, was financed and built in 1996 with support from the Chinese Government. Unfortunately, in 2003 a landslide destroyed the penstock and a fire in the powerhouse rendered the electrical equipment useless. Studies have been conducted to rehabilitate the plant but no concrete action has followed.

GPL’s residential, commercial and industrial rates are US$0.24, US$0.31 and US$0.27/kWh, respectively. Rates in the Hinterland systems are higher with generation costs ranging as high as US$0.50/kWh. Current electricity tariffs are far from cost reflective, as the government subsidizes GPL’s operation. Small hydropower sector overview and potential

The 1.5 MW Tumatumari hydropower project on the Potaro River was put in operation in 1959 for power supply to a mining company. Afterwards, it was operated to supply the nearby settlements until the plant was decommissioned in the early 1990s. Several actors are currently entertaining efforts to rehabilitate the site, though there has been no tangible outcome yet.

The definition of small hydropower (SHP) in Guyana is up to 5 MW. There is no installed capacity in Guyana, while potential capacity is estimated to be 24.17 MW (Figure 2). FIGURE 2

SHP capacities in Guyana (MW) Potential capacity Installed capacity

In recent times, hydropower initiatives have been considered and supported by the Government of Guyana. The Guyana Power Sector Policy and Implementation Strategy passed in 2010 outlines the way forward.

24.17 0.00

After the government stalled the development of the Amaila Falls project due to the associated high-risk levels, the government’s interest has reopened towards SHP projects. Therefore, projects like Moco-Moco, Tumatumari, Kato and others of small magnitude are now being reconsidered and support has been sought from international assistance agencies for its implementation.4

Source: Guyana Energy Agency4

The National Energy Policy of 1994 speaks of SHP in the capacity range of 500-5,000 kW.10 Some sources estimate the country’s overall hydropower potential at 7,000 MW, while some estimates are lower. Though Guyana has a track record of hydropower use, to this date, not a single hydropower plant is operational. The Guyana Energy Agency has published on its web page a list of 67 potential hydropower sites that were identified through numerous studies. Based on those studies, estimated SHP potential is 24.165 MW.4 Various projects were studied through the feasibility stage and some even further.

Due to the natural wealth in fauna and flora, each new project will be scrutinized for its ecological compatibility. Environmentally-friendly projects will be welcomed and have good chances of being approved. However, clear rules are lacking for the environmental and social evaluation of projects. Currently, the Government of Guyana is preparing to attract developers of SHP projects by means of public tendering processes for selected projects. The details of the process have yet to be defined.

In recent times, some projects such as the 165 MW Amaila Falls project and the 330 kW Kato project were pursued in an effort of implementation. None of the efforts of these projects have been successful yet.

There are no special financing mechanisms in place for renewable energy (RE) equipment or projects. There are several local commercial banks and branches of international banks in Guyana, none of which have experience in financing hydropower projects. The Caribbean Development Bank has recently set up a RE and energy efficiency section that seeks to foster increased lending in RE and energy efficiency projects. Several international donor projects from the German Corporation for International Cooperation, the IDB and the World Bank, can be approached for assistance to identify suitable project financing for larger projects. The Government of Guyana has repeatedly stated that they will grant preference to projects not requiring any sovereign guarantees.

The Kato project would have served for rural electrification in Region 8, and joint financing from the European Union and the Government of Guyana had been secured. However, the EU has withdrawn its financing offer after a first failed tender. This failure was due to a lack of qualified firms’ participation in the tender, and consequent elapsing of the time window for retendering.6 The Amaila Falls project was supposed to be implemented by foreign investors with financing by the Inter-American Development Bank (IDB). It was to supply the coastal area with electricity. The IDB has withdrawn its financing 296


and project development process. This results in uncertainty for developers regarding the application duration, application cost and likely outcomes. This applies for planning licenses, operating licenses, environmental permits and any other applicable permits. The Government of Guyana has introduced a web-based platform for investors8, but it is still in its development stage. Developers typically put forward high expectations regarding revenue and payback time, which the projects rarely are able to satisfy. On the other hand, the government also remains unwilling to grant sovereign guarantees, which would make it easier and cheaper for developers to mobilize financing. Here, both parties need to move from their standpoint towards realistic expectations.

The National Energy Policy of Guyana of 1994 contains an outlook from 1994 to 2004. In 1994, the policy already prescribed a mix of energy conservation and a preference for indigenous energy sources over imported fuels. The 1994 policy is outdated and requires modernization, considering the latest technological and other developments. A review of the policy is in progress. There are no feed-in tariffs for electricity generated from RE sources. RE developments are granted tax concessions for 10 years. The Electricity Sector Reform Act of 1998 mentions the use of renewable and alternative energy but does not explicitly promote the use thereof by creating preferences or other incentives.7


In the past, there has been no structured approach to developing the country’s hydropower resources. Instead of the government taking a proactive role in developing its resources by tendering concessions or generation capacity portfolios, the government responded to proposals brought forward on the initiative of individual developers. An alternative approach could be public tendering of project sites or concessions, or a generation portfolio with clearly outlined rules for participants in the bidding process. Recently, the cabinet has issued instructions to invite proposals from interested groups for RE supply for the Bartica community, Lethem (MocoMoco) and other identified communities. However, the degree to which the government will support the financing arrangements is not yet clear.

Technically, the great distances between hydropower sites and load centres and the difficult access into the Hinterland are the main barriers for the development of hydropower. In most cases, the construction of expensive access roads has to be included into the project budget. This jeopardizes the viability of projects. In addition to this, long transmission lines between project sites and load centres put a significant financial burden on the projects, particularly considering the ratio between line length and power demand. Hinterland villages face the problem of clustered settlements with large distances between villages and even individual houses, resulting in high costs for the connection of households to the electricity supply. The vast hydropower potential in Guyana requires strong administrative and procedural structures to channel development to a successful outcome.

Potential developers see themselves confronted with obscure processes for obtaining the various licenses instead of clear procedures and rules for the application

297

South America

2.3

Paraguay

2.3.9

Nathan Stedman, International Center on Small Hydro Power


6,552,518 1

Area

406,750 km2

Climate

The climate is sub-tropical in the Paraneña region and tropical in the Chaco region with an average temperature of 22°C. May to August is the winter season, with July being the coldest month (17°C). October to March is the summer season, with January being the warmest month (29°C). Day temperatures reaching 38°C are common.3

Topography

The two main regions in Paraguay are the Paraneña region, characterized by plateaus, rolling hills, and valleys, and the Chaco region, with an immense piedmont plain. The highest point is in the eastern mountains, close to Brazil, at 700 m.2

Rain pattern

Rainfall varies per region and per season. The Paraneña region receives an average of 1,270 mm of rain annually while some areas receive upwards of 1,800 mm. The Chaco region is considerably drier, with some areas receiving only 400 mm per annum.3


Río Paraguay and Río Paraná are the two main watercourses in the country. They define most of the borders and their basins provide all of the drainage. The major tributaries entering the Río Paraguay from the Paraneña region (such as the Río Apa, Río Aquidabán and Río Tebicuary) descend rapidly from their sources in the Paraná Plateau to the lower lands. The major tributaries of Rio Parana, which originate in Paraguayan territory, are the Acaray, Monday, Piratiy and Carapá. All of these possess important hydroelectric potential.2,3


generated that is not consumed domestically is exported to the markets in Brazil and Argentina (roughly 82 per cent).4

Paraguay is a country with a wealth of unique natural energy, particularly hydropower, and is regarded as one of the largest exporters of energy and the largest exporter of hydroelectricity in the world. Despite this, the country has domestic supply issues and is currently investing in improving the efficiency of the National Interconnected System (NIS), which covers roughly all of the territory.4

The Administracion Nacional de Electricidad (ANDE) is a state-owned utility and controls the electricity market. It operates more than 3,000 km of transmission lines in the NIS and 1,000 km of distribution lines. In addition to the ANDE network, there are also some private regional networks connected to the national grid.4 As of 2013, the national electrification rate was 99 per cent, with access in rural areas at roughly 98 per cent.8

FIGURE 1


Electricity generation in Paraguay (GWh) Hydropower Thermal power

The tariffs for the electricity sector in 2011 were at a national average of roughly US$0.07/kWh, nearly half

55,276.4 5.9

TABLE 1

Electricity tariffs in Paraguay

Source: IJHD5 Type

Total electricity generation in 2014 was 55.28 TWh, of which 99 per cent was from hydro and the rest from thermal.5 Installed capacity in 2014 was 8,834 MW. Only 24 MW was from thermal plants. Most of the capacity comes from the bi-nationally operated dams. 7,000 MW derive from the Itaipú dam jointly operated with Brazil, and 1,600 MW are from the Yacyretá dam jointly owned with Argentina (while 210 MW are from the solely Paraguayan owned Acaray dam).7 All of the electricity

Residential

8.64

Commercial

8.19

Industrial

5.75

General

6.53

Government

6.26

Street Lights

8.99

Source: Columbia University7

298

US$ cents/kWh

2.3

of what neighbouring countries’ tariffs were set at (US$0.14/kWh average).7 Tariffs are determined by the president of ANDE, as per Law 2199/03 (Article 16).4

South America

FIGURE 2

Electricity exports with and without RTA 50,000

During the period from 1999-2012, system losses in the NIS increased from 21 per cent to 30.9 per cent. The increase is attributable to the 220 kV lines in the network. Without 500 kV transmission lines, the current system is running over capacity. This results in frequent blackouts and shortages during inclement weather, which in turn can affect commercial activities by as much as 2 per cent of revenue. In 2011, there were 16 power cuts with an average duration of 10 hours.7

Exports without RTA

40,000

Exports with RTA

30,000 20,000 10,000

2039

2038

2037

2036

2035

2034

2033

2032

2031

2030

-20,000

2024

-10,000

Another cause of the increasing inefficiency of the NIS is the structure of the energy sector. The Vice Ministry of Mines and Energy decides the national energy strategy. However, this is often circumvented by the organizational and financial strength of ANDE, which can bypass the Ministry in the execution of ANDE’s Master Plan and other activities. Moreover, there is little incentive for ANDE to address the issue of system-wide losses, as any surplus in operation is transferred to the Ministry of Finance. Therefore, higher margins will not benefit the utility company.7

2014

0

Source: Columbia University7

electricity exports will cease by 2039 if generation does not continue to increase (Figure 2).7 Small hydropower sector overview and potential Paraguay has an enormous amount of hydropower potential, greatly exceeding the current installed capacity. The country has an estimated 130 TWh of hydropower potential, with technical and economically feasible potential near 101 TWh annually.7

ANDE’s 2012-2021 Master Plan outlined the strategy of upgrading the 220 kV transmission lines to 500 kV, due to the existing lines creating losses of an estimated US$226 million annually. The Master Plan will cost an estimated US$2.5 billion to complete. As of 2015, the government has secured 47 per cent of this from various international organizations (Inter-American Development Bank, Corporación Andina de Fomento and others).7

FIGURE 3

Hydropower in Paraguay, 2016 (MW) Hydropower Potential

Another development worth noting is the proposal by Rito Tinto Alcan (RTA) to invest a US$4 billion aluminium smelter in Paraguay. The smelter is expected to utilize some 1,100 MW of electricity, or nearly half of peak demand in 2011 (2,137 MW).7

LHP Installed

11,514 8,810

SHP Installed 0.0 SHP Potential N/A

Peak demand in 2020 is projected to reach 4,260-4,847 MW. By 2040, electricity demand could reach 59,713 GWh. Meanwhile, Argentina and Brazil are also expected to see a growth in demand. Some estimates have Brazil almost tripling demand by 2030.7

Sources: OLADE,4 Columbia University7

Currently there is no small hydropower (SHP) plant in operation, nor is there any proposed plan to install SHP. Feasibility studies performed and data published relate to hydropower in general, therefore data pertaining to SHP (less than 10 MW) is unavailable at present.

Several new hydropower projects have been planned by ANDE to meet the increased demand. The largest of these projects is the Corpus Christi dam, a joint project with Argentina that will have an installed capacity of 1,256 MW and is expected to be operational by 2030. With these new plants, generation is expected to reach 64,273 GWh by 2030 (compared to 55,282 in 2014).7

However, it can be deduced that there exists a real and untapped potential for SHP within the country. As demand continues to grow, the installation of new large hydropower plants will cover most of the increase in the short term, yet exports of hydro generated electricity will likely decrease. Adding SHP to the NIS could not only aid in domestic generation, but could potentially bring access to electricity to the remaining 2 per cent of the population that is lacking, while also allowing the government to continue the revenue flow from electricity exports.

Despite these efforts, if the RTA project is implemented, the country’s electricity exports are expected to decline over the next two decades, and cease by 2036 as demand surpasses supply. Even if the RTA project is not realized,

299



Regarding solar energy, Law 3557 approved an EU project to provide solar PV to 45 centres while Decree 6417 provided solar to 35 isolated communities.9

As 99 per cent of electricity generated in Paraguay is from hydropower, policies related to the NIS are in essence renewable energy (RE) policies. The ANDE 2012-2021 Master Plan to reduce losses in the NIS and increase efficiency also includes the addition of new hydropower plants.

Barriers to small hydropower development With the vast hydropower resources in the country, ANDE produces a surplus of electricity, which is exported to Brazil and Argentina. Currently there are no incentives for ANDE to alter the operation of the NIS and the generation of electricity. Although legislation allows for independent power producers and PPP within the energy sector, very few projects have been proposed. It is expected that independent power producers will not begin to enter the market until demand increases. However, SHP could be useful in times of unusual peaks, as well as reaching remote rural communities that still lack access to electricity. If the RTA project is realized, this could greatly impact revenue from exporting hydro produced electricity as well as domestic supply, SHP could help to offset those losses.

ANDE was the monopoly controller of the electricity market until 2006, when Law 3009/06 was adopted. The law opened the market to independent power producers to generate and transport electricity for domestic consumption or export. The law applies to all RE resources with the exception of hydropower plants larger than 2 MW. Despite the opening of the market, only a handful of proposals have been submitted currently. For any new projects, Law 2009/06 is also applicable as it established that access to the grid is non-discriminatory. Environmental Impact Assessments (EIA) are required by Law 294/93. Meanwhile Law 352/94 regulates protected areas.

300

2.3 South America

2.3.10 Peru Jorge Reyes and Leo Guerrero, University of Piura


31,155,263

Area

1,285,215 km2

Climate

Peru has a diverse climates and microclimates, including 28 of the 32 world climates. Such diversity is conditioned by the presence of the Andes Mountains, the cold Humbolt Current and El Niño. The temperature varies from below 0°C to 40°C.13

Topography

Peru is divided into three contrasting topographical regions: the coast, the highlands and the eastern rainforests, ranging from 0 m on the coast to 6,768 m above sea level in the highlands.13

Rain pattern

In the northern coast the summer rainfall total rarely exceeds 200 mm, except during the severe El Niño events, which can provoke major flooding with precipitations higher than 4,000 mm. In the central and southern coasts the rainfall is scarce with a total range between 10 mm and 150 mm.13


The main rivers in Peru are the Amazon, Madre de Dios, Putumayo, Napo, Maranon, Huallaga and Apurimac.13


FIGURE 1

Electricity generation by source in Peru (GWh)

The installed electrical capacity in Peru in 2015 was 12,251 MW; approximately 63 per cent of the total installed capacity was derived from thermal power, 34 per cent from hydropower, and 3 per cent was from solar and wind power (Figure 1).14 Total net electricity generation was estimated to be 48,066 GWh, with 23,300 GWh produced from hydropower.14 For the past ten years, generation has increased due to a greater use of natural gas (13 per cent increase annually).7

Thermal power

7,750

Hydropower Wind power

4,166 240

Solar power 96

Source: Ministerio de Energía y Minas7

The electricity sector in Peru has been shaped by public sector investment and the active participation of the private sector. In the early 1990s, the government issued a series of laws to promote private investment, highlighting the electricity sector as a national interest. The reform of the electricity sector started in 1992 with the promulgation of the Electricity Concessions Law. This law set the legal framework for the activities in the electricity sector. The general objective of this law is to promote a price system for greater economic efficiency by setting up a tariff for end-users. The tariff takes optimal usage of available energy resources into account. Generation, transmission and distribution utilities were unbundled as a result of this law. It also engaged the private sector in these commercial activities.2

Concessions Law. The Law for Efficient Generation Development aims to guarantee efficient electricity generation, reducing the vulnerability of the Peruvian electrical system to price volatility and long blackout periods. It also provides the assurance of a competitive electrical tariff to consumers. In addition, it establishes two new different types of transmission systems, one for supplementary transmission and one for guaranteed transmission. Sustainable rates of economic growth over the last decade have had a positive impact on poverty reduction. Private investment in the power sector in 2011 constituted 93.9 per cent of total investments, while the government invested 6.1 per cent. Private investment projects for generation accounted for 97.7 per cent of the total and 65.8 per cent for distribution. The public sector invested the remaining 34.2 per cent,

In 2006, the Law for Efficient Generation Development came into force to complement the Electricity 301


especially in rural electrification. In 2011, extreme poverty was at 6.3 per cent, and was particularly concentrated in rural Peru and more specifically the Sierra region.3 Studies have shown a strong correlation between poverty levels and access to basic services including electricity. The government is making significant efforts to raise access to electricity in rural areas under its social inclusion strategies. In this way, renewable energy (RE) technologies (especially solar, small hydro and biomass) could play an important role in satisfying energy requirements in rural Peru.4

FIGURE 2

Price for electricity by economic sector

“The Peruvian electricity market has matched the country’s economic growth and development. According to Ministry of Energy and Mines (MINEM), the total installed capacity has increased a 98 per cent in the last ten years with the electricity sector growing from 6,200 MW in 2005 to 12,251 MW in 2015.7 Demand has increased rapidly, but the expansion of grid infrastructure has in the past not matched the power demand requirements. This means that transmission is at present operating almost at maximum capacity, particularly in the country’s southern and northern corridors. This adds to the challenges of raising power generating capacity in these areas, which are expected to become the new poles of development. To relieve this situation, investments in grid infrastructure are now under way. While almost all regions are interconnected to SEIN, there is a clear heterogeneity in the regional electricity market. This situation is explained by the differences in the availability of generation sources, watersheds usable for the generation activity or access to pipelines transporting natural gas; the presence of SEIN transmission networks; location and heading of the main economic activities; population density or number of customers; among others.

Source: Ministry of Energy and Mines7

that public electricity is the most expensive, while the industrial sector uses the most electricity.7 The main problems with RE resources, is that the plants that operate with such technologies can create individual ecological problems. Additionally, there are a number of drawbacks that limit its economic cost competitiveness. These include: }} High investment costs: The capital cost for the technology is significant, while that for wind and solar is becoming more competitive. }} Variability: Solar and wind resources are unpredictable and cannot be dispatched, thus exhibit low load factor.7

The central part of the country has advantages over the aforementioned criteria, where sector development in the regions focus largely on installed capacity of hydro and thermal efficient generation (Camisea natural gas), which include areas such as Lima (4,847 MW), Huancavelica (1,024 MW), Callao (610 MW) and Junin (446 MW) in 2013. In contrast, regions in which the main economic activities take place in remote areas, such as mining in the Sierra and exploitation of hydrocarbons in the jungle, have a greater presence of auto-generation units. These differences are also expressed in the consumption regional power: in 2012, Lima accounted for 44.5 per cent of total sales, 56.6 per cent of sales was to regulated customers and 29 per cent of sales was to free customers. Regions with major mining and industrial operations, namely Arequipa, Ica, Moquegua and Ancash, have a concentration of the free customers outside the capital (Figure 2).

Peru has a total electrification rate of 90.3 per cent and a rural electrification rate of 70.2 per cent.7 The National Rural Electrification Plan 2013-2022 provides strategic direction to provide access to electricity to 6.2 million people by 2022. There are efforts to increase access to energy via auctions for solar photovoltaic systems, grid extension, mini-grids with hydro, solar and wind.4 FIGURE 3

SHP capacities 2013-2016 in Peru (MW) Potential 2016 2013


The government regulates transmission and distribution tariffs. In 2014, prices for electricity averaged from US$0.072/kWh to US$0.13/kWh. These tariffs vary among different economic sectors. Figure 3 demonstrates

1,600 N/A 391 351

Source: WSHPDR 2013,12 the World Bank Group5 Note: The comparison is between data from WSHPDR 2013 and WSHPDR 2016. 302

Small hydropower sector overview and potential

allowable capital costs increase to around US$1,000/ kW. Nevertheless, greenfield SHP projects cannot be built at such low capital costs.6 Unlocking the significant potential of SHP in Peru would require either the removal of the low price for natural gas from Camisea or a preferential tariff for SHP that reflects the economic opportunity cost of gas powered generation. Using a generation price based on the economic opportunity cost of gas generation of US$0.056/kWh and the same assumptions for FIRR, loan tenor and load factor, the allowable capital cost for SHP increases to US$1.4/kW. This is a level that would make many SHP plants financially viable in Peru, even with recent increases in hydro construction costs.6

Peru has significant small hydropower potential, defined as plants with capacity less than 20 MW, which is conservatively estimated at over 1,600 MW. Unfortunately, there is no solid basis for estimating the technical potential of SHP in Peru because of the lack of inventories of such resources. The total installed capacity for all SHP plants, including grid connected and isolated plants under 20 MW is 391 MW,15 with 251.1 MW connected to the national grid.16 In 2015, the installed capacity for grid connected plants up to 10 MW was 112.8 MW.16 Between the 2013 and 2016 World Small Hydropower Development Reports, installed capacity up to 20 MW has increased, while potential has been reassessed due to more conservative estimates of economically feasible potential.

Renewable energy policy The regulatory framework for the promotion of renewable energy has evolved since the enactment of the Electricity Concessions Law and its Regulations (1993, 1994), which created the electricity market and set its institutional arrangement. The Law on Efficient Generation (2006) promotes long tenders and contract terms as a means to support investment in large-scale generation (large hydro and other conventional technologies). Legislative Decree No. 1002 (2008) declares, out of national interest and public necessity, the development of electricity generation from renewable resources.8 It establishes a national priority the promotion of renewable energies; defining Renewable Energy Resources (RER) as the sources of non-conventional renewable energy: solar, wind, geothermal, biomass, and hydropower up to 20 MW (Hydro RER).

MINEM, supported by the Advisory Committee, have set a goal of preparing a proposal to institutionalize the process of energy planning in Peru. MINEM has proposed three central hypotheses. First, it is considered that the national economy will grow by an average 4.5 per cent annually and in a more optimistic scenario, 6.5 per cent. This is a situation that would confirm that the reserves and infrastructure are sufficient to continue to endure high rates of growth. Secondly, it is postulated that the level of energy prices in the domestic market will follow the trends in global energy prices, with the exception of gas. The price will reflect current contractual conditions and incorporate more lots with prices to match the offer and domestic demand.4 Thirdly, MINEM proposed the availability of resources, based on the fact that currently production has reserves and untapped resources of hydropower, natural gas and non-conventional RE, all sources are suitable and sustainable for the expected economic growth.7

The Government promotes electricity sales of RER through auction, posing as the current target level of penetration RER, excluding small hydropower projects. The main incentives offered are: the priority access to the office of System Economic Operation Committee (COES) and purchase of energy produced; priority access to transmission and distribution networks; and stable long term rates determined by auction.9 Auction Bases are approved by the Ministry of Energy and Mines; the Supervisory Commission for Investment in the Energy and Mining Sector (OSINERGMIN) leads the auction, fixes the maximum prices and determines the premiums through annual assessments.

The most fundamental constraint to developing the country’s hydro potential has been the low tariff faced by generators, which is a consequence of the low domestic price of natural gas. Almost all new power generation installed in Peru during the last decade has been based on low priced natural gas from the Camisea Field. The price of Camisea gas delivered to plants near Lima is estimated at US$2.15 per BTU, which means an average price for gas-based generation of around US$0.035/kWh. Given that Peru will shortly become an LNG exporter, the opportunity cost of natural gas is now linked to international prices.5

Legislation on small hydropower It has been difficult to attract financial support for green energy projects. To rectify this, the MINEM approved some benefits for SHP projects under 10 MW installed capacity:6 }} All of the permitting process is carried out at the regional level with local authorities, where the project is located; }} No Environmental Impact Study (EIA) is required. It is sufficient to file a non-environmental impact commitment document.7

Development of SHP has not been financially viable because the financial cost of generation was set by the cost of gas-based generation at a lower price for natural gas from Camisea. At an average price for gasbased generation of US$0.035/kWh, a 17.5 per cent financial rate of return (FIRR) on equity, a 10-year loan period and a 70 per cent load factor, the maximum capital cost that is financially viable for a hydro project is around US$850/kW. When carbon finance and the increasing cost of oil are taken into consideration, the 303

South America

2.3


The benefits of SHP projects in development and under construction are such that even some of the bigger power generation companies are investing in them in Peru. In some cases, larger companies even buy them as greenfield projects at the permitting stage or by acquiring hydropower power plants in production. They proceed to invest additional funds, earmarked for improvements. In some cases, water storage facilities are added to the projects to enhance production. This is done without altering water use permits and by seeking support from the local stakeholders, who have already seen first-hand the benefits of having a local power plant operating and know that they can also benefit from the water regulation facility.3

in the RE sector has seen an increase, there are some barriers to developing new RE projects, including SHP: }} Investment costs: All have different costs and depend on technology and resources. }} Operation and maintenance cost: All energy resources require moderate human resources training. }} Transport and construction infrastructure for most energy resources is limited. }} Environmental: Most RE projects have at least minimal to moderate environmental impact during construction phases. }} Financial: Bankers’ limited knowledge of the RE market and profitability, credit officers’ limited knowledge about RE project evaluation and regulations. Banks may need external technical support to assess RE investment projects and technical assistance component is required to credit lines.11

Barriers to small hydropower development Peru is rich with RE resources: solar, hydro, biomass, biogas, wind, and geothermal, but only a small fraction of this potential is currently used.10 While investment

304

2.3.11 Uruguay Martin Scarone, Ministerio de Industria, Energia y Mineria


3,407,0001

Area

176,215 km2

Climate

Uruguay has a temperate climate with cold winters (June to September) and hot summers (November to March). The average temperature in January is 24°C. In July, it is 10°C.1

Topography

The landscape features mostly rolling plains and low hill ranges (cuchillas) with fertile coastal lowland. The highest elevation is roughly 500 m.1

Rain pattern

Uruguay has a rainy climate without a dry season. The rains are characterized by their extreme irregularity and annual variability. The annual precipitation varies between 1,100 mm in the south of the country and 1,600 mm in the north.1


Uruguay is surrounded by rivers on three sides. In the north the Cuareim River forms its border with Brazil for more than 280 km. On the southern border is the Río de la Plata, the large estuary formed by the union of the Uruguay and Paraná Rivers. The Uruguay River, from which the country took its name, forms the western boundary and is by far the largest and most picturesque of the country’s rivers.1


consists of 770 km of 500 kV lines that are connected from Salto Grande through the Rincon del Bonte dam to the main consumer centre in Montevideo. The national grid also includes a branch to San Carlos City, located in the south-east of the country. There are 3,549 km of 150 kV lines connecting the power generation plants with almost all the major cities and main load centres.3

In 2014, the energy generated in Uruguay was approximately 13,008 GWh. Of the total generated, 3,125 GWh came from hydropower plants.3 In 2014, the installed capacity was 1,538 MW of hydropower plants, 1,696 MW of thermal plants that run on fossils fuels and biomass, 481 MW of wind energy, and almost 4 MW of solar energy. Regarding the installed capacity by energy source, the most significant share in 2014 corresponded to renewable energy with 66 per cent (hydropower, biomass, wind, solar), whereas non-renewable energy accounted for 34 per cent of total capacity (gas oil, fuel oil, gas natural).2

In Uruguay, electricity generation is open and every generator can connect with the public electric grid. Private generation companies must sign contracts with the electricity utility Administración Nacional de Usinas y Trasmisiones Eléctricas (UTE) or sell at the spot price. UTE is the only distribution and transmission operator in Uruguay. The electrification rate in Uruguay is 99 per cent. The average household electricity tariff is US$0.19 for 600 kWh per month.4

FIGURE 1

Installed capacity by sources in Uruguay in 2013 (MW) Hydropower


1,538

Thermal power

1,696

Source: Secretary of Energy2

The definition of small hydropower (SHP) in Uruguay is plants with an installed capacity up to 50 MW. Mini is defined as 100-1,000 kW, micro is defined as less than 100 kW and pico less than 5 kW.9 SHP installed capacity remains 0 MW, while potential is 232 MW.

The consumption of energy in 2014 was approximately 10,350 GWh.10 In 2013, there was a 51 per cent increase in hydropower consumption of electricity production, in comparison to 2012, while fossils fuels decreased 50 per cent (both fuel and oil).2 The electric grid in Uruguay

Regarding SHP potential, there are three kinds of sectors that have been studied: SHP sites only for generation, SHP sites that can be added to a dam used for irrigation and hydropower sites that can be added to a dam that can be used for irrigation but have not yet been developed.

Wind power Solar power

481 4

305

South America

2.3



FIGURE 2

SHP capacities 2013-2016 in Uruguay (MW) Potential 2016 2013

In the Uruguayan 2005-2030 National Energy Policy, the government has set a RE goal of 50 per cent native renewable sources in its primary energy matrix by 2015. Among other measures to accomplish this, nontraditional RE sources (wind, biomass residues and micro-hydraulic generation) will contribute 15 per cent of the total generation. It has also set up the target of reaching 90 per cent of RE in its electric matrix by 2030.4

232 110

capacity Installed

0

capacity

0

Sources: WSHPDR 2013,8 IMFIA7


In the case of small hydropower sites only for generation, the study was carried in all the rivers except for the rivers on the borders and the Black River. Up to 70 feasible sites were identified, all of which would not cause environmental damage or draughts in the surrounding areas. These 70 sites have a potential capacity of 232 MW. From these 70 sites, five were selected in order to study installed capacity, energy generation, environmental impact and economic and financial feasibility. From these five projects, only the projects of Arerengua, Arapey and Yerbal were determined to be economically feasible (including the price of the land) with the energy prices that are being paid currently (Table 1).7

In 2007, the Government of Uruguay offered 20 MW to be added to the grid from SHP, but no private investors applied. The government still plans to develop SHP to promote rural development and to increase the number of irrigation dams. Article 47 of the Uruguayan Constitution outlines the utilization of water and defines the right to water and sanitation as a fundamental human right. In accordance with the requirements established by Law No. 16466 of Environmental Impact (1994) and enabling regulations established in regulatory code No. 349/005 (Evaluation of Environmental Impact), an environmental permit must be requested for hydropower projects with capacities exceeding 10 MW or water flows higher than 0.5 m3/s. Law No. 16 906 on the Promotion and Protection of Investments provides a framework for encouraging investments in the country, upon approval by the designated commission. Enabling regulation No. 354/009 promotes the generation of electricity from non-traditional renewable sources and grants the exemption of a significant percentage of the income tax for electric generating companies at the start of business, with subsequent reductions in the following years. Decree 2/2012 establishes tax benefits that may be granted (income tax deduction according to amount of investment, tax exemptions, VAT returns).6

TABLE 1

Potential studied SHP sites in Uruguay River

Potential capacity (MW)

Capacity factor (per cent)

Estimated energy generation per year (MWh)

Arapey 80 m

7.00

62

38.69

Arapey 130 m

3.70

62

19.69

Yerbal 88 m

2.60

74

16.59

Arerungua 90 m

8.90

68

52.35

Barriers to small hydropower development Currently there are no SHP plants connected to the national grid, therefore, the approval process and duration as well as the associated risks with lengthy investment periods related to SHP projects are relatively unknown. As no projects have yet been completed, there is a fundamental gap of experience and knowledge between planning and implementation, operation and maintenance for SHP.

Source: IMFIA7

From the more of 1,331 irrigation dams already built in Uruguay, 20 damns were selected to carry out a generation viability studies. Moreover, economic and technical feasibility studies were carried out. The average capacity for each damn is 100 kW.

306

2.4 Northern America Johan G. Grijsen, Hydrology and Climate Risk Assessment


to a sub-arctic or polar climate in Alaska, a semi-arid climate in the Great Plains west of the Mississippi River, arid conditions in the Southwest and a temperate climate elsewhere. Annual rainfall varies between over 1,600 mm in Hawaii and just 241 mm in Nevada.5 The country’s topography is dominated by large central plains with hills and low mountains in the east and higher mountains in the west. The nation’s largest river systems based on flow volume are the Columbia River in the north-west and the Mississippi River in the south-east.

North America comprises five countries and territories: Bermuda, Canada, Greenland, Saint Pierre and Miquelon, and the United States of America (USA). Of these, only Canada and the USA are endowed with large small hydropower (SHP) potential. Canada, Greenland and the USA cover exceptionally large swaths of land with varying climates. FIGURE 1


FIGURE 2

Net change in installed capacity of SHP (MW) for Northern America, 2013-2016 185 USA 52%

Canada 48%

Greenland 0%

28 9

Source: WSHPDR 20167 Canada

Greenland is largely covered by an icecap of up to 3,200 m thick, with an estimated volume of 1.7 million km3 (2,166,086 km2 or 81 per cent of its total land area is covered by ice).1 The icecap covers all but a narrow, mountainous, barren and rocky coast, in an arctic to subarctic climate. The Canadian territory covers 9,985,000 km2 and possesses climate conditions ranging from mild temperate on the west coast to sub-arctic and arctic in the north of the country.2 The interior provinces are dominated by the relatively flat Great Plains and Canadian Shield, bordered by mountain ranges on the western and eastern sides of the country. Nine per cent of the territory consists of 8,500 rivers and 2 million lakes.3 The USA, with its large size (9,826,675 km2) and huge geographic variety,4 includes most climate types, varying from a tropical climate in Hawaii and Florida

Greenland

USA

Sources: WSHPDR 2013,9 WSHPDR 20167 Note: The comparison is between data from WSHPDR 2013 and WSHPDR 2016.

Around 60 per cent of all electrical energy (GWh) generated in Canada (in its western and eastern provinces with mountain ranges) and in Greenland is hydro-energy (Table 1). On the other hand, the USA depends predominantly on fossil fuels (coal and natural gas) and nuclear energy (85.5 per cent). Non-hydro renewable energy (RE) resources provide 6.9 per cent while hydropower provides 6.2 per cent of the total energy.6 Recently, natural gas generation has been growing rapidly, along with wind and solar energy.14 Hydropower, as a percentage of total electricity generation, has been relatively stable in the USA since 2007.8

TABLE 1

Overview of countries in Northern America (+ % change from 2013) Country*

Population Dec 2015 (million)

Rural population (%)

Electrification access 2015 (%)


Electrical generation (GWh/year)

36 (+2%)

19

100

127,800 (–2%)

610,700 (+4%)

Greenland

0.058 (+4%)

14

100

140 (0%)

541 (+16%)

91.3 (+32%)

317 (+13%)

USA

322.8 (+2%)

14

100 1,003,000 (–4%)

4,093,100 (–1%)

80,000 (+2%)

252,580 (–2%)

358.858 (+2%)

14.5

100

4,704,341 (0%)

155,891.3 (+2%)

639,997 (+6%)

Canada

Total

1,130,940 (–3%)

Source: Various7,9,10,11,12,13,14 307



75,800 (+1%) 387,100 (+11%)


Small hydropower definition

TABLE 3

SHP in Northern America

The definition of SHP in Canada is up to 50 MW of generating capacity.15 According to some sources, this is 10 MW to 15 MW. In the USA, there is no widely accepted definition, but for this report the threshold is set at an installed capacity of 10 MW, i.e. the largest capacity qualifying for a SHP exemption at the Federal Energy Regulatory Commission of the USA. In Greenland the threshold is also 10 MW, in accordance with the standard in Denmark (Table 2).16

Country Canada (up to 10 MW)

—

1,113

Canada (up to 50 MW)

15,000

3,400

183

9

6,366

3,676

7,599

4,735

USA (up to 10 MW) Total (up to 10 MW) Source: WSHPDR 2016

Classification of SHP in Northern America Country*

Small HP

Canada

up to 50 MW

Greenland

up to 10 MW

Source: WSHPDR 2016


Greenland (up to 10 MW)

TABLE 2

USA


7

The Department of Nature, Energy and Climate of Greenland supports development projects regarding RE,21 energy efficiency and climate. Government investment has led to 50 per cent of energy supplies now being derived from RE resources.

up to 10 MW

In Canada, regulatory and policy control over the electricity industry is primarily vested in provincial governments, which own, inter alia, 87 per cent of the hydro generation assets.22 Even though each province has its own electricity policy and regulatory agency, leading to disparate electricity tariffs between provinces relying primarily on hydropower and those relying mainly on thermal energy, Canadians enjoy the lowest overall residential energy prices out of all the countries in the Organisation for Economic Cooperation and Development.23 The Canadian Government aims to develop a green energy sector that will help to meet emission targets, including the doubling of non-hydro renewable sources and the retirement of coal-fired power plants.24

7

Regional small hydropower overview and renewable energy policy Electricity supply in Greenland is divided over many isolated systems. There is no main grid due to the large distances between various locations and many small and dispersed settlements. SHP would be an adequate technology for isolated operations in Greenland. The inland ice is the world’s second largest freshwater reservoir and represents an ideal potential for hydropower development. However, to date, only about 5 per cent of Greenland’s small and large hydropower potential has been developed. The small degree of utilization may be caused by the low level of electricity consumption. However, with the launching of new mining projects, a greater portion of the hydropower potential might be utilized in the future. Greenland aims to replace its diesel power plants with hydropower projects running on glacial melt water.

In the USA, more than 3,000 private and public electric utilities operate across the country, historically within exclusive franchise service territories and subject to a high degree of governmental regulation. The USA Department of Energy (DOE) is driving research and development efforts for SHP as part of its Water Power Program, which focuses on increasing generating capacity and efficiency at existing hydropower facilities as well as adding hydropower generating capacity to existing non-powered dams. In 2014, the DOE announced the development of a long-range National Hydropower Vision, which will establish the analytical basis for a future roadmap towards a new era of growth in hydropower, including SHP. Various state governments have developed policy and programme efforts to support SHP, including hydropower resource assessments, grant and loan funding, and efforts to improve hydropower licensing coordination between state and federal environmental agencies. Various federal and state financing mechanisms are being developed to support SHP. Many states have some form of Net Energy Metering requirement in effect, providing a strong economic incentive for distributed RE generation, including SHP.25 The DOE also supports the National Hydropower Asset Assessment Program, an integrated water-infrastructure

The installed capacity of SHP (up to 50 MW) in Canada is 3.4 GW (4.4 per cent of total installed hydro capacity and 2.6 per cent of the total generating capacity),17,18 including 1 GW plants with up to 10 MW capacity. The economically feasible potential (including the existing SHP plants) is estimated to be about 15 GW (up to 50 MW), indicating that 23 per cent of this potential has already been developed. Only up to 15 per cent of the technically feasible SHP locations are economically feasible. Most of the installed hydropower capacity in the USA comes from large projects built between 1930 and 1970. The total hydropower generating capacity has been relatively flat since 2000 with less than a 2 per cent total increase during that time. The installed capacity of SHP (up to 10 MW) is 3.7 GW (4.6 per cent of total installed hydro capacity and only 0.4 per cent of the total generating capacity). The economically feasible but as yet untapped SHP potential is estimated to be approximately 2.7 GW (Table 3).9,19 308

information platform for the management and policy planning of sustainable hydroelectricity generation.

}} SHP is normally uneconomical and requires some form of inducement (feed-in tariffs or standing offers). }} The generation of SHP is normally purchased by provincial utilities through power purchase agreements that are very competitive, resulting in a low profit margin. }} Significant environmental and regulatory requirements are still required. }} High costs of interconnection in some jurisdictions.

Many states in the USA have adopted policies to encourage RE development, most prominently the adoption of a Renewables Portfolio Standard (RPS). An RPS is a marketbased policy that requires electric utilities and other retail electricity suppliers to supply a minimum percentage of their electricity sales from eligible RE sources, e.g. a 50 per cent target in California by 2030 and a 75 per cent target in Vermont by 2032.26

Despite significant recent progress in the USA, SHP developers still face barriers, including:7 }} Lack of comprehensive information regarding suitable sites, also conduit hydropower opportunities, including canals and pipelines; }} Owners of potential conduit hydropower sites typically show risk aversion to new technology; }} Lack of standardized technology for conduit hydropower projects, with associated high customengineering costs; }} Notwithstanding successful recent federal reform efforts, there remain significant permitting challenges associated with SHP development; }} Uncertainty in the cost, timing and technical requirements of grid interconnection can be challenging for SHP and other distributed energy resources; }} Unfamiliarity from electrical inspectors due to the fact that few SHP projects are installed each year, making it difficult to secure electrical inspection approval; }} State and local regulatory challenges, including regulatory issues associated with water quality certifications and environmental requirements; }} Financing challenges due to high upfront costs, lengthy permitting processes for existing dam projects, variable hydrology, and other project risks.

Barriers to SHP development In Greenland, barriers to SHP development are experienced especially in the more scarcely populated areas. Many smaller towns and settlements are still dependent on an energy supply based on fossil fuels, since transporting electricity across long distances is associated with great costs and losses.28 Supply and transportation is costly and associated with heavy fuel consumption. Many towns and settlements are not connected by road, so travel between them has to take place either by boat, plane or helicopter. This is especially energy intensive.28 In Canada, the success of hydropower development depends on transboundary cooperation between upstream and downstream jurisdictions.29 The fragmented approach in almost all aspects of the energy sector (due to the provinces’ own electricity policy and RE targets) has in some cases led to its underperformance. In recognition of Aboriginal rights, native communities (the First Nations) are now being included as hydropower project partners. From a technical perspective, unpredictable ice formations at hydropower generators can be a particular challenge, potentially causing damage to other infrastructure, such as transport passages and bridges. Overall, the situation in Canada is dynamic, but many anticipate that a hydro renaissance is possible, with hydro resources playing a larger role in the quest for a more renewable, sustainable, stable and economical power system. Other barriers in Canada include:

309

Northern America

2.3

2.4.1

Canada Bryan Karney, Sharon Mandair and Samiha Tahseen, University of Toronto


35,700,0001

Area

9,985,000 km2

Climate

The climate varies greatly throughout the country, with interior regions such as the prairies (e.g. Manitoba, Alberta) experiencing more extreme temperatures. More temperate weather is common along the west coast within the province of British Columbia. Average summer temperatures from July to August range from 20°C to 27°C, while average winter temperatures from January to February range from –30°C to 0°C.2

Topography

The western part of the country has a mountain range that stretches through British Columbia and Alberta and down into the USA. In the northern part of this mountain range is Mount Logan, the highest point, at 5,959 m above sea level.3 The interior provinces are dominated by the Great Plains and the Canadian Shield, which are relatively flat. Towards the Atlantic coast is the geologically older Appalachian mountain range.4

Rain pattern

In the coastal cities, rainfall is 1,100 mm to 1,500 mm per year. In the interior cities it is 400 mm to 500 mm and in the northern regions it is 250 mm to 300 mm. Snowfall in the east coast can reach 300 cm and in the west coast it is 50 cm.5


Nine per cent of the total area of Canada is made up of 8,500 rivers and 2 million lakes.6 There are 12 rivers over 1,000 km long, the longest being the Mackenzie River (4,250 km), which drains into the Arctic.7 By discharge, the St Lawrence River is the largest river, with an average flow of 9,850 m3/sec.5


Alberta, Saskatchewan, Nova Scotia and New Brunswick depend heavily on fossil fuel. Ontario mostly depends on nuclear energy and hydropower. Among other renewable sources, wind accounts for 4.2 per cent of the total installed capacity, but has shown rapid growth over the past decades.11 Table 1 shows the existing generation capacity while Figure 3 illustrates the generation mix within major Canadian provinces.


The energy sector in Canada has an installed capacity of 127.8 GW (Figure 1), providing electricity to the entire population.9,10 In 2015, electricity generation was 593.77 TWh and consumption was 534.31 TWh (Figure 2). The major sources of energy across Canada are hydro (59.3 per cent), fossil fuels (24.1 per cent) and nuclear (10.5 per cent) which make up the majority of the total generation. The rest comes from a combination of wind, solar and tidal.9

Canada has a predominately north–south transmission network that connects most strongly to the USA.13 The transmission grid, apart from facilitating interprovincial trade, plays a key role in exporting electricity to the US market. Overall, Canada exports 7-9 per cent of its power generation and has traditionally been a net electricity exporter.14

The energy mix varies substantially, with British Columbia, Manitoba, Québec, Newfoundland and Labrador’s energy generated predominantly from hydroelectric sources. FIGURE 1

In Canada, regulatory and policy control over the electricity industry are primarily vested provincially. Provincial governments have ownership over generation assets, especially hydro, nuclear, and conventional steam plants. Generation and transmission are often provided through a public entity (e.g. British Columbia, Québec, Manitoba) or produced by a competitive, bidding process (e.g. Alberta, Ontario).14 The private sector nevertheless, in all provinces, owns an important share of the generation capacity.

Installed electricity capacity (GW) Hydropower

75.8 30.8

Fossil fuel Nuclear power Others

13.4 7.8

Source: Canadian Electricity Association (2014)9

310

TABLE 1

Total electricity generation by provinces in 2013 (TWh) Sources

B.C.

Alta.

Sask.

Man.

Ont.

Que.

N.S.

N.B.

N.L.

P.E.I.

58.2

2.2

4.5

35.4

36.7

204.9

1.1

3.3

40.75

0

0

0

0

0

93.1

0

0

3.9

0

0

Conventional steam

4.5

44.87

17.2

0.1

7.1

0.9

8.5

4.4

1

0

Internal combustion

0.1

0.1

~0

~0

0.8

0.3

0

0

0.1

0

Combustion turbine

Hydro Nuclear

1.2

13.7

0.7

~0

9.38

0.4

0.5

1.9

0.3

0

Wind

0

2.3

0.7

0.4

3.3

0.7

0.14

0.6

0.1

0.5

Solar

0

0

0

0

0.24

0

0

0

0

0

64.1

63.6

23.1

35.9

149.8

206.8

10.5

13.9

42.1

0.9

Total

Source: Key Canadian Electricity Statistics (2014)12

depends on the provincial market structure. Ontario, Alberta and New Brunswick have Independent System Operators. In most other provinces, the operator also owns transmission assets.11

FIGURE 2

Electricity generation and consumption, 2012-2015 (TWh) 65 60 55 50 45 40 35 30 25 20 Dec.2012

At the federal level, the stated plan has been to develop a green energy sector that, apart from having employment benefits, will help to meet the emission targets. The government has projects to double nonhydro renewable sources as well as retire coal-fired power plants.16 With a recent change in the Federal Dec.2013 Dec. 2014 Dec. 2015 Government in October 2015, it will be interesting to Electricity generation Electricity consumption see how national goals will evolve. Ontario has already eliminated coal generation, and other provinces (Alberta and Saskatchewan in particular) face pending Source: Statistics Canada33 federal regulations. Several provinces pursue demandside management programmes and are leaning towards FIGURE 3 smart grid investments to support the behavioural Electricity generation map by source in Canada shifts. Some have taken steps in that direction by installing smart meters (e.g. Ontario).17

Biomass Hydroelectric Nuclear Wind Solar Fossil fuel

Canadians enjoy some of the lowest residential energy prices among Organization for Economic Cooperation and Development countries.18 Each province has its own electricity policy and regulatory agency, leading to disparate electricity tariffs. Québec, BC, Manitoba, and Newfoundland and Labrador produce 56 per cent of Canadian electricity almost exclusively from hydropower plants.19 Given the low operational cost of their generation portfolio, these provinces have the lowest electricity rates in Canada. The lack of hydropower potential for Alberta, Ontario and New Brunswick led to a reliance on thermal generation (fossil fuel and nuclear), leading to higher production costs. Provinces have separate regulation entities for reviewing and approving plans. In a majority of the provinces, utilities are operating as regulated monopolies with the exception of Ontario and Alberta, which have at least partly deregulated their electric industry over the last decade. A few key responsibilities are still handled by the Federal Government such as issuing permits for inter-provincial and international power lines, assessment for major hydroelectric developments, etc.20 The Federal Government retains some oversight and permit responsibilities on issues relating to fisheries.

Tidal

Source: Canadian Electricity Association32

The national transmission grid is a collection of relatively loosely connected provincial grids that are linked together through varying levels of intertie capacity. British Columbia, Manitoba, Ontario and Québec have the largest external connections to the regional USA markets. The system operator coordinates power flows in real time, and the entity that acts as system operator 311

Northern America

2.3



aboriginal participation and on-peak generation.27 Standing Offer Program in BC offers CA$0.09139/kWh (US$0.06/kWh).25

Natural Resources Canada (2007) defines small hydropower (SHP) as 50 MW of generating capacity.21 However, in the absence of an international convention, a 10-15 MW limit can also be used. The installed capacity of SHP in Canada is 3,400 MW (up to 50 MW) while the potential is estimated to be 15,000 MW indicating that 23 per cent has been developed. Between the World Small Hydropower Development Report (WSHPDR) 2013 and WSHPDR 2016, installed capacity for SHP up to 50 MW has increased by 1 per cent. For plants up to 10 MW, it has increased by 6 per cent, leading to a significant increase in estimated potential (Figures 4 and 5).

Renewable energy policy Due to the provincial dominance over the electricity sector, there is a large variation in incentives provided for clean, renewable development across different provinces. The schemes are also subjected to frequent amendments and adjustments. A brief description of some of these renewable policy measures are discussed below: }} Clean energy fund An Economic Action Plan that includes the Clean Energy Fund, a five-year, CA$795 million (US$558.6 million) programme to support clean energy technology research.28 }} Standard offer programmes The qualifying projects are subjected to a capacity restriction and required to connect to the distribution. The programme usually guarantees a sustained tariff for a period of 20 years. }} FIT programmes The programme assures priority grid connection and long-term stable prices (40 years for hydropower and 20 years for others) for electricity generated from renewable resources, subjected to capacity restrictions. At present, FIT programmes are available only in Ontario. Within the first two years, it has extended Ontario’s renewable capacity by 4,600 MW.29 }} Net metering Net metering allows generators to send the excess electricity, after their own use, to the grid. The credit received in return can be applied against future electricity use or at times, can be subjected to annual monetary returns. Net metering programmes are available in almost every province across Canada. }} Requests for proposal A request for proposal (RFP) usually involves a specific target announced by the government that needs to be executed by the monopoly utility in particular jurisdiction. The proponents bid according to a fixed delivery schedule and are eligible to get a defined tariff rates which may or may not be subjected to escalation.

FIGURE 4

SHP capacities 2013-2016 in Canada (MW) Potential 2016 2013

15,000

capacity

7,500

Installed

3,400 3,372

capacity

Sources: Statistics Canada,34 WSHPDR 201331 Note: Data for SHP up to 50 MW. FIGURE 5

Installed SHP capacity

10

208

Source: StreamMap, WSHPDR 2013, Sea and water authority, Kling, J. 11

21

13

of these installations. All stakeholders acknowledge the input to the energy system that hydropower makes but due to the old permits linked to many of the existing SHP stations, environmental organizations are not actively pushing for SHP as a better alternative to large hydropower. Environmental organizations such as Naturskyddsföreningen (Swedish Society for Nature Conservation) actively support environmental improvements in existing hydropower through its ecolabelling scheme, Bra Miljöval (Good Environmental Choice) and the environmental funds generated from the purchase of the labelled products.

23

market is a technology neutral instrument and there are no targets set specifically for new hydropower capacity in Sweden. From 2007 onwards, not many new plants have been built but refurbishment is being made, including upgrading larger SHP plants. But typically there is a higher cost per produced kWh as compared to large hydropower and the economic incentives are weak (especially for the large number of hydropower stations with installed capacity of less than 1.5 MW) to undertake modernizations of equipment or improve the environmental status of the affected water. Barriers to small hydropower development

Renewable energy policy The EU Renewable Directive 2009/28/EC (by 2020) has not resulted in any changes for SHP in Sweden. The EU Water Framework Directive is implemented under Swedish Law and the effect of the directive in reality will only be known after a Swedish court ruling.

In 2009, Sweden surpassed its EU Renewable Energy Directive 2020 renewable energy targets of 49 per cent share of final energy from renewable sources by 2020, achieving 50.2 per cent.17 In 2013 the share of renewable energy was 52.1 per cent.18 A market-based support system for renewable electricity production has been in place in the form of electricity certificates since 2003. The objective of the Swedish electricity certificate system is to increase the production of renewable electricity by 25 TWh by 2020. Since 1 January 2012, Sweden and Norway have a common electricity certificate market. Over the period until 2020, the two countries aim to increase their production of electricity from renewable energy sources by 28.4 TWh. The joint market permits trading in both Swedish and Norwegian certificates and receiving certificates for renewable electricity production in either country. There are no feed-in tariffs (FITs) or other direct support structures for SHP in Sweden.

The water concessions that are linked to the hydropower stations in operation today are in most cases based on older legislation. For example more than 90 per cent of all hydropower concessions were granted prior to 1983 and thus the concession rights are based on the Water Law of 1918 or even older legislation.19 There are direct costs involved in getting new concession rights that are in line with modern legislation. Apart from putting together the application there might be requirements to alter and modify the hydropower station. In addition, another requirement might be that hydropower plants are required to spill water corresponding to 5 per cent of the total water flow resulting in reduced electricity production.20 The motivation behind this is to improve the ecological status of rivers.

Legislation on small hydropower There is the potential to increase production in SHP in Sweden by improving efficiency in existing hydropower stations. Many older SHP plants are now being phased out of the Swedish green certificate support scheme. To be entitled to operate for the next 15 years, it is required that the plants must undergo total refurbishment of all essential parts. As refurbishment is very expensive and not always economically viable for smaller plants (approximately less than 100 kW), many SHP stations could face an uncertain future.19 The green certificate

Notes i This report is a revised and updated version based upon the 2012 report by Small Hydropower Association, Stream Map ii There are 16 Environmental Objectives. Flourishing Lakes and Streams is one of the objectives linked to hydropower as these installations will affect biodiversity, hydro morphology and other environmental parameters in lakes and watercourses.16

536

4.2.10 United Kingdom of Great Britain and Northern Ireland Gabrial Anandarajah, UCL Energy Institute


64,596,8001

Area

248,531.52 km2

Climate

The climate is temperate, with the Gulf Stream ensuring mild, maritime influenced weather. Temperatures range from not much lower than 0°C in the winter months between December and February and not much higher than 32°C in the summer months between June and August. The temperatures in Scotland are generally lower than that in the other parts of the country.4

Topography

The United Kingdom is divided into hilly regions of the north, west and south-west and low plains of the east and south-east. The eastern coast of East Anglia is very low lying, much of it lower than 5 m above sea level. All the top ten highest peaks are located in either Wales or Scotland. The highest point is Ben Nevis, reaching 1,343 m.5

Rain pattern

The mountains of Wales, Scotland, the Pennines in Northern England and the moors of southwest England are the wettest parts of the country. Some of these regions receive more than 4,500 mm of rainfall annually, making them some of the wettest locations in Europe. Other regions can be very dry, with the south and south-east regions receiving an annual average of less than 700 mm.4


The longest river is the Severn (350 km), which flows through both Wales and England, and the second longest is the Thames (322 km). Other major rivers in England and Wales include the Humber, Tees, Tyne, Great Ouse, Mersey and Trent Rivers. Scotland’s river system is largely separate from that of England. The two major rivers of Scotland’s central lowland are the River Clyde and the River Forth. Scotland’s longest river is the River Tay (188 km). As a result of its industrial history, the United Kingdom has an extensive system of canals, mostly built in the early years of the Industrial Revolution.3,4

In 2014, total electricity generation was 336 TWh, of which renewable energy accounted for 19 per cent. Gas and coal powered plants dominated the generation mix contributing a combined 60 per cent to total generation. Nuclear provided 19 per cent while wind, wave and photovoltaic contributed approximately 11 per cent (Figure 2). Hydropower accounted for less than 2 per cent. For electricity generated from renewable sources, wind contributed more than half.

Electricity sector overview Electricity infrastructure in the United Kingdom of Great Britain and Northern Ireland is well developed with a 100 per cent electrification rate. In 2014, total installed capacity was 85 GW. Approximately 40 per cent is from combined cycle gas turbine plants, 31 per cent from conventional thermal power plants (utilizing both coal and gas), 12 per cent from nuclear plants, 7 per cent from wind power, 5 per cent from hydropower plants (including pumped storage facilities) and a further 5 per cent from other forms of renewable energy (Figure 1).6

In addition to domestic generation capacity, the United Kingdom electricity network also has four interconnectors

FIGURE 1

FIGURE 2

Installed capacity in UK by source (GW)

Annual electricity generation in UK by source (TWh)

Combined cycle gas turbine

33.8 26.6

Thermal power plants Nuclear Wind power Other RE sources Hydropower

Gas

100.9

Coal

100.7

Nuclear

9.9

63.7

Wind, wave and solar

5.6

36.1

Other RE sources

4.7 4.3

6.0

Hydropower

5.9

Source: DUKES7

Source: DUKES6

537

22.7

Oil and other

Northern Europe

4.2


}} }} }} }}

totalling 4 GW of capacity connecting the grid with Ireland and mainland Europe.9 The country was a net importer of electricity in 2014, with net imports contributing 5.7 per cent of the electricity supply.7 Final consumption in 2014 was 303.4 TWh with approximately 36 per cent consumed by the residential sector, 31 per cent by the industrial sector and 25 per cent by the commercial sector (Figure 3).

The United Kingdom faces particular challenges to ensure a continuing security of supply, to decarbonize electricity generation and to maintain affordability.14 Electricity demand is expected to increase due to electrification of end-use sectors such as transport and heat.15 Further, approximately a fifth of existing plants are set to close over the coming decade and will be replaced by sources which are likely to be increasingly intermittent, such as wind, or inflexible, such as nuclear.14,15 An analysis by the Committee on Climate Change (CCC) has suggested the need for investment in 30-40 GW of low-carbon capacity between 2020 and 2030, to replace the ageing capacity currently on the system and to meet growing demand.16 Renewable generation, especially wind, can play a greater role to meet part of the future capacity expansion requirements in the UK power sector. In recent years, investment in wind has made good progress, with the construction of 1.1 GW of onshore capacity and 0.33 GW of offshore capacity in 2013/14, leading to a total installed capacity of 11.1 GW of wind by end of 2014.8 The Government has introduced renewable electricity policies in order to increase the share of renewable energy (wind, biomass, solar and hydro) in the UK electricity generations (see below).

FIGURE 3

2014 electricity consumption by sector (%) 9%

35%

25% 31% Domestic Commercial

nPower: GBP 0.162.kWh (US$0.257); E .ON Energy: GBP 0.148/kWh (US$0.235); Scottish Power: GBP 0.168/kWh (US$0.267); SSE: GBP 0.155/kWh (US$0.246).33

Industry Other

Source: DUKES6,7

Although there are many producers operating within the generation sector, it is largely dominated by six companies collectively known as the Big Six: EDF, Centrica (British Gas), E.ON, RWE nPower, Scottish Power and SEE plc. National Grid plc is responsible for the transmission network in England and Wales. In Scotland the grid is split between two separate entities, SP Energy Network (a subsidiary of Scottish Power) is responsible for southern and central Scotland and SSE plc is responsible for Northern Scotland. National Grid plc, however, remains the system operator for the whole United Kingdom grid. Nine Distribution Network Operators (DNO), operating in 12 separate regions, distribute electricity from the transmission network.

Small hydropower sector overview and potential In the United Kingdom small hydropower (SHP) is generally classed as below 10 MW.30 As of September 2015 there was an estimated installed capacity of 274.2 MW with an estimated additional, financially viable, potential of up to 905 MW, bringing total potential to 1,179 MW.26,27,31 This would suggest that approximately 23 per cent of SHP potential, below 10 MW, has been developed. It is worth noting, however, that the estimated potential figure is based upon studies with lower limits meaning sites with sufficiently low capacities were not included (see below). In comparison to data from World Small Hydropower Development Report (WSHPDR) 2013, installed capacity has increased by approximately 19 per cent while estimated potential has increased by over 236 per cent.32

Full competition was introduced into the United Kingdom electricity retail market in 1999.12 Electricity suppliers buy electricity from the wholesale market or directly from generators and arrange for it to be delivered to the end customers who can choose any supplier to provide them with electricity. The market is regulated by the Gas and Electricity Markets Authority, which operates through the Office of Gas and Electricity Markets (Ofgem). Ofgem issues companies with licences to carry out activities in the electricity and gas sectors, sets the levels of return which the monopoly networks companies can make, and decides on changes to market rules.13

FIGURE 4

SHP capacities 2013-2016 in United Kingdom (MW)

Electricity costs vary across suppliers and regions. In 2014 the average annual residential rate in the United Kingdom (across all payment types) was approximately GPB 0.158/kWh (US$0.248).32 According to 2012 data, average electricity prices of the Big Six were: }} British Gas: GBP 0.151/kWh (US$0.240); }} EDF Energy: GBP 0.160/kWh (US$0.254);

Potential 2016 2013


1,179 350 274 230

Sources: SISTEch et al.,26 BHA,27,31 WSHPDR 201332

538

There is an estimated 340 SHP plants in the United Kingdom with a total capacity of 274.202 MW. Sixty-five of these sites are between 1 MW and 10 MW representing more than 75 per cent of the total installed capacity (Table 1). This represents approximately 6.4 per cent of the total hydropower installed capacity and approximately 0.3 per cent of the country’s total installed capacity. Almost all of the country’s hydropower plants are located in Scotland and Wales.

contribute to the European Union’s (EU) overall binding target of 20 per cent of energy consumption from renewable sources by the same year.17 The Government has indicated that it expects to meet this target with 30 per cent of electricity supplies coming from renewable sources by 2020.19 Having achieved its own target of 31 per cent by 2013, Scotland has introduced an ambitious renewable energy target of 100 per cent by 2020.20 Major polices relating to renewable electricity generation include: feed-in tariffs (FITs), the Renewable Obligation (RO) and Contracts for Difference (CfD). FITs for renewable energy were announced in October 2008 as part of the Energy Act 2008 and came into effect in April 2010. The tariffs apply to electricity generated from plants of no more than 5 MW utilizing hydropower, solar photovoltaic, wind or anaerobic digestion with an eligibility period of 20 years. Micro combined heat and power (CHP) installations of 2 kW or less are also eligible. The FITs cover all energy generated, not just what is fed into the grid. However, electricity that is fed into the grid receives a small additional export tariff of GBP 0.0485 (US$0.077) per kWh as of 1 April 2015.

TABLE 1

SHP plants in the United Kingdom by capacity (MW) 1-10 MW

500999 kW

100499 kW

5099 kW

2549 kW

Less than 25 kW

Number of sites

65

46

128

39

31

31


206.85

32.67 30.59 2.69

1.08

0.33

Source: BHA31

Due to costs and concerns about its environmental impact, further large-scale development potential is limited. However, there is scope for exploiting the country’s remaining SHP resources in a sustainable way. The good quality and most financially viable sites have already been utilized or lie in protected regions of the Scottish highlands and Snowdonia, Wales. The British Hydropower Association’s (BHA) England and Wales Hydropower Resource Assessment Report has identified approximately 1,692 potential sites in England and Wales. The total potential identified by this study is between 146 MW and 248 MW. Between 119 MW and 185 MW, or 75 to 80 per cent, are from potential sites located in England and between 59.33 MW and 77.51 MW, or 30 to 40 per cent, from potential sites in the north of England.26 A separate study of SHP potential modelled 36,252 separate sites that were deemed practically and technically feasible in Scotland. Of these, 1,019 sites with a potential of 657 MW were deemed financially viable. More than half of these sites were estimated to have a capacity between 100 and 500 kW (537 sites with total potential capacity 150.4 MW).27 Both studies however, had lower limits in terms of the potential capacity of sites which were included. For the England and Wales study, a lower limit of 25 kW was set for remote sites and for the Scottish study there were limits of 100 kW for sites in the north of Scotland and 25 kW in the south. This means that a number of pico-hydropower sites were not included, in particular old water mills that could be modernised to provide generated electricity. With some estimates suggesting there could be 20,000 old water mill sites in England alone there remains significant potential unaccounted for.33

TABLE 2

Proposed hydropower FITs in the United Kingdom, 1 October 2015 to 31 March 2016 Plant capacity

Rates GBP/kWh (US$/ kWh)

< 15 kW

0.1545 (0.2455 )

15 kW-100 kW

0.1443 (0.2292 )

100 kW-500 kW

0.1140 (0.1811 )

500 kW-2 MW

0.0891 (0.1416 )

> 2 MW

0.0243 (0.0386 )

Source: Ofgem38

As of June 2013 over 400,000 installations were part of the FIT scheme with a total capacity over 2.1 GW.37 Since their introduction the FITs have been slowly reduced at regular intervals with FITs for hydropower being reduced by an average of 25 per cent while those specifically for plants above 2 MW reduced by almost 50 per cent (Figure 5). FIGURE 5

FITs for hydropower in the United Kingdom by capacity 2010-2016 25 FTT (p/kWh)

20 15 10 5 0


2010

The Government has a target of 15 per cent of energy supply from renewable sources by 2020, in order to

2011 2012 < 15 kW 100 kW - 500 kW

Source: Ofgem38 539

2013 2014 2015 15 kW - 100 kW 500 kW - 2 MW

Northern Europe

4.2


For plants greater than 5 MW, the RO was introduced in England and Wales in 2002 and in Northern Ireland in 2005. In Scotland, a different but similar policy, Renewable Obligation (Scotland), was also introduced in 2002. The RO requires electricity suppliers to source an increasing proportion of electricity from renewable sources. In order to demonstrate they have met their obligation, suppliers must obtain Renewable Obligation Certificates (ROCs), which are issued to operators of accredited renewable energy plants.

forces in order to encourage greater efficiency, to reduce uncertainty of revenues and to protect consumers from paying higher costs.35 Legislation on small hydropower All hydropower projects must obtain three permissions prior to construction and operation: an environmental license granted by the relevant regional environmental agency, planning permission granted by the local council or National Park Authorities and accreditation to generate and export electricity provided by Ofgem. FITs for hydropower from 1 October 2015 to 31 March 2016 are given in Table 1. FITs are available only for plants with an installed capacity less than 5 MW (see below). As of 2015 there were 421 accredited hydropower plants on the Central FIT Register with a combined total capacity of 43 MW.24

Where suppliers do not present a sufficient number of ROCs to meet their obligation, they must pay an equivalent amount into a buy-out fund. In the 2013/2014 period 62.8 million ROCS were issued by the Government, the highest number on record, with each ROC worth GBP 47.72 (US$75.83). Suppliers in England, Wales and Scotland were required to present 0.206 ROCs per MWh of electricity supplied while suppliers in Northern Ireland required 0.097 ROCS per MWh. All suppliers met their obligations in this period with 60.8 million ROCS presented for compliance and GBP 42.4 million (US$67 million) paid into the buy-out fund. Total supplier obligation was 61.9 million ROCs meaning 98.2 per cent of obligations were complied with via ROCs, the highest proportion since the introduction of the scheme.34 The RO scheme is currently being phased out in favour of a new scheme, Contracts for Difference (CfD) and will close to new generating capacity in 2017.

Barriers to small hydropower development Investment in new SHP plants is limited despite the renewable policies. The FITs had only had a small impact on hydropower with only 2 per cent of the total capacity of plants registered for FITs coming from hydropower. Lowering of the FIT tariffs may further deter potential investors. In addition, investors and operators must consider environmental issues including additional features which may impact costs.28 Developers must not only have the initial financial outlay for the build, but also for feasibility studies on the economic viability and environmental impact of a potential site and detailed analysis and expensive hardware to prevent adverse effects on fishing. They also have to counter a range of perceived conflicts with riverbased leisure interests and prove that there will be no impacts to the river bed, river banks, flora and fauna, land drainage or the ability to remove flood waters.29

The CfD scheme was introduced in 2013 and constitutes a contract between a low carbon electricity generator and the government-owned Low Carbon Contracts Company (LCCC). According to the scheme, generators are paid the difference between the price for electricity given the cost of investing in a particular low carbon technology and the country’s average market price for electricity. According to the Government, the aim of the new scheme is to give generating companies more exposure to market

540

4.3

Southern Europe Paulo Alexandre Diogo, New University of Lisbon


Six of these countries (Croatia, Greece, Italy, Portugal, Slovenia and Spain) are European Union (EU) member states. Four other countries (Albania, Macedonia, Montenegro and Serbia) are recognized candidates for EU membership and Bosnia and Herzegovina is a potential candidate. As a result, all countries of the region have their national policies aligned in accordance with the EU initiative on renewable energy.

Southern Europe comprises 16 countries and territories. This report covers 11 of them that use small hydropower (SHP): Albania, Bosnia and Herzegovina, Croatia, Greece, Italy, The Former Yugoslav Republic of Macedonia (Macedonia), Montenegro, Portugal, Serbia, Slovenia and Spain. The overview of these countries is given in Table 1.

Climate and resource endowments vary from country to country. However, most countries experience the same regional energy-related challenges, namely heavy dependence on imported fossil fuels, underdeveloped grid infrastructure and climate change causing temperature increase and desertification. Due to the region’s high dependence on imported energy, it is exposed to geopolitical tensions and commodity price volatility. In order to strengthen their energy security, the countries aim to reduce the share of fossil fuels in electricity production and diversify energy sources, in particular, through development of domestic renewable energy. However, the economic downturn experienced by the region since 2008 has heavily affected national economies and drove down investments in the energy sector, including renewable energy sources.

FIGURE 1

Share of regional installed capacity of SHP by country Portugal Serbia 6% 1% Macedonia 1% Montenegro 0%

Slovenia 2%

Spain 33% Italy 50%

Bosnia and Herzegovina 1% Albania 1%

Greece 4%

Croatia 1%

The main renewable energy sources developed in the region are hydropower, wind power and solar power. With the long history of hydropower exploitation and the total


TABLE 1

Overview of countries in Southern Europe (+/– % change from 2013) Country

Total population (million)

Albania

2.82 (–6%)

44 (–8pp)

Bosnia and Herzegovina

3.79 (–2%)

60

Croatia

4.24 (–5%)

41 (–1pp)

100

4,017 (+1%)

13,431 (–8%)

2,141 (+1%)

8,106 (+6)

Greece

10.90 (+1%)

22 (-)

100

19,604 (+27%)

50,300 (–3%)

3,241 (+7%)

3,800 (–37%)

61.34 (+0.1%)

31 (–1pp)

100 121,762 (+10%)

269,148 (–7%)

Macedonia, FYR

2.08 (+1%)

43

100

2,011 (+33%)

4,980 (–22%)

663 (+26%)

1,200 (–45%)

Montenegro

0.63 (–2%)

36

100

867 (0%)

3,105 (+16%)

657 (–0.2%)

1,686 (–39%)

Italy

Portugal

Rural Electricity population access (%) (%)





100

1,823 (+17%)

4,724 (–38%)

1,725 (+18%)

4,724 (–11%)

100

3,989 (–7%)

15,030 (+7%)

2,085 (–12%)

5,821 (–6%)

21,979 (+24%) 59,575 (+30%)

10.37 (–4%)

37 (–2pp)

100

17,404 (–3%)

48,999 (–9%)

5,335 (+7%)

16,412 (+1%)

Serbia

7.13 (–2%)

45 (–3pp)

100

8,350 (–0.1%)

36,832 (+3%) 2,800 (–0.7%)

11,472 (–8%)

Slovenia

2.06 (+3%)

50 (0pp)

100

3,453 (+13%) 17,437 (+34%)

Spain

46.4 (–1%)

21

100 108,299 (+14%)

Total

151.76 (–0.9%)

—

100

268,057 (–3%)

291,576 732,043 (–4%) (+11%)

Sources: Various1,3,4,5,6,7 Note: The comparison is between data from WSHPDR 2013 and WSHPDR 2016.

541

1,295 (+53%)

6,366 (+81%)

20,778 (+12%) 31,396 (+37%) 62,699 (+14%)

150,558 (+15%)

FIGURE 2

As of 2016, the region’s total installed SHP capacity amounts to 6,286 MW, with the countries’ installed SHP capacities ranging from 18 MW in Montenegro to 3,173 MW in Italy (Table 3). Italy is also the regional leader in terms of SHP potential. The total SHP potential of Southern Europe is at least 16 GW, with a significant number of projects awaiting implementation. However, the exact regional potential is unknown because many countries do not have accurate data or have never performed any studies of their SHP potential.

Net change in installed capacity of SHP (MW) from 2013 to 2016 for Southern Europe

TABLE 3

Small hydropower* in Southern Europe (+/– % change from 2013)

438

Country 178 27.7

0

-6.7 27

15

Albania

8.8

Bosnia and Herzegovina Spain

Slovenia

Serbia

Portugal

Montenegro

Macedonia

Italy

Greece

Croatia


-78 -4.1 -14 Albania


Regional SHP overview and renewable energy policy

installed capacity of approximately 61 GW, hydropower remains critical for Southern Europe. Thus, Italy is the fourth-largest producer of electricity from hydropower in Europe, whereas Croatia and Macedonia produce more than half of their electricity from hydropower, and Albania depends completely on hydropower. The potential of hydropower remains largely untapped in the region, especially in the Balkan countries. High solar radiation also creates very good potential for solar energy development, with Italy and Spain being the second and third major solar power contributors in the EU.8


Up to 10

Croatia

Up to 10

Greece

Up to 15

Italy

Up to 10

Macedonia, FYR

Up to 10

Montenegro

Up to 10

Portugal

Up to 10

Serbia

Up to 30

Slovenia

Up to 10

Spain

223.0 (+14%)

2,000 (0%)

3,173.0 (+16%)

7,073 (+0.1%)

Macedonia, FYR

60.0 (+33%)

260 (+4%)

Montenegro

17.8 (+98%)

97.5 (–59%)

372.0 (–17%)

750 (0%)

45.5 (–8%)

409 (0%)

Slovenia

157.0 (+34%)

475 (+147%)

Spain

2,104.0 (+9%)

2,185 (0%)

6,286 (+11%)

16,313 (+15%)

Sources: WSHPDR 2013, WSHPDR 2016 Notes: a. The comparison is between data WSHPDR 2013 and WSHPDR 2016. A large difference or a negative change can be due to closures or rehabilitation of SHP sites, and/or due to access to more accurate data for previous reporting. b. Data is for up to 10 MW with the exception of Greece which is up to 15 MW. 1

In Southern Europe, SHP, with its significant untapped potential, plays an increasingly important role in the growth of renewable energy, which is one of the main priorities for the countries’ energy development in accordance with EU policies. All countries in Southern Europe that are members of the EU follow EU Directive 2009/28/CE, which sets the target of a 20 per cent share of renewable energy sources in the EU gross final energy consumption to be achieved by 2020. The target distribution among the countries of Southern Europe is as follows: Croatia, 20 per cent; Greece, 18 per cent; Italy, 17 per cent; Portugal, 31 per cent; Slovenia, 25 per cent; Spain, 20 per cent. According to the progress reports submitted by the countries in 2013, the following percentages had already been achieved: Croatia, 18 per cent; Greece, 15 per cent; Italy, 16.7 per cent; Portugal,

Small (MW) Up to 15

Greece

2

TABLE 2

Albania

1,000 (0%) 100 (+150%)

Total

Classification of small hydropower in Southern Europe Country

1,963 (-)

36.0 (0%)

Serbia

SHP is defined as up to 10 MW by most countries of the region, except Albania and Greece, which have an upper limit of 15 MW, and Serbia, with 30 MW (Table 2). Serbia extended its definition of SHP from 10 MW up to 30 MW in January 2013.

65.1 (+74%) 32.9 (–17%)

Portugal

Small hydropower definition


Croatia Italy

Sources: WSHPDR 2013,2 WSHPDR 2016 1 Note: The comparison is between data from WSHPDR 2013 and WSHPDR 2016. A negative net change can be due to closures or rehabilitation of SHP sites, and/or due to access to more accurate data for previous reporting.


Up to 10

Source: WSHPDR 2016

1

542

One of the most common barriers is the long and complicated authorization and licensing process—a problem reported to be experienced by developers in Greece, Italy, Montenegro, Portugal, Serbia and Spain. Other institutional and regulatory barriers include corruption, disagreement between local and national regulations and institutions. In Bosnia and Herzegovina frequent changes in regulations have caused problems for developers, and other regulatory issues are mentioned as relevant to Albania, Greece, Macedonia, Montenegro and Portugal.

25.7 per cent; Slovenia, 21.5 per cent; and Spain, 15.4 per cent.9 As candidates for EU membership, the other five countries aim to align their energy policies with the EU and have implemented Directive 2009/28/CE as well. Their shares were calculated based on the same methodology for the EU member states and reflect an equal level of ambition. The national targets set for them are as follows: Albania, 38 per cent; Bosnia and Herzegovina, 40 per cent; Macedonia, 28 per cent; Moldova, 17 per cent; Montenegro, 33 per cent; and Serbia, 27 per cent.7

Bosnia and Herzegovina, Croatia, Slovenia, Greece and Montenegro have issues related to water management, with Greece and Montenegro lacking strategic water management documents. In Croatia and Serbia, finding the required initial capital investment can be problematic.

In order to promote the development of renewable energy, all countries of the region have implemented economic incentives, which have also driven the growth of SHP. Thus, suppliers of electricity from renewable sources have received a range of benefits, which include feed-in tariffs (FIT), priority connection to the grid, guaranteed purchase of electricity, preferential access to the network and subsidies. However, in Portugal, the incentives are considered insufficient because of a reduction of the FIT in 2005, whereas Spain in 2012 temporarily suspended FIT pre-allocation and removed economic incentives for new power generation, including renewable energy sources, because of the tariff deficit caused by these incentives. Barriers to small hydropower development

Moreover, missing or weak distribution networks complicate SHP development in Macedonia and Montenegro as their sites with the highest SHP potential are located in remote areas. Development of potential SHP sites is also limited in Croatia due to legal protection of the country’s cultural heritage and landscapes. Italy experiences pressure on the part of social movements that do not approve of hydropower plants, whereas in Serbia there is a generally low awareness of the advantages of SHP among the public as well as professionals. In Albania, power losses reaching above 30 per cent is a significant problem.

Although Southern Europe has a significant SHP potential, its further development is hampered by a number of barriers.

Finally, a number of countries, including Croatia, Macedonia, Serbia, Slovenia and Spain, lack accurate hydrological data, which hinders further SHP development.

543

Southern Europe

4.3

4.3.1

Albania Arian Hoxha


2,894,4751

Area

28,748 km2

Climate

Albania is situated in a transition zone between the Mediterranean climate and the moderate continental climate. Winters are cool, cloudy and wet and summers are hot, clear and dry on the coastal plain. In the mountainous interior part of the country, rainfall in summer is more common and winters are cooler. The average annual temperature is 15°C, the minimum average temperature 1.6°C and the maximum average temperature 20.9°C.2

Topography

Mostly mountainous terrain with small plains along the coast and river valleys. The highest peak is Mount Korab at 2,751 metres above sea level, situated in the east, at the border with Macedonia.2

Rain pattern

Average annual rainfall is 1,430 mm with 1,000 mm on the coast and over 2,500 mm in the mountains. Approximately 70 per cent of rainfall occurs from November to March.2


Albania has 11 major rivers with their 150 tributaries. The longest river in Albania is the Seman, which is 281 km long and divides into the Devoll and Osum. The River Vjosa, 272 km long and, originating from Smolika mountain, is the most torrential in Albania.11 The average altitude of the hydrographical territory is about 700 metres above sea level. The total average flow of the rivers is approximately 1,245 m3/sec.3


FIGURE 2

Generation of electricity in Albania 2007-2014 (GWh) 7,702

3,806

6,957 4,724

5,159 4,158

2,864

4,722

2007 2008 2009 2010 2011 2012 2013 2014

Source: Energy Regulatory Body12

FIGURE 1

FIGURE 3

Electricity generation by sources in Albania (GWh)

Electricity consumption in Albania 2002-2014 (MWh)

2014

2013

2012

2011

2010

2009

2008

2007

2002

It should be noted that the significant difference between the highest and lowest electricity generated volumes due to changing water flows highlights the risk of the power security and stability (Figure 2). Electricity consumption is steadily increasing, with 7,793 GWh reached in 2014 (Figure 3). In 2014 2,814 GWh of electricity was imported.16

2006

Source: Ministry of Energy and Industry10

2005

65.1

9 8 7 6 5 4 3 2 1 0 2004

Small hydropower

4,658.9

2003

Large hydropower

Millions


The main power producer is the Albanian Power Corporation S.A (KESH); it is 100 per cent owned by the State. The total installed capacity in 2014 was 1,823 MW, with the installed capacity of hydropower at 1,725 MW. The thermal power plant (TPP) in Vlora has an installed capacity of 98 MW.10 However, as of 2014, the Vlora TPP was not used due to issues with its cooling system.16 The total generated electricity in 2014 was 4,724 GWh (Figure 1), with 3,408 GWh from KESH and 1,318 GWh from other producers.12


operating in 2011, but due to technical problems in 2014 it was still idle. The KESH S.A was in the process of resolving all related legal disputes with the contractor.

The thermal power plant at Vlora was meant to start 544

Meanwhile a pre-feasibility study for using Liquid Natural Gas (LNG) as a primary source for energy instead of oil was under preparation.20

kV interconnection lines with Kosovo in addition to the South Ring line, which is being finalized. The key event in the distribution sector was the resolution of the dispute between the formerly licensed operator and the Government of Albania.

The transmission system of Albania comprises 400 kV, 220 kV, 110 kV lines and interconnected substations that serve transmission and international interconnectivity. The latter includes: 220 kV lines from Albania to Kosovo and from Albania to Montenegro, 400 kV lines from Albania to Greece and from Albania to Montenegro, 150 kV lines from Albania to Greece. The public entity responsible is the Transmission System Operator.

Until 2015, the electricity market was based on the Transitory Market Model established by the Government Decree No. 539 dated 12 August 2004.21 The decree defined the actors, roles and responsibilities for addressing all related issues and challenges and also ensuring cooperation in terms of legislation compatibility with the European Union directives. On 30 April 2015 the Albanian Parliament adopted the new Law on Energy Sector compliant with the Third Energy Package. The law has fully transposed Directive 2009/72/EC. It includes: }} Liberalization, organization, participation and functioning of a competitive electricity market; }} Authorizations and licensing procedures in the electricity sector; }} Consumer protection, security of supply and competitive structures in place within the sector; }} Integration of the Albanian electricity market into the regional and European electricity market.

The Distribution System Operator (OSHEE) is now a 100-per-cent public-owned company. Recent initiatives and reforms have achieved a positive impact on the reduction of electricity losses (both technical and nontechnical) and increased the collection rate of unpaid bills. The level of electricity losses was reduced from 45 per cent in 2013 to 37.8 per cent in 2014. The reduction of the losses in the distribution grid has continuously increased in the first months of 2015. The losses in January, February and March 2014 were 47 per cent, 42 per cent and 42.8 per cent, respectively, whereas in 2015 they were 36.6 per cent, 31.8 per cent and 33.4 per cent, respectively. The annual collection improved from ALL 38.5 billion (US$302.65 million) in 2013 to ALL 49.1 billion (US$386 million) in 2014 (Table 1). The first months of 2015 also recorded a significant improvement in collection compared with the revised targets.12

Small hydropower sector overview and potential The definition of small hydropower (SHP) used in Albania is up to 15 MW.22 Installed capacity of SHP plants up to 10 MW in Albania is 65.13 MW while the potential is estimated to be 1,963 MW, indicating that nearly 3.5 per cent has been developed. Between World Small Hydropower Development Report (WSHPDR) 2013 and WSHPDR 2016, installed capacity has almost doubled (Figure 4).14

TABLE 1

Electricity tariffs in Albania for 2015 Activity

Approved tariff (ALL (US$) per kWh)

Production KESH

1.45 (~ 0.01)

Wholesale public supplier

3.0 (~0.02)

Transmission OST

FIGURE 4

0.65 (~0.005)

Small hydropower capacities 2013-2016 in Albania (MW)

Users of distribution grid 35 kV

1.5 (~0.01)

Users of distribution grid

4.79 (~0.038)

Potential

7.636 (~0.06)

capacity

Private small and large HPP Distribution retail prices

Off-peak

Peak

Consumers 35 kV

9.5 (~ 0.075)

10.93 (~ 0.086)

Consumers 20/10/6 kV

11 (~ 0.086)

12.65 (~ 0.1)

14 (~ 0.11)

16.1 (~ 0.127)

9.5 (~ 0.075)

9.5 (~ 0.075)

Consumers 0.4 kV Households

2016 2013

Installed capacity

1,963 N/A 65.13 37.45

Due to its topography, Albania is quite rich in rivers, with more than 150 rivers and torrents forming eight main big rivers. They have a south-east to north-west flow, mainly oriented towards the Adriatic coast. The most important rivers are the Drin (340 m3/sec), Vjosa (210 m3/sec), Seman (101 m3/sec), Mat (74 m3/sec), and Shkumbin (60 m3/sec) revers. Although they have small flows, their considerable inclination makes these rivers important for hydropower development. Consequently, Albania is seen as a country rich in water reserves and its hydropower potential can play an important role in the development


There have been a number of changes in the sector, which relate to an overall reform process across all areas including legislative and strategic aspects. The country’s generating capacity still remains insufficient for meeting its demand. However, the overall production has increased. The transmission system should soon benefit from the investment projects including the 400

545

Southern Europe

4.3


of the country. Considering the current power supply situation as well as the potential demand for power, the Government has set the development of the energy sector among its priorities, focusing on the development of renewable energy resources and, in particular, hydropower plants. There is a large hydropower potential and currently only 35.4 per cent of it is being used. The total hydropower reserves could enable the installation of a 4,500-MW power network and its annual electricity power production could reach up to 16 TWh. Based on studies carried out by international consultants, the main potential areas for installation of hydropower plants are the Drin River, the Osum River, the Vjosa River and the Erzen River.3

but indirectly governed by the Law on Concessions. This has helped to increase the participation of independent power producers (IPP) in the development of SHP installations or the rehabilitation of existing mini grid systems, such as the successfully implemented New Arras SHP plant.18 In addition to the new Power Sector Law of 2015, the Government is drafting new laws on renewable energy and on energy efficiency, as well as regulatory acts of those laws, which are likely to further liberalize the sector. Meanwhile the Government has removed the VAT on imported machinery, which will facilitate foreign investment and SHP development.19

There are no new SHP projects planned or carried out currently.

Renewable energy policy Under Directive 2009/28/EC, Albania has committed to a binding 38 per cent target of energy from renewable sources in gross final energy consumption in 2020, compared with 31.2 per cent in 2009. The network operators have to increase transparency regarding connection and access to the grids. In 2015 the Energy Regulatory Body was working on the preparation of a system that would certify renewable sources of energy based on guarantees of the origin. Also the Ministry of Energy and Industry is finalizing the Energy Efficiency Law to be sent to the Parliament for approval. It would be essential for further development of the legislative framework and for the implementation of corresponding measures foreseen for the achievement of energy efficiency targets.

Legislation on small hydropower Established by the Power Sector Law (Law No. 9072), the Energy Regulatory Body (ERE) has the authority to regulate electricity pricing for existing hydropower stations under 10 MW and for new installations of up to 15 MW, and only these SHP installations may receive feed-in tariffs with power purchase agreements with the ERE.17 Moreover, the ERE is responsible for granting licenses to power producers with separate licenses for generation, transmission and distribution of electricity. Under its Rules of Practice and Procedure (Decision No. 21 dated 18 March 2009), the ERE guarantees equal treatment in issuing licenses and resolving disputes between parties.5 More specifically, under the Rules and Procedures on Certification of Electricity from renewable sources, the ERE has outlined the procedures for generators to apply for green certificates and approval of project implementation.

Barriers to small hydropower development While SHP installed capacity has risen considerably in recent years, the progress of SHP development in Albania is slower than expected due to the delay in the approval of the law on Renewable Energy which will establish mechanisms of support and incentive schemes for developers. The main obstacles to SHP development are related, but not limited to the lack of financing.

The criteria for authorization of new electricity generating capacity without concessions are duly transposed by the Power Sector Law, whereas tendering for new capacity is not treated in the Power Sector Law

546

4.3

4.3.2

Southern Europe

Bosnia and Herzegovina Armin Hadzialic, Higracon d.o.o. Sarajevo


3,791,6621

Area

51,209 km2

Climate

Bosnia and Herzegovina has three climatic zones: a moderate continental climate in the north, a mountainous climate in the centre and a Mediterranean climate in the south-west. Overall mean annual temperatures are between 9.5°C and 14.6°C. Mean temperatures in January are around 0°C while in July the mean temperatures are between 18.7°C and 22.6°C. Absolute minimum temperatures can dip below –27°C in the mountainous regions; absolute maximum temperatures can reach 45°C.2

Topography

The territory of Bosnia and Herzegovina can be divided into three geographic zones: high plains and plateaus along the northern border with Croatia, low mountains in the centre and the higher Dinaric Alps covering the rest of the country. The highest mountain is Maglic at 2,386 metres above sea level. Approximately 50 per cent of the country is covered by forests.3

Rain pattern

In the northern continental climate zone average annual precipitation ranges from 700 mm in the east to 1,300 mm in the west. In the southern Mediterranean zone annual average precipitation ranges from 1,000 mm to 1,800 mm. The highest levels of precipitation occur in the colder part of the year—between December and February, while between June and August the precipitation is relatively low. During this time of year drought periods are possible.1


Rivers and lakes of Bosnia and Herzegovina are part of the hydrographical basin of the Black Sea and the Adriatic Sea. The Sava is the most prominent river that flows into the Black Sea and runs 345 km in Bosnia and Herzegovina, along the northern border with Croatia. All the major rivers in Bosnia and Herzegovina flow into the Sava River, which is the largest tributary of the Danube: the Una, the Vrbas, the Bosna and the Drina Rivers. The only river that flows into the Adriatic Sea is the Neretva in Herzegovina. In Herzegovina there is a massive karst area (more than 4,000 m2) below which flow a number of underground rivers and streams.4


and 83.75 MW (2.1 per cent) from small hydropower (SHP), wind and solar power plants combined (Figure 2).

In 2014, total electricity generation of Bosnia and Herzegovina was 15,030 GWh. Approximately 59 per cent came from thermal power plants, 39 per cent from hydropower and less than 2 per cent from other renewable sources and industrial power plants combined (Figure 1).5

FIGURE 2

Installed electricity capacity in Bosnia and Herzegovina by source (MW) Hydropower

FIGURE 1

Annual electricity generation in Bosnia and Herzegovina by source (GWh) Thermal power

1,765.0

Industrial power plants

91.2

Other RE sources

83.8

Source: State Electricity Regulatory Commission5

8,920.7

Hydropower Other RE sources

2,048.6

Thermal power

5,820.5

Unfavourable hydrological conditions in 2014 reduced the amount of electricity generated by hydropower plants by approximately 18 per cent compared to 2013. Figure 3 shows variations in hydropower generation and its relationship to the overall electricity generation mix.5 Nonetheless, despite annual variations, the country is a net exporter of electricity with consumption remaining significantly below generation since 2010. Overall consumption in 2014 was 12,209.72 GWh and the country has an electrification rate of 100 per cent.

264.1

Industrial power plants 24.6

Source: State Electricity Regulatory Commission5

Total installed capacity in 2014 was 3,988.58 MW, with 2,048.6 MW (51.3 per cent) from large hydropower, 1,765 MW (44.3 per cent) from thermal power plants, 91.23 MW (2.3 per cent) from industrial power plants 547

Brcko) and owned by the local government. In 2014 EP BIH contributed approximately 50 per cent of the overall electricity generation, ERS 38 per cent and EP HZHB 12 per cent (Figure 4).5 The transmission network in Bosnia and Herzegovina consists of 110 kV (cable), 110 kV, 220 kV and 400 kV facilities. The total number of overhead lines is 297, with an interconnection number of 32 and a length of 6,341.48 km. The total number of substations is 145 + 5 (MV), with installed power (MVA) of 12,387.5 + 189.5 (MV), number of transformers 255 + 33 (MV) and transformers installed power (MVA) of 12,387.5 + 189.5 (MV).7

FIGURE 3 FIGURE 4

Annual generation in Bosnia and Herzegovina 20102014 (GWh)

Annual generation in Bosnia and Herzegovina by generation company

20 000 38%

15 000 10 000

50%

5000 GWh


The electricity market in Bosnia and Herzegovina is structurally underdeveloped despite its potential and the commercial activities of the industry. Due to the country’s unique political structure, there are multiple energy regulatory bodies, which makes their work complicated and less efficient. As established by the 1995 Dayton Agreement, there is a national government, as well as second-tier governments of the Federation of Bosnia and Herzegovina (FBiH) and the Republika Srpska (RS). Following this political structure, the regulatory structure includes three regulators—one at the national level and two entity-level regulators.

0 2010

2011

Hydropower Total generation

2012

2013

2014

12%

Thermal power Total consumption

EPBH

EPHZHB

EF6

Source: State Electricity Regulatory Commission5 Source: State Electricity Regulatory Commission5

Total price for electricity covers: the cost of electricity production and purchase of electricity from renewable energy sources, the supplier’s service cost, and the fee for renewable energy sources, which was introduced in accordance with the Regulation of the Government of the Federation of Bosnia and Herzegovina on Renewable Energy Sources and Cogeneration. According to this regulation, each supplier is obliged to submit an invoice to a customer highlighting the amount of total compensation for the promotion of renewable energy sources.

At the national level, the Ministry of Foreign Trade and Economic Relations of Bosnia and Herzegovina (MOFTER) has primary responsibility over the energy sector. The State Electricity Regulatory Commission (SERC) is in charge of regulatory implementation with regards to electricity transmission, transmission system operation and international trade. At the entity level, the energy sector is regulated by the Ministry of Energy, Mining and Industry of the Federation of Bosnia and Herzegovina (FMEMI); and the Ministry of Industry, Energy and Mining of the Republika Srpska (MIEMRS). The Federation of Bosnia and Herzegovina Electricity Regulatory Commission (FERK) and the Republika Srpska Energy Regulatory Commission (RERS) implement regulation of electricity generation, distribution and supply within each entity respectively.

Current winter tariffs (October – April) for unqualified (tariff) customers are approximately EUR 0.640/ kWh (US$0.852). Summer tariffs (April – October) are approximately EUR 0.492/kWh (US$0.655).8 For electricity generation from renewable sources (and for efficient cogeneration) suppliers receive a number of benefits including: priority connection to the grid, preferential access to the network (dispatch), compulsory purchase of electricity, a guaranteed repurchase price (feed-in tariff) and the right to a premium for the consumption of electricity for their own use or sold on the market.9

The participants of the electricity market are: the Independent System Operator in Bosnia and Herzegovina (ISO BiH) (which began operations in July 2005), the transmission company, Elektroprenos Bosne I Hercegovine(which began operations in February 2006), three separate vertically integrated utilities engaged in generation, distribution and supply (each of which are entity-owned), traders, and eligible customers. The three s utilities are Elektroprivreda BIH Sarajevo (EP BIH), Elektroprivreda HZHB Mostar (EP HZHB) and Elektroprivreda RS Trebinje (ERS). They operate in their regions, while in the Brcko District distribution and supply are carried out by a separate entity (Komunalno

Small hydropower sector overview and potential SHP is defined as less than 10 MW with subcategories for mini-hydropower (less than 1 MW) and micro-hydropower (less than 100 kW).12 The total installed capacity of SHP plants is 36 MW with a total potential capacity of 1,000 MW. This indicates that 548

approximately 3.6 per cent of SHP potential in the country has currently been developed.13 This data has remained unchanged since World Small Hydropower Development Report (WSHPDR) 2013 (Figure 5).14

plants are returned to state ownership. The guaranteed price for energy produced by SHP is approximately EUR 0.06/kWh (US$0.08). Renewable energy policy

FIGURE 5

In accordance with the Energy Community Agreement, the Energy Community Ministerial Council adopted an implementation plan for Directive 2009/28/EC on promotion of the use of electricity from renewable sources in 2012. The binding target for Bosnia and Herzegovina is 40 per cent of renewable energy consumption by 2020. To achieve this, the Governments of both the Federation of Bosnia and Herzegovina and the Republika Srpska adopted plans in 2014 to encourage production from renewable energy sources.15 On the basis of laws adopted for efficient cogeneration and the development of renewable energy sources, both entities also developed and adopted relevant by-laws.

Small hydropower capacities 2013-2016 in Bosnia and Herzegovina (MW) Potential 2016 2013

1,000 1,000


36 36

77 Significant activity in the SHP industry began when EP BIH launched a study of hydropower potential on medium and small rivers. Based on this study a public call for concessions was announced between 2005 and 2006 with over 70 concessions for SHP awarded. In the RS, a 1980 study of the hydropower potential on a tributary of the Drina River was the basis for awarding 100 concessions for SHP in 2006. Currently there are 25 operational SHP plants, 10 plants are under construction and a further 135 are in the pre-approval stage.10

There is still no comprehensive countrywide scheme for promotion and development of the renewable energy sector. Bosnia and Herzegovina continues to operate without a national renewable energy action plan, as required by the Energy Community Treaty and there are no competencies laid down in the relevant legislative framework. Energy laws to enforce such a plan (and the public responsibilities for ensuring that the plan is devised in such a way that the national renewable energy target is reflected in the laws) are unclear. At the same time, the improved legislative framework at the entity level, along with the incentives introduced, has resulted in ongoing promotion of renewable energy sources. In the Federation of Bosnia and Herzegovina the 40 per cent target of total generation from renewable energy has effectively been achieved, which may lead to stagnation of the sector. A smaller number of electricity generating facilities powered by renewable energy sources have been developed in the Republika Srpska, which may enable more development within the region.11

SHP accounts for approximately 1.8 per cent of total hydropower capacity and less than 1 per cent of the country’s total installed capacity.5‑ The country’s gross theoretical hydropower potential is estimated to be 8,000 MW while the technically feasible potential is 6,800 MW and the economically feasible potential is 5,800 MW. Thus SHP potential is between 12.5 and 17.2 per cent of total hydropower potential.10 Electricity from renewable sources, including SHP plants, is mostly purchased by domestic energy companies. They buy electricity at much lower prices than is guaranteed with the difference paid by citizens and other consumers. In the Federation of Bosnia and Herzegovina this amounts to almost half the price and in the Republika Srpska to approximately two-thirds. This is funded by the Fund for Compensation for Renewable Sources, which is sourced from citizens and other electricity consumers. The fee is charged with each electricity bill and, depending on the energy company citizens purchase their electricity from, ranges from KM 0.29 (US$0.197) to KM 0.34 (US$0.231) per month.

Barriers to small hydropower development Hydropower potential, especially SHP potential, is not sufficiently exploited in Bosnia and Herzegovina. One of the most important factors in the lack of development is the discrepancy between regulations at the entity level and the local community or municipality levels. This means that obtaining the necessary permits may take anywhere from 18 to 36 months. Another concern is the malleability of policy for renewable energy: during construction of projects the law is liable to change with a potentially negative impact on owners and/or investors.

In addition to the higher electricity prices, investment in SHP plants is also more cost-effective in the Republika Srpska due to the purchase guarantees lasting 15 years, as opposed to only 12 years in the Federation of Bosnia and Herzegovina. However, even in the period when electricity producers have the right to incentives, price adjustments can occur which are often detrimental to producers. Concessions are issued for a period of 30 years with the possibility of extension; and if not extended, the SHP

Potential investors may face the possibility for favouritism and corruption which can occur at any step in the construction of SHP plants, from the application for the concession and obtaining permits to the approval of connection to the electricity grid.6

549

Southern Europe

4.3


In general, the existing model for transmission has never truly been unbundled and independent and the electricity market would benefit from being opened up in real terms, including between the entities. This would require a coordinated process for further liberalization of the supply chains and full recovery of costs, together

with creation of a system for the protection of socially vulnerable customers outside price regulation.6

550

4.3

4.3.3

Southern Europe

Croatia Marcis Galauska and Nathan Stedman, International Center on Small Hydro Power


4,238,3891

Area

56,594 km2

Climate

Mediterranean and continental; continental climate predominant with hot summers and cold winters; mild winters, dry summers along coast. Average temperatures are approximately 25°C during summer and 8°C during winter.3

Topography

The country‘s topography is diverse and includes flat plains along the Hungarian border and low mountains and highlands near the Adriatic coast. The territory can be divided into three geographic zones: the Pannonian and Peri-Pannonian Plains in the east and north-west, the hills and mountains in the centre and the Adriatic coast.2

Rain pattern

Precipitation varies across the country. The Adriatic coast enjoys abundant rainfall of 1,0001,500 mm per year with autumn and winter being particularly rainy. However, some areas in the bays and along the coast are protected by the islands and receive about 800 mm of rain per year. Summers tend to be dry and sunny along the coast, with occasional rain or thunderstorms. Only in the northernmost zone the rains are quite frequent and abundant even in the months of July and August. In the interior parts of the country precipitation is frequent ranging from 700 to 860 mm per year.3


About 62 per cent of the territory is covered by the branching river network that belongs to the Black Sea catchment basin. The longest Croatian rivers, the River Sava (562 km) and the River Drava (505 km) also belong to this catchment basin, as does the Danube, into which they both flow. These three rivers to a large extent form the natural borders of the country.4


areas of the country: near the Slovenian-Hungarian border and along the Adriatic coastline. The Varazdin hydropower plant is located near the Slovenian-Hungarian border, and the three hydropower plants along the Adriatic coastline are at Senj, Obrovac and Zakucac. All of these are owned and operated by the national electricity company, Hrvatska Elektroprivreda (HEP).

In 2013, overall domestic electricity supply was 17,921 GWh, electricity generation was 13,431 GWh, including hydropower (60 per cent), coal (18 per cent), gas (15 per cent), wind (4 per cent), oil (2 per cent) and biofuels (1 per cent), while solar PV produced less than 0.1 per cent; exports were 6,770 GWh and imports 11,260 GWh (Figure 1 and Figure 2).5 Installed capacity was 4,017 MW and the electrification rate 100 per cent.

FIGURE 2

Electricity supply (GWh)

FIGURE 1

Imports

Electricity generation by source in Croatia (GWh)

Exports Hydropower

Source: IEA5

2,421

Gas

2,021

The 486 MW Zakucac hydroelectric plant, the largest power plant in Croatia, is scheduled for renovation to improve its operability. A tender has been announced for the new 68.5 MW Ombla hydroelectric plant proposed for a site on the Rijeka Dubrovacka River. Two additional hydropower plants have also been proposed, the 106-MW Virje plant and the 42 MW Lesce plant.

517

Oil

230

Biofuels

125

Solar power

6,770

8,106

Coal

Wind power

11,260

11

Source: IEA5

The Croatian electric power transmission system is owned and operated by HEP. The electricity distribution

Croatia has four major hydroelectric plants in two main

551


grid has three different voltages; there are 903 kilometres of 400 kV lines, 1,224 kilometres of 220 kV lines, and 4,760 kilometres of 110 kV lines. There are also five 400 kV substations, fifteen 220/110 kV substations and 140/110 kV substations.6

FIGURE 3

Small hydropower capacities 2013-2016 in Croatia (MW) Potential 2016 2013

Although the Croatian electricity market is formally open, the market activities of generation, supply and trade are mainly carried out by state-owned companies. There are 28 companies active in the generation sector. Although the majority of these (approximately 80 per cent) are privately owned, their market share is dwarfed by the generation capacities of state-owned companies, which dominate the sector. There are 18 companies that cover electricity supply. Three of these companies are state-owned and hold the majority of the market share. In 2014, companies forming part of the state-owned HEP Group held a total of 85.75 per cent of the market share. The privately owned supply companies with the highest market share in 2014 were: GEN-I (approximately 6.07 per cent), RWE Energy (former Energija 2 Sustavi with approximately 4.52 per cent) and Proenergy (approximately 2.32 per cent). In the period of September 2013 to September 2014, non-state-owned companies more than doubled their market share to approximately 14 per cent.7


100 N/A 32.96 39.65

Sources: WSHPDR 2013,14 Energy Institute Hrvoje Pozar11,15 Note: The comparison is between data WSHPDR 2013 and WSHPDR 2016.

country’s renewable energy support scheme. As of July 2015, these projects have not yet begun commercial service. The projects are: the 1.4 MW Ilovac plant, developed by Tekonet, the 1.35 MW Prancevici plant on the Cetina River, developed by HEP-Proizvodnja, the 1.3 MW Cabranka 1 plant developed by EUCON, the 0.245 MW Letaj plant by Kapitol Grupa, the 0.155 MW Orljava plant by Mahe Hidroelektrarna, the 0.113 MW Glini plant by Najam Za VAS, the 0.150 MW Klipic plant by VIZMolendium, and the 0.225 MW Dabrova Dolina 1 plant by Kelemen Energija. In addition, Prancevici HEP is also planning to reconstruct two existing schemes: the 4.6 MW Fuzine and 1.7 Zeleni Vir plants.9

In general, electricity tariffs vary starting from approximately US$0.02 to US$0.132 for commercial users, and from approximately US$0.05 to US$0.1 for residential users; tariffs vary depending on the amount of electricity consumed. Additionally, all customers pay a separate feed-in tariff (FIT) of HRK 0.035/kWh (approximately US$0.005/kWh), except customers who must obtain the greenhouse gas emission permit pursuant to the Ordinance of the Croatian Government.8

Legislation on small hydropower Since 2001 coupled together with the adoption of the First Energy Package, the Government has transformed the energy sector by amending the Energy Act (2012) and by adopting the Electricity Market Act and the Act on the Regulation of Energy Activities (2013). In 2013, the Third Energy Package was adopted as well as a new Electricity Market Act (2013), and, in accordance with EU regulations, adopted the Energy Efficiency Act (2014). The licensing and tariff systems were updated in compliance with the new regulations.7

Small hydropower sector overview and potential The definition of small hydropower (SHP) in Croatia is up to 10 MW. Installed capacity of SHP is 32.96 MW (Figure 3).15 The technical potential for installed SHP is 177.1 MW with a potential generation of 567.7 GWh while the economically and environmentally feasible potential is about 100 MW and 350 GWh.11 It should be noted that feasibility studies were conducted on 63 watercourses; the potential for SHP will increase significantly after more studies are completed.

The incentive prices for SHP plants according to the Tariff System (Official Gazette No. 133/2013) are as shown on Table 1. As of 2015, only seven sites with a combined installed capacity of 1.6 MW were operating under the FIT, while the remainder did not fall under the incentive system.15 TABLE 1

SHP feed-in tariffs in Croatia by capacity

The first hydropower plant installed in Croatia was in 1895, when the 300 kVA Jaruga plant became operational. The plant was rebuilt in 1904 with an installed capacity of 5.4 MW and is still operational.12 Since that time, installed SHP capacity has increased six-fold.

Installed capacity

Developers of a total of eight SHP plants with a combined capacity of almost 5 MW have signed electricity offtake agreements with the market operator HROTE under the

US$/MWh

< 300 kW

154

300 kW to 2 MW

134

2 MW to 5 MW

126

5 MW to 10 MW

76

Source: Center for Monitoring Business Activities in the Energy Sector And Investments13

552


an additional obligation on project developers to install equipment acquired from suppliers and/or authorized representatives of suppliers based in Croatia.9

In 2013, the Government adopted a National Action Plan for renewable energy by 2020, with a greater emphasis on biomass, biogas, cogeneration and SHP. The goal is to increase the renewable energy share from approximately 16 per cent to 20 per cent by 2020. Also by 2020 Croatia aims to have the following share from renewables in total electricity production: 79.6 per cent from large and SHP, 10.5 per cent from wind farms, 8.3 per cent from biomass, 0.9 per cent from geothermal and 0.7 from solar plants.

The Government is currently debating a new Renewable Energy Act; as of 2015, the negotiations were still ongoing.13 Barriers to small hydropower development The SHP sector development needs high specific investments and faces limitations related to the environmental impact, historic-cultural heritage and landscape protection. In order to achieve the goals determined in the Energy Strategy, Croatia shall motivate the inspection of remaining watercourses to determine the exact location and potential for construction, facilitate administrative procedures to obtain the necessary permits to construct SHP plants (particularly for plants under 5 MW), and to harmonize energy legislation and other laws related to water management.10

Renewable producers who obtain the status of eligible producers and who conclude a power purchase agreement (PPA) with HROTE are entitled to receive the FIT for a period of 14 years. The transmission and distribution system operators are obliged to ensure the offtake of all electricity produced from renewable energy sources for up to 14 years. The new tariff system imposes

553

Southern Europe

4.3

4.3.4

Greece John Kaldellis and Stelios Liaros, Piraeus University of Applied Sciences (former TEI of Piraeus)


10,903,7041

Area

131,954 km2

Climate

Greece has a Mediterranean temperate climate presenting mild, wet winters and hot, dry summers. The year can be divided into two main seasons: the cold and rainy period, which lasts from mid-October until the end of March, and the warm and dry season, which lasts from April to October. During the colder period, the coldest months are January and February (average minimum temperature are between 5 and 10°C in coastal areas and 0 to 5°C in inland areas). In the north part of the country the winter is much stronger with temperatures occasionally falling as low as –20°C. In the months of July and August, average maximum temperatures lie between 29 and 35°C.2

Topography

Greece is a peninsular country, with an archipelago (Aegean) of about 3,000 islands. The peninsular coastline measures almost 15,000 km. The Pindus mountain range lies across the centre of the country in a north-west to south-east direction, with a maximum elevation of almost 2,650 metres. Central and western Greece feature high and steep peaks intersected by many canyons and other karstic landscapes, including the Meteora and the Vikos Gorges—the latter being one of the largest in the world, plunging vertically for more than 1,100 metres. Mount Olympus is the highest point in Greece rising to 2,919 metres above sea level.2

Rain pattern

Rainfall in Greece even during winter does not last for many days and winter storms usually end by mid-February. Average annual precipitation varies between 500 and 1,200 mm in the north and between 380 and 800 mm in the south.2


The most important rivers in Greece are: Evros, Nestos, Strimon, Axios, Aliakmon, Penios, Arachtos, Acheloos, Sperchios and Alfios. The Acheloos has a considerable water flow of approximately 300 m3/sec in December, while the flow rate of the Axios is almost 230 m3/sec in March. The flow rate of the Evros varies between 200 and 220 m3/sec from January to March.16 The total domestic water resources are estimated at 85 TWh/year while the annual specific theoretical hydropower potential of Greece accounts for 0.73 GWh/km2. The technically and economically exploitable hydropower potential is estimated at an annual level of 21 TWh/year.

Electricity sector overview The national Electricity Generation System (EGS) is divided into two main sectors, the interconnected system of the mainland and the autonomous power plants of the Aegean Archipelago islands. Concerning the Archipelago region, the Greek EGS is composed of approximately 40 local Autonomous Power Stations (APSs) which consume imported fuel (diesel and heavy oil).4 The mainland’s electrical grid, in addition to the 16 large hydro installations (3.02 GW), is mainly supported by thermal power stations (TPSs) with a total rated capacity of 9.5 GW, with almost half of them using indigenous lignite and 4.9 GW using imported natural gas.9 Lignite power units contribute almost 45-50 per cent on an annual basis, while the total electricity generation in Greece (including the autonomous islands) was 50.3 TWh in 2014, which was considerably lower than in 2008.


In 2013, installed capacity in Greece was 19,604 MW, including natural gas (4,906 MW), renewable energy sources (RES) (4,743 MW), lignite (4,456 MW), large hydropower (3,018 MW), diesel (1,783 MW) and oil (698 MW) (Figure 1).3 FIGURE 1

Installed electricity capacity by in Greece by source (MW) Natural gas

4,906 4,743

Other RE sources Lignite

4,456

Large hydropower

3,018

Diesel Oil

1,783

Across the interconnected system (excluding the autonomous islands) the share of renewable energy sources (RES) (including large hydropower) reached approximately 23 per cent during 2014. Recently, the installed RES-based

698

Source: Ministry of Environment and Energy3 554


capacity exceeded 8 GW, although the small hydropower (SHP) contribution remains almost constant.15 The electrification rate in Greece is 100 per cent.

The definition of SHP in Greece is up to 15 MW. Installed capacity of SHP is 223 MW while the economic potential is estimated to be 2,000 MW indicating that approximately 11 per cent has been developed. Between World Small Hydropower Development Report (WSHPDR) 2013 and WSHPDR 2016, installed capacity has increased by approximately 14 per cent and potential capacity has not changed.

The significant increase in GDP during 2000-2008 was accompanied by a corresponding increase in electricity consumption, which peaked at the level of 57 TWh during 2008. Subsequently, the economic crisis led to a significant decline in consumer activity resulting in a reduction of both GDP and electricity demand in 2014 down to the levels of 2000. Given the continuing economic uncertainty, the demand for electricity is not expected to recover any time soon.

FIGURE 2

Small hydropower capacities 2013-2016 in Greece (MW)

A series of legislative reforms were attempted in order to liberalize the state monopoly. The undertaken efforts have not led to deep changes. The Public Power Corporation (PPC) maintained its dominant position in the electricity sector, while the main effect of the predefined tender system for meeting the demand for the next 24 hour period was a significant increase in imports of cheap electricity from the Balkan countries neighbouring Greece in the North. During 2014, net electricity imports exceeded 8.5 TWh, accounting for 18 per cent of the domestic energy consumption.

Potential 2016 2013

2,000 2,000


223 196

Sources: Ministry of Environment and Energy,3 WSHPDR 201314 Note: The comparison is between data from WSHPDR 2013 and WSHPDR 2016. Data is for up to 15 MW.

In recent years, the electricity sector has been characterized by several factors including the pressure of withdrawing, due to environmental and economic grounds, the old thermal units (the lignite fired plants of Megalopolis and Ptolemais and the natural gas fired plant of Lavrio); the rapid penetration of 2,500 MW of photovoltaic systems in just two years (due to the particularly high feed-in tariffs (FITs)); and the support provided for the creation of large wind farms, mainly in the Greek archipelagos islands, along with the extensive plans for subsea interconnection of the islands with the mainland.

In 2014, the total hydropower electricity generation accounted for about 3.8 TWh, i.e. 3.1 TWh from large and 0.7 TWh from SHP stations, contributing 7.5 per cent in the total electricity consumption. From data available, there are approximately 230 SHP plants with a total installed capacity of 223 MW, which is approximately 7.3 per cent out of total hydropower installed capacity. During 2009, installed SHP capacity was approximately 182 MW, demonstrating a limited increase in the range of 7 MW/year which corresponds to the creation of five to 10 SHP plants annually. It is worth noting that of the total installed capacity, only 95 MW correspond to projects with a nominal output of more than 5 MW while the remaining 34 MW are composed of mini and micro projects with a nominal capacity below 1 MW. Correspondingly, the annual electricity production from SHP is increasing slightly from 0.66 TWh in 2009 to 0.7 TWh in 2014, while the estimated average load factor of SHP projects varies between 35 per cent and 45 per cent, almost three times the corresponding value of large hydropower plants in the same period. The technically and economically exploitable hydropower potential is estimated at 21 TWh/year.

Although the Ministry of Reconstruction of Production, Environment & Energy supported the creation of new lignite-fired power plants, the protests of environmental organizations and the unfavourable economic situation coupled with a significant decrease in demand for electric power are expected to delay the implementation of similar projects. Moreover, in the context of the European objectives for 2020, Greece will have to cover 40 per cent of its domestic electricity consumption from renewable sources. At the end of 2014, the RES contribution did not exceed the range of 20 to 23 per cent. While the cost of electricity generation is based on the respective System Marginal Price, the price of electricity to consumers is controlled by the Government, which often cancels or modifies the values suggested by the competent bodies. Finally, it is worth noting, that since 1994, there has been a predetermined purchase price for electricity from RES, which is also prioritized for purchase by the electrical system unless technical constraints appear. For example, considering the case of the production by SHP plants, the relative price varies at the levels of EUR 90/MWh (US$90/MWh), adjusted every year by a ministerial decree.

A large portion of water resources is concentrated in the western and northern parts of the mainland where one may find the majority of hydropower plants installed.6 Similarly, all the SHP stations are located in the northern and western parts of the country.7 Regarding the geographical distribution of SHP plants, the majority of them are located in Central Macedonia (exploiting the waters of the rivers from the north), Epirus (exploiting the rugged terrain of the region) and western Greece in general.8

555

Southern Europe

4.3



With a national target for 2020 of 350 MW of SHP installed capacity, there is a significant number of projects awaiting implementation. Approximately 130 MW already have binding connection offers while 280 MW are under approval. According to the current estimates of implementation, by 2020 the total SHP capacity will be just over 250 MW.

One of the major drawbacks decelerating SHP penetration in the local electrical market is the administrative bureaucracy. Despite the efforts of the Greek State, there is a substantial number of documents that one should provide in order to start the construction of a new SHP station. In fact, for obtaining the final licence an investor needs to wait for an extended period (usually up to 3 years).12

Although SHP projects do not face significant environmental problems or social reaction as is the case with large hydroelectric plants whose development in Greece faces serious obstacles, there is no serious state encouragement for their implementation.10 The initial development cost of an SHP plant ranges from EUR 0.8 million/MW to EUR 1.5 million/MW with the most likely value corresponding to EUR 1.2 million/MW (0.89 million, 1.67 million, 1.3 million US$/MW).11,12 During the last decade, state subsidization of SHP projects accounted for up to 40 per cent of the initial capital for new SHP projects.11 Even with that incentive policy, SHP projects are an economically efficient investing option, as attested to, by the investor’s interest even today.

An additional serious obstacle for the creation of a considerable number of new SHP plants is the absence of an integrated national water management plan. This problem hinders the exploitation of potential small hydro locations of the country. In most cases examined, the water potential exploitation status is totally unclear, hence local municipalities and agricultural cooperatives raise exclusive or preferential proprietary rights on the existing water resources. Essentially, in some cases local municipalities and agricultural cooperatives exercise pressure, via their political influence, on the utilization planning of the available water potential. Thus in several cases SHP plants cannot operate continuously since the electricity production is not a priority. However, via careful and fair water potential management one may cover the parallel requirements of local communities/ unions without zeroing the electricity generation from SHP plants of the area.

Renewable energy policy The Greek State, since implementing the European policy for independence from imports and reduction of environmental impacts of fossil fuels, officially supports the further penetration of RES in the domestic energy balance. In this context some ambitious and often poorly rated objectives have been set up, which mainly include the massive installation of large wind farms (estimated installed capacity of 7-8 GW by 2020) and the installation of solar photovoltaic panels (estimated installed capacity by 2020 of 2.5 GW). In both cases, serious problems have been experienced, in particular the lack of electrical networks and negative social reactions to the establishment of large wind farms have limited the installed wind power at the level of 2 GW, through 2015.9

Taking into account the relatively small size of the installations and the corresponding limited budget, most big energy-related construction companies are not showing much interest in similar small size projects. Hence, the development of small or mini hydropower installations is realised by small private companies with limited socio-economic influence on the local and national level. These relatively small firms have neither the necessary know-how nor the technical equipment to optimize their plants. Only in case of a number of successive SHP stations along the same river one may take advantage of scale economies. The result of this situation is the remarkable construction time required and the violation of the initial budget. Additionally, in many cases, the developed SHP stations are oversized, since the subsidy amount depends only on the installed power of the station and not on the corresponding energy yield. In these cases, the existing SHP stations do not operate for a considerable period of the year due to the low water volume rate available and the operational restrictions imposed by the hydro turbines of the installation, in order to avoid increased wear and maintenance of the equipment.

Correspondingly, the installed capacity of PV panels by the end of 2014 exceeded the targets of 2020, bringing the State to a position of limiting the uncontrolled dynamics of the domestic market by both dramatically reducing the electricity purchase price (which in 2012 stood at the very high for the interconnected grid value of EUR 0.5/kWh (US$0.56/kWh)) and by imposing a retroactive taxation of 30 per cent on revenue of PV stations for the years 2012 and 2013. In this context, the utilization of water resources experienced a lack of governmental interest, as large hydro faced persistent reaction of local communities and small hydro was not considered capable of significantly changing the national energy mix.

556

4.3

Italy

Southern Europe

4.3.5

Gianluca Lazzaro, University of Padova


61,336,38711

Area

301,340 km2

Climate

Cold winter, hot and humid summer in the north; mild winter in central Italy; very hot summers and very mild winters in the south and in the islands. Average temperatures are between 3°C (north) and 14°C (south) in January and between 28°C (north) and 30°C (south) in July.10

Topography

The country can be divided into four topographic regions: north of the peninsula, the central region, the southern region and the islands. The territory is mostly mountainous; the Alps are the northern boundary of the country and the Apennine Mountains represent the backbone of the peninsula; the largest plain is the Po Valley (71,000 km2); the highest peak is Monte Bianco (4,810 metres above sea level).10

Rain pattern

Mean annual rainfall is about 1,000 mm; highest values occur in the north-east (> 2,000 mm); in the islands and in the south, rainfall rarely exceeds 500 mm per year.10


Rainfall is mainly lost due to evaporation (about 500 mm per year); water consumption also reduces runoff availability (385 litres per capita per day). The longest and most important river is the Po, which is located in the northern regions along with the Adige River. In the central region, the most influential are the Reno and Arno Rivers, while in the south it is the Bradano River.10


decreasing trend (2.5 per cent less than in 2013) which was observed in the previous year (3.0 per cent less than in 2012).1 This trend is strongly influenced by the decline of energy demand for industrial production, mainly driven by a declining economy. In 2013, the Gross Domestic Product (GDP) decreased (–1.9 per cent) for the second consecutive year (–2.5 per cent in 2012). Moreover, slight declines were also observed in tertiary (first time since 1963) and domestic consumption.2

In 2014 electricity generation was 269,148 GWh and satisfied about 86 per cent of the national demand (310,535 GWh).1 Imported electricity provided the remaining fraction (43,716 GWh).1 Renewable sources (hydropower, solar and wind) have become increasingly important since 2011 thereby reducing the use of fossil fuels (Figure 1).

In Italy, private companies manage the production, transmission and distribution of electricity. Competition in these sectors is allowed and promoted by the Authority of Electricity and Gas (AEEG, Law 481/1995). Terna S.p.A. is the Transmission System Operator and owns the whole national high-voltage transmission grid. Eleven other companies are involved in the management of low-voltage grids at regional levels. In 2013, 138 distribution companies were employed. In particular, Enel Distribuzione S.p.A. provided electricity to the largest portion of domestic and industrial users (86 per cent).2

FIGURE 1

Electricity generation in Italy by source (GWh) Thermal power

167,080

Hydropower Solar power Wind power Geothermal

59,575 21,838 15,089 5,567

Source: Terna 1

Approximately 6.3 per cent of the produced electricity was lost along transmission and distribution networks (19,451 GWh).1 Moreover, several connection lines are now insufficient and often suffer congestion. Therefore, investments are needed to improve the aging energy infrastructure in order to increase the efficiency of networks and guarantee power supply for new users. The electrification rate is 100 per cent.

Net generation capacity in 2014 was 121,762 MW (2.2 per cent less than in 2013), which includes thermal (68,417 MW), hydro (21,979 MW), solar (18,609 MW), wind (8,683 MW), other (4,074 MW). Minimum and maximum annual grid load values observed in the same year were 18.7 GW and 51.6 GW (12 June 2014).3 The national electricity demand in 2014 confirmed the

557


}} M ini hydropower: between 0.1 MW and 1 MW; }} SHP: between 1 MW and 10 MW.

The Government’s plans mainly involve the reduction of fossil fuels for electricity production and the safety of power supply, which has been recently imperilled by conflicts in Libya and Ukraine. Consequently, the diversification of sources for energy production and the promotion of renewable energy (RE) are objectives of the Government.

FIGURE 2

SHP capacities 2013-2016 in Italy (MW) Potential

The first regulated electricity market in Italy was introduced in 2004. The electricity market, commonly called the Italian Power Exchange (IPEX), enables producers, consumers and wholesale customers to enter into hourly electricity purchase and sale contracts. The market, regulated by the Energy Market Manager (GME), mainly consists of the Day-Ahead Market (MGP) whose trades involve electricity for the next day. GME is the central counterparty in the transactions concluded in the MGP. Then, sell/purchase proposals may be changed during following electricity market sections.

2016 2013

7,073 7,066


3,173 2,735

Sources: WSHPDR 2013,9 World Energy Council8 Note: The comparison is between data from WSHPDR 2013 and WSHPDR 2016.

In 2014, there were 2,304 micro and mini hydropower plants in operation with an installed capacity of 679 MW, and 825 SHP plants with a capacity of 2,494 MW.5

In 2014, the Italian electricity market was characterized by a mean electricity price of EUR 52/MWh (US$57/MWh), with a decrease of 17.3 per cent compared to 2013 (the lowest ever seen since the introduction of the market).4 This decrease in the price mainly reflected the reduction of the electricity demand (primarily a consequence of economic difficulties) and the growth of renewable sources of energy.

Italy is the leading European country for installed capacity and electricity generation, taking into consideration hydropower plants with less than 10 MW.6 The energy produced by all SHP plants in 2014 was 14,141 GWh (3,148 GWh by micro and mini HP and 10,993 GWh by SHP).3 The number of micro and mini plants rose by 8.2 per cent compared to 2013, and the number of small plants rose by 1 per cent. The same comparison in terms of energy produced is meaningless as inter-annual climatic fluctuations strongly affect the water resources available for HP plants.

A reduction in the mean electricity price occurred in all regions in 2014 compared to 2013: EUR 52/MWh (15 per cent less) in the continental region, EUR 52/MWh (15 per cent less) in Sardinia, and EUR 81/MWh (12 per cent less) in Sicily (57, 57 and 90 US$/MWh, respectively).4

Large hydropower plants (greater than 10 MW) still represent the most important source of hydroelectricity in the country. Thus, in 2014 large hydropower plants produced about 44,404 GWh (76 per cent of the total hydropower generation).7

The electricity price in Italy is greater than that observed in other European markets, which ranged between EUR 33/MWh (US$36/MWh) in Germany and EUR 42/MWh (US$46/MWh) in Spain in 2014.4 Italy strongly depends on gas, which is the most expensive source, and thus suffers from the increase in gas prices more than countries characterized by a better-balanced mix of electricity sources.

The gross hydropower potential in Italy is estimated to be about 200 TWh/year, of which 38 TWh/year is associated with SHP.8 Technical and economic constraints reduce the HP potential production to about 50 TWh/ year.8 Estimates of the technical SHP potential range between 12.5 TWh and 20 TWh.6,8 The potential installed capacity available is around 3,900 MW.6 Interestingly, although the potential for additional development in Italy is low compared to that of other countries, future policies will likely favour additional HP development.

Small hydropower sector (SHP) overview and potential The definition of small hydropower (SHP) in Italy is up to 10 MW. Installed capacity of SHP is 3,173 MW, while the economic potential is estimated to be 7,073 MW, indicating that approximately 45 per cent has been developed. Between World Small Hydropower Development Report (WSHPDR) 2013 and WSHPDR 2016, installed capacity has increased by approximately 16 per cent while estimated potential has increased by less than 0.1 per cent (Figure 2).

Renewable energy policy Italy has placed the growth of renewable sources of energy among the priorities for the energy development of the country. In accordance with the EU Directive 2009/28/CE, in 2020, 17 per cent of the total energy demand of the country will be provided by RE.

SHP plants are classified according to their maximum capacity as: }} Micro hydropower: less than 0.1 MW;

The National Renewable Energy Action Plan (2010) has

558

defined the strategies to achieve the targets prescribed by the EU and established the expected growth from 2010 to 2020 of the installed capacity and the energy production for each renewable source of energy.

The unexploited hydropower potential is thus associated with SHP. This sector has become increasingly important during the last decade thanks to the Government’s policies, which have caused rapid installation of new SHP plants beyond expectations.

Moreover, RE will play an important role in reducing CO2 emissions by 40 per cent, to 70 per cent below 2010 levels, by 2050. This target was established at the G7 leader’s summit in June 2015 and will lead to the decarburization of the global economy over the course of this century in Italy as well as in other countries worldwide.

SHP growth has been driven by comprehensive FIT (EUR 0.22/kWh for 15 years; US$0.24/kWh) introduced in 2008 as an alternative to Green Certificates for plants with a capacity up to 1 MW. In July 2012, a ministerial decree introduced a new support scheme for SHP plants. FIT (and subsidized period) actually depends on the maximum capacity (P) and is also provided for plants up to 10 MW according to the following scheme: }} 1 < P ≤ 20 kW: EUR 257/MWh (US$285/MWh) (20 years); }} 20 < P ≤ 500 kW: EUR 219/MWh (US$243/MWh) (20 years); }} 500 < P ≤ 1,000 kW: EUR 155/MWh (US$172/MWh) (20 years); }} 1,000 < P≤ 10,000 kW: EUR 129/MWh; }} US$143/MWh for 25 years.

Since 2012, the Government has introduced an annual threshold on RE incentives, which is EUR 5.8 billion (US$6.4 billion) (not including solar energy). Several RE development schemes actually exist in Italy: (a) CIP6 (1992) CIP6 was the first system of incentives for RE adopted in Italy. It is no longer in use but there are plants that still benefit from this system. The increase of installed RE capacity thanks to CIP6 has been estimated at 6.5 GW (b) Green Certificates (1999) New RE plants receive a number of GC according to their energy production (1 GC = 1 MWh). GC can be sold to industries that are required to produce a fraction of energy with renewable sources, but are not able to do it on their own. GC average annual price ranged between 80 and 120 EUR/MWh (90 and 135 US$/MWh) (excluding VAT) 4

However, laws prescribe the maximum annual installed capacity for each source of energy. In particular, no more than 70 MW of additional hydropower capacity can be installed each year. If new SHP projects exceed the annual capacity growth threshold, plants are ranked and feed-in tariffs are guaranteed only for those having less environmental impact. Plants producing less than 50 kW avoid this procedure and are supported by feed-in tariffs, and the payback period for SHP investments is approximately 5 years.

(c) Feed-in Tariffs (FITs) (2008) FITs include electricity prices and incentives, and are guaranteed for several years after the activation of the plant. Small producers usually prefer this support scheme because GC markets can be very complex. FITs simplify financial planning for plants with a small capacity

A new support scheme will begin in January 2016, probably reducing the annual hydropower production threshold and feed-in tariffs.



The National Renewable Energy Action Plan (2010) predicted an overall hydropower production of 42 TWh in 2020. Even though this goal has already been achieved, major efforts will be made in compensation for the reduction of the efficiency of large HP plants (some of them were built 100 years ago) with the construction of new SHP plants. In fact, the Government expected the SHP generation to grow from 9.2 TWh in 2010 to 12.08 TWh in 2020. However, SHP electricity production in 2014 already surpassed this target.12

The main barriers to SHP development regard the following: (a) Authorization process The authorization process in Italy lasts on average 2-3 years. Permissions (water concession, construction licence, etc.) come from different departments. Moreover, there is no substantial difference between the water concession for small and large HP plants. Finally, the recent introduction of a threshold on the annual installed capacity (and consequently the ranking procedure for competitive plants) has slowed down the process even more.

The development of Italian hydropower production in the 20th century has been typically associated with the construction of conventional plants that rely on large dams, which induce dramatic changes in the landscape and significant alteration of river discharges. However, conventional HP plants are close to saturation in most EU countries, including Italy.

(b) Environmental requirements Even though SHP inflicts a smaller impact on aquatic ecosystems and local communities compared to large dams, it cannot prevent stresses on plant, animal, and human well-being. Additionally, the

559

Southern Europe

4.3


negative cumulative effect of SHP plants operating along the same river threatens the ability of stream networks to support biodiversity. Currently, the prediction of the long-term impacts associated with the expansion of SHP projects induced by globalscale incentive policies remains highly uncertain.

must be placed on combining energy/monetary needs with environmental preservation. Small hydro technology is likely to gain a higher social value in the next decades if the environmental and hydrologic footprint associated with the energy exploitation of surface water will take a higher priority in civil infrastructure planning.

Although limiting HP exploitation, environmental regulations are thus needed to preserve river networks. An example is the regulation of the Minimum Environmental Flow (MEF), which was established by Water Authority. Weirs crossing the river must also be equipped with fish passages allowing migration. Moreover, SHP plants with a capacity larger than 100 kW are required to undergo an Environmental Impact Assessment (EIA).

(c) Social conflicts Social movements against SHP are growing in Italy, especially in the northern region (Alps). Usually concentrated in less developed, mountainous areas, the hydroelectricity generation is associated with negative externalities in proximity to the plants, and the downstream communities take most benefits. The goal of these movements is to prevent further exploitation of mountainous river networks that are already altered by water regulation due to dams. There are examples of new SHP plants that have been stopped or delayed because of this opposition.

Given the recent expansion of SHP plants in Italy and the disturbance on river ecosystems, an emphasis

560

4.3

Montenegro

Southern Europe

4.3.6

Igor Kovacevic, Montconsult


625,2661

Area

13,812 km2 1

Climate

A Mediterranean climate in the south and the Zetsko-Bjelopavlicka plain regions are characterized by long, hot and dry summers between June and August and relatively mild and rainy winters between December and February. The north has a continental climate with large daily and annual temperature variations and low annual rainfall. Average temperatures range from –0.9°C in January to 18.8°C in July.2

Topography

Topography ranges from high mountains in the north of the country falling to a narrow coastal plain on the Adriatic Sea in the south and south-west. There are a number of peaks exceeding 2,000 metres including Bobotuv Kuk which, at 2,523 metres, is believed to be the highest point in the country. The coastal region is noted for its active seismicity.2

Rain pattern

Mean annual precipitation in Montenegro is 1,745 mm. However, this ranges from 777 mm to 4,580 mm, which is the highest precipitation level in Europe. The lowest precipitation is in the north and the highest in the central regions where continental and Mediterranean climate conditions meet.3


Significant rivers of Montenegro include the Drina, Tara and Lim. Several rivers, including the Tara, Piva, and Moraca, pass through mountainous areas and have carved valleys or canyons, some up to 1,200 metres deep. The largest lake is Lake Skadar, and is shared with Albania; the lake combined with Zeta Valley provides the most fertile area in the country.3


cent less than in 2013, when precipitation was higher than usual. Total electricity demand in 2014 was 3,546 GWh. Montenegro has a 100 per cent electrification rate.4

Total installed capacity is approximately 867 MW. The majority is provided by two large hydropower plants, Perucia (307 MW) and Piva (332 MW), contributing approximately 74.4 per cent with a thermal power plant, Pljevlja (210 MW), contributing 24.4 per cent (Figure 1). The remaining installed capacity is provided by small hydropower (SHP) plants. Perucica and Piva began operating in 1960 and 1976 and have average annual productions of 853.6 GWh and 737.3 GWh respectively. Pljevlja began operating in 1982 and has an average annual production of 1,400 GWh.4

The electricity sector in Montenegro has been in transition over the past decade. Montenegro is a candidate country for the European Union (EU) and a contracting party of the Energy Community Treaty. As such it has an obligation to follow the EU policy in energy and the environment. Elektroprivreda Crne Gore (EPCG) is a vertically integrated company operating as the distribution system operator, public supplier and owner of all major generation units in Montenegro. Previously EPCG was also responsible for transmission however, in 2009, Crnogorski elektroprenosni sistem (CGES) was established as the transmission system operator, which separated transmission from EPCG. Both companies are owned by the State of Montenegro with a majority share of 55 per cent. The major minor shareholders are A2A, with 43 per cent of EPCG, and CGES Terna with 22 per cent of CGES. Both are Italy-based.

FIGURE 1

Installed electricity capacity in Montenegro by source (MW) Large hydropower

639

Thermal power Small hydropower

210 18

Source: Government of Montenegro4

The transmission network was originally part of the exYugoslavian 400 kV cycle and today the Government wants to extend this network to become an electricity hub in South-eastern Europe. In 2011, a new 400 kV transmission line was constructed between the capital, Podgorica, and Tirana, the capital of Albania.

Planned electricity generation in 2014 was 3,108 GWh with 1,702 GWh(or 55 per cent), generated from hydropower.4 Annual net electricity import was expected to be 441 GWh. The total electricity generation in 2014 was 3,105 GWh, 5 per cent less than planned and 20 per 561


Furthermore, a 375 km long undersea electricity cable between Italy and Montenegro with converter stations on both coasts, overhead 400 kV lines in Montenegro and interconnection lines to Serbia and Bosnia and Herzegovina are under development.

SHP installed capacity of 9 MW was derived from 7 plants owned and operated by EPCG. There is no specific focus of EPCG on these small facilities and their operating condition is poor. In 2007, however, the Government began giving concessions to private investors for SHP construction. This agreement includes development, construction, operation and maintenance for up to 30 years after which all equipment and facilities transfer to state ownership. As of 2015, six SHP plants have been constructed by private investors and are operational. These SHP plants are the first new electricity generators to be installed in 30 years and have a combined installed capacity of 8.8 MW and an estimated electricity generation of 28 GWh.8

The distribution system is undergoing significant development with a focus on the implementation of an advanced management system that includes replacing old electricity meters with smart meters. EPCG plans to replace 240,000(or 86 per cent), of active electricity meters by the end of 2016. At the same time, reconstruction of the low-voltage network is ongoing. As a result, the electricity losses from the distribution network are constantly decreasing (16.8 per cent in 2014).

FIGURE 2

Based on decisions of the Regulatory Energy Agency (REA) from 2009 and the 2010 Law on Energy, the electricity market was opened up in 2015, including for households. Currently, only EPCG is active on medium and low-voltage levels.

Small hydropower capacities 2013-2016 in Montenegro (MW) Potential 2016 2013

The REA is responsible for determining tariffs and prices on medium and low-voltage levels for electricity supplied by EPCG. The retail price for distributed consumer categories is calculated based on: active electricity, engagement of transmission and distribution capacities, transmission and distribution network losses, fixed fees for electricity system operators and VAT. Active electricity and network losses are defined for high-tariff (07:00-23:00) and low-tariff (23:00-07:00 and Sundays) periods, whereas tariffs for network capacities are not dependent on time periods. The retail electricity prices for the distributed customer category, valid from August 2014, are EUR 0.104 (US$0.139) per kWh and EUR 0.072 (US$0.096) per kWh, for high and low tariffs respectively. The VAT in Montenegro is 19 per cent.

97.5


240.0 17.8 9.0

Sources: Green Home and World Wide Fund,8 WSHPDR 201311 Note: A negative change can be due to access to more accurate data. The comparison is between data from WSHPDR 2013 and WSHPDR 2016.

As of 2015, 43 new, privately owned, SHP plants, including the 6 operational plants, have been approved with a combined capacity of 83 MW and an estimated generation of 269 GWh. Four tenders for concessions have been undertaken since 2007 resulting in the approval of 14 valid concession agreements to construct 30 SHP plants with a combined installed capacity of 75 MW and an annual generation of 236 GWh (Table 1).8


In order to improve and accelerate the authorization process for renewable energy sources, a new and simple procedure for authorizing the construction of SHP plants with an installed capacity of up to 1 MW was established. Under the current regulation, energy permits can be issued for plants up to 1 MW on rivers with a generation potential less than 15 GWh.7 As of July 2015, 13 energy permits were issued under this scheme (Table 1).8

In Montenegro an SHP installation is defined as a plant with an installed capacity less than 10 MW. The current installed capacity of SHP is 17.8 MW with a total potential of at least 97.5 MW, which is planned to be harnessed by 2019. Therefore, approximately 18 per cent of the discovered SHP potential has been developed so far (Figure 2).8

Planned reconstruction by EPCG is also outlined by the Energy Development Strategy until 2030 to bring existing EPCG plants up to a combined capacity of 11.4 MW. By

SHP represents approximately 3 per cent of total hydropower capacity in Montenegro. Prior to 2014, the

TABLE 1

Overview of approved small hydropower plants as of 2015 Type of agreement

Number of contracts

Number of sites Estimated capacity (MW)

Estimated generation (GWh)

Tender

14

30

74.72

236.18

Energy permit

13

13

8.69

32.82

27

43

83.41

269.00

Total Source: Green Home and World Wide Fund

8

562


2019, it is planned to achieve a total installed SHP capacity of 97.5 MW with 11.2 MW from plants up to 1 MW and 86.3 MW from 1-10 MW plants.8 However, the actual potential figure is likely to be significantly higher. The Energy Development Strategy includes data from the 2001 Water Master Plan which estimates the overall theoretical hydropower potential of Montenegro as between 10.6 TWh and 10.8 TWh and the technical potential between 5.0 TWh and 5.7 TWh until 2030 (Table 2).

The NREAP also defines targets for different types of renewable energy. Total installed capacity from hydropower is planned to total 826 MW with an annual generation of 2,050 GWh by 2020. Installed capacity of SHP plants is planned to total 97.5 MW with an annual generation of 287 GWh (Table 3). With the new approved and reconstruction projects expected to increase SHP to 94.8 MW, the country is close to achieving this objective.

TABLE 2 TABLE 3

Theoretical and technical hydropower potential Source

Theoretical potential Technical potential (TWh) (TWh)

Main rivers

9.8

4.6-5.3

Small rivers

0.8-1.0

0.4

Total

National goals for construction of small hydropower plants up to 2020

10.6-10.8

Plant size

5.0-5.7

Source: Strategy of Energy Development of Montenegro up to 20305

Capacity (MW)

Generation (GWh)

Up to 1 MW

11.2

35

1-10 MW

86.3

252

Total

97.5

287

Source: National Renewable Energy Action Plan Up To 20209

However, the theoretical and technical potential of small rivers could be underestimated. Beginning in 2007, Montenegro has made in-situ hydrometric measurements at locations on small rivers that could be used for the construction of SHP plants. Three series of one-year measurements were finished for approximately 40 locations on 35 rivers. The programme continues and today hydrometric measurements are ongoing.

Further development of renewable policy has also been undertaken with a new energy law adopted in 2010 and a renewable energy regulatory framework set up between 2010 and 2012, which has established a feedin tariff scheme based upon European regulations. New producers from renewable sources receive the status of privileged producers for 12 years entitling them to feedin tariffs and priority delivery. Feed-in tariffs for SHP are based on annual electricity generation and favour the construction of smaller facilities (Table 4).10 In addition, a flat rate feed-in tariff of EUR 0.07/kWh (US$0.09/kWh) has been established for refurbished SHP plants.10

Moreover, in 2010, hydrometric measurements on the smallest rivers were started, specifically on small rivers most suited to the development of SHP plants with an installed capacity less than 1 MW. Aside from past and ongoing measurements, the state hydrometric measurement network is continuously improving in terms of the number of automatic hydrometric stations and the quality of the equipment. Therefore, it is expected that the estimated hydropower potential on individual water streams will become higher and more reliable.

TABLE 4

Feed-in tariffs for small hydropower plants Annual generation


Feed-in tariff (Euros (US$) per kWh)

Up to 3 GWh

0.1044 (0.1391)

3-15 GWh

0.0744 (0.0991)

More than 15 GWh

0.5040 (0.0671)

Source: Government of Montenegro (2011)

10

The Strategy for Energy Development in Montenegro up to 2030 defines technologies for electricity generation in the period up to 2030. New facilities for electricity generation are planned from coal, hydro, wind, solar power and biomass. Hydropower will still be the dominant source for electricity generation. Existing hydropower plants will be reconstructed and new plants constructed.

Barriers to small hydropower development Although the Government has taken an active role in improving the legislative and development processes for SHP, many obstacles to developing an attractive environment for investment still remain. These include: }} Missing general and strategic water plans; }} Disagreement between strategic plan documents in energy, water and environment sectors and the national and local spatial plan documents; }} Weak distribution networks in regions where SHP potential is highest; }} Weak administrative capacities in water, ecological and energy institutions that deal with this issue.

In addition, the National Renewable Energy Action Plan (NREAP) up to 2020 was adopted in 2014.9 Based on the Energy Community Ministerial Council Decision D2012/04/MC-EnC, Montenegro is obligated to adopt Renewable Energy Directive 2009/28/EC and establish a national target of 33 per cent of total energy consumption and 51.4 per cent of total electricity consumption from renewable energy sources by 2020. 563

Southern Europe

4.3

4.3.7

Portugal Paulo Alexandre Diogo and António Carmona Rodrigues, New University of Lisbon


10,374,8221

Area

92,225.6 km2 1

Climate

Portugal is characterized by a temperate climate with hot and dry summers between June and August in the south, and dry and mild summers in the north. Average annual temperature varies from 7 oC in the northern regions of the country and 18 oC in the southern regions.1

Topography

The centre and north of Portugal are mountainous regions with several mountain chains reaching as high as 1,500 to 1,900 metres. In the south plains are characteristic although some high mountains can also be found. At 1,993 metres, Serra de Estrela is the highest point in mainland Portugal. However, the summit of Mount Pico, on the Azores, is higher at 2,351 metres.3

Rain pattern

Total annual precipitation ranges between 2,400 mm and 2,800 mm in the north-western coastal mountains to 400 mm in the south. In the south monthly variations are more intense and 80 per cent of precipitation tends to occur during the wet season, typically from October to March, with November and December generally the wettest. July and August are the hottest and driest months.3


Transboundary river basins in Portugal represent around 64 per cent of the country’s territory, with the largest rivers being the Tagus, Douro and Guadiana; the main rivers within the territory of Portugal are the Mondego, Vouga and Sado. In 2005 the country’s total water dissipation per inhabitant was 6,545.97 m3/year. River flows have high seasonal variations due to precipitation patterns, mainly in the south of the country, and hydropower dam operation occurs mainly in the north.3


since 2005, mostly as a result of increasing hydropower installed capacity and production.

In 2014, total electricity generation in Portugal was 48,999 GWh. In 2013 installed capacity was 17,404 MW comprising 5,335 MW of hydropower, 4,731 MW of wind power, 4,991 MW of gas, 1,871 MW of coal and cogeneration plants, 447 MW of solar and 29 MW of geothermal power (Figure 1).13

The electrification rate in the country is close to 100 per cent and the overall energy mix is strongly influenced by the transport sector, which represents 36 per cent of primary energy consumption and 73 per cent of total oil demand for energy purposes.10 The privatization process of the energy sector has been recently concluded, partly as a result of the bailout process enforced between 2011 and 2014. Accordingly, the main energy company Energias de Portugal (EDP) became completely independent from the State with the China Three Gorges Corporation becoming the main shareholder with 21.35 per cent control. In 2014, the privatization of the electricity grid infrastructure was also concluded, with the State Grid of China becoming the main shareholder with a 25 per cent share. EDP remains the main electricity distributor although the energy market is being gradually liberalized.

FIGURE 1


Installed electricity capacity in Portugal by source (MW) Hydropower

5,335

Gas

4,991

Wind power

4,731

Coal Solar power Geothermal

1,871 447 29

On the Portugal mainland, transmission is handled by a single company, Rede Eléctrica Nacional (REN) while most of the distribution networks are handled by, EDP Distribuição, and also by some low-voltage electricity distribution operators. Electricity suppliers are responsible for managing the relations with end

Source: Direção Geral de Energia e Geologia13

Having no fossil fuels available in the country, Portugal must import most of its required energy, this is demonstrated by a rate of energy dependence of 79.2 per cent (2012).1 This dependence rate has been reduced 564

consumers, including billing. In Portugal, mainland electricity can be sold on a liberalized market, through free suppliers, and on a regulated market, through the last resort supplier. In 1998, the Portuguese and Spanish Administrations began building the shared Iberian Electricity Market (MIBEL).

renewable energy capacity and 8 per cent of the total hydropower capacity (Figure 3). As part of the NREAP, Portugal is aiming for an annual average generation of 1,511 GWh from SHP by 2020 corresponding to a total installed capacity of 750 MW from 250 plants. In order to achieve its goals, the NREAP highlighted the need for a specific plan to develop SHP potential. However, currently, there is no plan in place.15

The market is regulated by the Energy Services Regulatory Authority (ERSE), the sectorial regulator for gas and electricity, and an independent legal entity of public law, financially and administratively autonomous according to Decree-Law No. 97/2002, updated with Decree-Law No. 84/2013. The process of market liberalization is therefore not complete with some regulated tariffs still in place. Though it has been postponed since the initial date was fixed, this is expected to cease in the near future and impacts on the energy market are yet to be evaluated as are all the effects associated with the privatization process.

FIGURE 3

Location of small hydropower plants

Historical tariffs are well documented but have been subject to multiple tax-related changes, some with relevant impacts on the consumer costs. Consumer prices have varied over the years. Although some tariffs have regional differences, they are generally market driven. Average costs in the second half of 2014 were EUR 0.223 (US$0.297) per kWh and EUR 0.119 (US$0.159) per kWh for residential and industrial consumers, respectively.1 Small hydropower sector overview and potential In Portugal, small hydropower (SHP) is defined as plants with a capacity of 10 MW or less. Current installed capacity is 372 MW. However, there are no accurate or complete studies for SHP potential.1 Nonetheless the country’s National Renewable Energy Action Plan (NREAP) is aiming for a total of 750 MW from 250 plants by 2020 indicating that at least this potential exists.15 Current capacity constitutes approximately 50 per cent of this target.

Source: Energias Endógenas de Portugal6

Since 2007, the National Plan for Dams with High Hydropower Potential has been underway, defining the construction of 10 new large dams. This plan is, however, only half complete and its continuation may depend on governmental options, international energy prices and limits to energy exports to European countries associated with energy market constraints that represent real obstacles in pursuing an increase in large hydropower capacity.

FIGURE 2

Small hydropower capacities 2013-2016 in Portugal (MW) Potential 2016 2013

750 750



372

A key challenge for the Portuguese energy sector is to reduce energy dependence, a goal which can only be achieved by developing renewable energy sources. Currently renewable energy sources constitute a 27 per cent share of the energy sector and a 58 per cent share of the electricity sector.9 According to a study developed by Deloitte for the Renewable Energy Association (APREN), although future renewable energy growth should be below the European Union and global expected growth, a further 7,100 MW of installed power is expected from renewable sources over the next 16 years.10

450

Sources: WSHPDR 2013,8 Direcção Geral de Energia e Geologia14 Note: A negative change can be due to access to more accurate data. The comparison is between data WSHPDR 2013 and WSHPDR 2016.

As of 2014, there were 159 SHP plants in Portugal constituting approximately 4 per cent of the total

565

Southern Europe

4.3


new tariff was defined by the Decree-Law No. 126/2010 specifying for the public tender launched in that year: EUR 9.5/kWh (US$10.8), up to 25 years.9

Current energy policy is built on two major pillars: sustainability and economical rationality on the basis of energy efficiency; and endogenous renewable sources incorporation and cost reduction. Goals outlined in the National Plan of Action for Energy Efficiency, National Action Plan for Renewable Energies and the Program of Energy Efficiency in the administration are to: }} Reduce greenhouse gases in a sustainable way; }} Diversify primary energy sources; }} Increase energy efficiency; }} Contribute towards an increase in economic competitiveness.11,12

Barriers to small hydropower development Portugal is in a slow stage of development of its SHP sector with only a few power plants being developed in the last decade. Major barriers include: }} A lengthy, costly and unpredictable licensing procedure. On average the licensing procedure for an SHP plant can take between 3 and 11 years. }} Legal constraints, particularly in regard to more stringent environmental requirements such as the Water Framework Directive, can lead to a limitation of the technical characteristics and potentially the profitability of a project. }} Inadequate support mechanisms. A reduction in the value of the FIT in 2005 has led to a significant decrease in the number of new SHP plants. }} In general technical capacity is available, while state-of-the-art information systems and effective social awareness of environmental issues support the growth of the renewable energy sector. Furthermore, the national electricity grid infrastructure is of no major concern. However, limitations on energy exports are an obstacle to the increase of renewable energy sources. On the other hand, SHP is socially preferred over large dam construction as environmental and economic impacts are reduced.

Legislation on small hydropower There is no regulation published on establishing residual flow. Yet, there are indications that the ecological flow in Portugal should be, on average, 5-10 per cent of the modular flow. Also, this flow should be variable during the year to enable a better adjustment to the differences in the natural hydrological regime and to the spawning seasons. The residual flow would be the sum of the ecological flow with the flow necessary for the existing uses such as irrigation and water supply.9 In Portugal, the support scheme in place for SHP is its feed-in tariff (FIT). The Decree-Law No. 225/2007 indicates an average reference FIT of EUR 7.5-7.7 /kWh (US$8.5-8.7), with a limit set to the first 52 GWh/MW or up to 20 years, whichever is reached first. It could be increased to 25 years in exceptional cases. In 2010, a

566

4.3.8

Serbia Milena Panic, Marko Urošev and Ana Milanovic Pešic, Geographical Institute; Jovan Cvijic, Serbian Academy of Sciences and Arts


7,129,3661

Area

88,499 km2

Climate

Continental climate (in areas of plains, basin rims and river valleys) and mountain climate in the southern part of the country. In the period 1961-2010, the average annual temperature ranged from 3°C in the highest parts of mountains to 12.3°C in Belgrade. The average temperature in January ranges from 4.6°C in mountainous areas (Kopaonik) to 2.1°C in Belgrade and in July from 11.3°C in the mountainous areas (Kopaonik) to 22°C in the valleys (Negotinska krajina, Belgrade).3

Topography

The relief is characterized by three types of regional morph structures: plains and basin rims, located in the northern and eastern part of the country and the areas of mountains and valleys in the southern part (Dinarides, the mountains of the Vardar Zone and the Serbo-Macedonian mass, Carpatho-Balkanides). The highest point is Deravica (2,656 metres) in the Prokletije Mountains. Serbia is mostly a low-land country, up to 200 metres altitude (36.7 per cent of the territory) and up to 500 metres (61.3 per cent of the territory).3

Rain pattern

Serbia has a moderate continental climate with the maximum precipitation in May or June and October and minimum in February. Several parts of the country (southern, south-western) have Mediterranean pluviometric regimes (the maximum precipitation is in the winter months). The average annual precipitation ranges from 500 to 600 mm (Vojvodina and several river valleys), 600-700 mm (Posavina, Pomoravlje, lower parts of Šumadija and Carpatho-Balkanides), 700-800 mm in hilly areas and 800-1,100 mm in the mountainous areas.3


The largest rivers are transit, international rivers (water discharge of the Danube at the exit of Serbia is about 5,500 m3/sec, Tisa 900 m3/sec, Sava 1,600 m3/sec, Drina 350 m3/sec), while the internal rivers are generally shorter and have lower discharges. The largest national river is the Velika Morava (175 km in length) with a discharge of 230 m3/sec. The total discharge of internal rivers is 480 m3/sec for the 1961-2010 period. Most abundant water areas (34.5 per cent of total runoff), with the highest precipitation and the lowest evaporation are located between 400-700 metres of altitude. The total capacity of existing groundwater sources is around 687 million m3 per year.3


consumers’ needs for electric power during periods of peak consumption.6

The power system of Serbia has a nominal capacity of 8,350 MW: 5,200 MW from thermal power plants, 2,800 MW from hydropower plants and 350 MW from combined heat and power plants (Figure 1). Overall electricity generation in 2014 was 36,832 GWh with 25,297 GWh from thermal power plants, 11,472 GWh from hydropower plants, and 63 GWh from combined heat and power plants.22 The electrification rate is 100 per cent. The annual electric power production by hydropower plants varies depending on the hydrological situation.5

Source: Balkan Energy News4

In Serbia, 64 per cent of hydropower plants are run-ofriver plants, 15 per cent are storage plants, and 21 per cent are reversible (pumped storage) plants. The power of thermal plants and run-of-river hydropower plants accounts for almost 90 per cent of the total capacity, while their share in electric power production is 95 per cent. These facts, as well as an extremely uneven consumption, lead to great difficulties in fulfilling

Several factors have influenced the electricity sector in Serbia like the economic development accompanied with difficulties and major political changes have led to frequent changes of responsible institutions, laws and regulations and have made it impossible to monitor the planned developments. Also, the established legal framework has been subject to permanent improvement and harmonization with the legislation of the European

FIGURE 1

Installed electricity capacity in Serbia by source (MW) Thermal power

5,200

Hydropower Combined cycle

567

2,800 350

Southern Europe

4.3


Union. One of the most significant steps was the implementation of the Water Framework Directive (Directive of European Parliament and of the Council 2000/60/EC). Also influential was the ratification of the treaty establishing the Energy Community, by which the Republic of Serbia agreed to adopt and carry out the plan for the implementation of Directive 2001/77/EC on the promotion of electricity produced from renewable energy sources, to enforce a set of regulations on climate change aimed at reducing greenhouse gas emissions and to accede the International Renewable Energy Agency (IRENA).7,8

important renewable resource and it is estimated at 27.2 TWh per year; technically feasible potential reaches 19.8 TWh per year, 18 TWh per year of which can be produced by hydropower plants larger than 10 MW. Currently 15 large hydropower plants produce 11.7 TWh per year.11 The potential of small watercourses suitable for installing SHP plants is up to 0.4 million tonnes of oil equivalent or 3 per cent of the total potential of renewable sources in Serbia.6 So far, 88 SHP plants up to 10 MW have been built on the rivers in Serbia. Out of that number, 50 (four in 2015) with a total capacity of 36.80 MW and an annual electricity production of approximately 200 GWh are operational and 38 facilities with a total capacity of 8.67 MW are out of use.13,14 In 2013, Electric Power Industry of Serbia (EPS) bought energy from 33 SHP plants, while in 2014 EPS bought from 41 SHP plants that had the status of privileged producers. The electricity acquired from the privileged producers reached a total of 147 GWh.15 A survey of 38 municipalities with the biggest potential for construction of SHP plants includes 711 locations with a potential of 409.3 MW (1,459 GWh/year).16

The point of departure highlighted in adopted strategic and planning documents is the conclusion that energy resources are not sufficiently explored, while available data is not conclusive. However, there is a general agreement that besides geological reserves of primary energy resources, hydropower potential and other renewable energy resources will be the basis for the development of production capacities in the future.

The government of the Republic of Serbia supports trends aimed at increasing hydropower generation capacity; it has defined three priorities: modernization and upgrading of existing hydropower plants, construction of new facilities and encouraging the development of the SHP sector. According to the National Action Plan for Renewable Energy Sources, it is planned that by new power plants with a total installed capacity of 1,092 MW will be erected by 2020.17 So far, the Ministry of Mining and Energy has published two public calls for the allocation of sites for construction of SHP plants. In the past two years the State has offered investors 450 locations for the construction of small hydroelectric power plants. As a result of the first call, memoranda were signed for 212 locations (from 317 offered) with 90 investors in 17 municipalities of Serbia. Investors have shown great interest in the second Notice of available locations. The applications were submitted by 74 investors for 106 locations, while the interdepartmental commission proposed that the 40 investors signed a tripartite memorandum of understanding on 79 locations. The tripartite memorandum should be signed between the Ministry of Mining and Energy, local governments and investors.18

Small hydropower sector overview and potential The definition of small hydropower (SHP) in Serbia is up to 30 MW. Installed capacity of SHP up to 10 MW is 45.5 MW, while the potential is estimated to be 409.3 MW indicating that 11 per cent has been developed. Between World Small Hydropower Development Report (WSHPDR) 2013 and WSHPDR 2016, installed capacity has decreased by approximately 8 per cent (Figure 2). Since the adoption of the Decree on Incentive Measures for Privileged Electric Power Producers in January 2013, the term ‘small hydropower’ plants has been extended to include hydropower plants with the installed power up to 30 MW.9 Until December 2012, this term covered all hydropower plants with the installed power up to 10 MW regardless of their type (i.e. it included both plants using reservoirs and run-of-river hydropower plants). The hydropower plants with the installed power up to 100 kW are called micro energy plants.10 FIGURE 2

Small hydropower capacities 2013-2016 in Serbia (MW) Potential 2016 2013

409.3 409.3


Projects for construction of SHP plants are constantly under consideration. It is believed that a significant number of approved projects will be completed by 2020. Also, it is planned to revise the Survey of Small Hydropower Plants in the Republic of Serbia (without the autonomous provinces) and the Survey of Small Hydropower Plants in Vojvodina. However, until the new surveys are completed and the data updated, these documents remain the key data concerning the future development and construction of SHP plants in Serbia. According to these documents, the greatest hydro potential usable for SHP is located in the west (in the Kraljevo and Užice regions) and south (the Niš region) of Serbia, which are mountainous areas. The greatest number of such facilities could be installed

45.5 49.6

Sources: WSHPDR 2013,16 Ministry of Mining and Energy of Republic of Serbia9 Note: The comparison is between data from WSHPDR 2013 and WSHPDR 2016.

In Serbia, hydropower potential is considered the most

568

in the region where the first SHP plant in Serbia was built—in the Užice region. In the northern, flatland area of Serbia (Podunavlje, Vojvodina, the Belgrade area), hydropower potential is somewhat lower but these regions are the most densely populated and economically most developed parts of Serbia.11

Law regulates issues related to SHP plants, all types of licences and permits and their privileged position in the market, compared to other energy producers who sell energy under equal conditions; it also implies the right to subsidies (tax, tariff and other subsidies provided for by law), as well as incentive feed-in tariffs.21 Also, it is characterized as a law that will allow an increase in investments in the energy sector and incorporation of the EU acquis into the legal system of the Republic of Serbia. Following the adoption of the new laws, the Government plans to adopt new bylaws, including model contracts to purchase electricity from privileged producers.

According to the Energy Law of the Republic of Serbia, one of the main goals is to increase the share of renewable energy sources in energy production.4 Along with the documents dealing with new facilities, there are numerous studies which draw attention to the revitalization of old SHP plants and the complementary utilization of other water management facilities for energy production. For example, the reconstruction and adaptation of the sites where water-mills were constructed in the past (according to estimations, there are about 5,000 such locations in Serbia), it would be possible to provide 10 MW of installed power, i.e. about 45 GWh of generated electricity per year. However, technical documentation for these facilities is lacking and it would be very difficult to assess investment possibilities.5 Also, the Spatial Plan of the Republic of Serbia foresees the drafting of the investment-related and technical documentation and the implementation of projects aimed at installing SHP plants on the existing accumulation dams and hydropower production facilities, as well as on the existing multipurpose water management accumulation reservoirs.19 Projects by the Electric Power Industry of Serbia and foreign partners are currently in progress to develop 10 SHP plants on the Ibar River, with a total capacity of 120 MW, an annual production of 453 GWh, and an investment value of 340 million EUR.18

The National Action Plan for Renewable Energy Sources (Official Gazette of the Republic of Serbia 53/2013), adopted in 2013, encourages investment in renewable energy sources, and sets the goals for utilizing renewable energy sources and their implementation by 2020. This document is the result of international commitments of the Republic of Serbia as a member of the Energy Community.17 Other legal acts, which specifically regulate the functioning of SHP plants and provide the necessary guidelines for investors were adopted in 2009 (Decree on the Requirements for Obtaining the Status of a Privileged Electric Power Producer and the Criteria for Assessing the Fulfilment of these Requirements; Model Agreement on Purchasing Electric Power from Privileged Producers) and in 2013 (Decree on Incentive Measures for Privileged Electric Power Producers), according to the previous Energy Law (Official Gazette of the Republic of Serbia 84/04, 57/2011). The Spatial Plan of the Republic of Serbia from 2010 to 2020 (Official Gazette of RS 88/10) governs the spatial development of the Republic of Serbia. The Plan provides an overview of the available hydropower potential of Serbia and also deals with potential locations where SHP plants could be built in the territory of Serbia, taking into account documents such as the Survey of Small Hydropower Plants in the Republic of Serbia (1987) and the Survey of Small Hydropower Plants in Vojvodina (1989) and it also suggests that such locations be protected against unplanned usage.19

As for small-scale investments, investors usually decide to cover part of expenses by bank loans. However, as the practice has shown, banks offer varying repayment conditions, which are particularly reflected in varying annual repayment interest rates. Also, the European Bank for Reconstruction and Development (EBRD) approved a loan of EUR 32.3 million to the Electric Power Industry of Serbia for the reconstruction of 15 SHP plants with a total capacity of 18 MW and the construction of two new SHP plants on existing dams. In the long term, the Electric Power Industry of Serbia plans new investments in renewable energy, related entirely to SHP.20

The Survey of Small Hydropower Plants in the Republic of Serbia (1987) and the Survey of Small Hydropower Plants in Vojvodina (1989) are still used as supplemental documents in the process of choosing potential locations for the construction of SHP plants. According to these documents, 869 locations were identified. The results of fifteen recently completed preliminary feasibility studies show, under the present economic conditions, it would be possible to use 5–10 per cent of the total locations foreseen by the Surveys.12

The Survey of Small Hydropower Plants in the Republic of Serbia (1987) and the Survey of Small Hydropower Plants in Vojvodina (1989) are not up-to-date, so they should be replaced with the new SHP Cadastre which will be financed from pre-accession funds (IPA 2013). Renewable energy policy The Energy Law of the Republic of Serbia (Official Gazette of the Republic of Serbia 145/2014) prescribes the energy policy objectives and the methods of its implementation. In a separate segment, it highlights issues related to renewable energy sources, pointing out that it is in the interest of the Republic of Serbia to utilize them. The

The Decree on Incentive Measures for Privileged Electric Power Producers (Official Gazette RS 8/2013), determined privileged purchase prices of electricity from SHP plants (Table 1).9 569

Southern Europe

4.3


by the construction of several dozens of such facilities, more recent political and economic changes caused a significant delay in their development compared to other countries. Relevant legislation and planning documents seek to promote a more intensive exploitation of the energy source due to its advantages. However, there are numerous limiting factors that hinder and impede it.

TABLE 1

Feed in tariffs for small hydropower Categories of SHPs

Installed power (MW)

Incentive measures – pretax price (EUR/kWh (US$/kWh))

Newly built facilities

< 0.5 MW

0.097 (0.109)


From 0.5 to 2 MW

~0.0103 (0.012)


From 2 to 10 MW

0.0785 (0.088)

Existing infrastructure

< 2 MW

0.0735 (0.083)

Existing infrastructure

From 2 to 10 MW

0.059 (0.066)

Country-specific barriers: }} Complicated permit-issuing procedures (about two years to complete); }} Great initial investment (costs of preliminary and main project drafting); }} Limited funds for investing in projects in this area; }} No updated versions of the Survey of Small Hydropower Plants in the Republic of Serbia (1987) and the Survey of Small Hydropower Plants in Vojvodina (1989); }} Low awareness of the advantages of SHP both among professionals and the public; }} Insufficient knowledge of technologies, economic and ecological indicators; }} Payback time estimation.

Source: Ministry of Mining and Energy of Republic of Serbia9

Barriers to small hydropower development Although the idea of installing SHP plants in Serbia emerged in the early 20th century and was followed

570

4.3.9

Slovenia Saso Santl, Institute for Water of the Republic of Slovenia


2,062,8741

Area

20,273 km2

Climate

The climate is continental with cold winters and warm summers, but at the coastal areas there is a pleasant sub-Mediterranean climate. The average temperatures are 0°C in January and 20°C in July.2

Topography

The topography of the Slovenian territory is mostly elevated. Outside the coastal area, the terrain consists largely of karstic plateaus and ridges, alpine areas with mountain and hill chains, basins and valleys and also river lowlands in the south-east. The highest Alpine peak is Triglav (2,864 metres).2

Rain pattern

On the global scale, Slovenia exhibits above average precipitation abundance. The average rainfall is 1,000 mm at the coast and up to 3,500 mm in the western areas of the Alps, 800 mm in the south-east and 1,400 mm for central Slovenia. Plentiful snow falls in winter (December – February). The driest months are December to March, while June and November receive more than 130 mm on average.7


The average measured runoff in Slovenia is 27 l/sec/km2, which is equivalent to around 588 m3/sec of net runoff from the territory. The Mura and the Drava transit streams (from Austria) have an average annual runoff around 418 m3/sec and the total average runoff from Slovenian territory is around 1,006 m3/sec.6


Source: Statistical Office, Slovenia, 20151

implement the European Union (EU) directives that had been adopted after the previous law was enacted, as well as to bring the law into compliance with decisions of the Slovenian Constitutional Court, which had declared the previous law unconstitutional in relation to certain aspects of the determination and calculation of network charges. The law lays down the principles of energy policy, energy market operation rules, manners and forms of providing public services in the energy sector, principles and measures for achieving a secure energy supply, improving energy efficiency and energy saving and increasing the use of energy generated from renewable energy sources. In Slovenia, the Energy Agency is the market regulator and is responsible for the transparency of market operations, determining methodologies for the energy sector, issuing guarantees of the origin of electrical energy and commercial green certificates for the production of electricity from renewable energy sources (RES). Borzen is the market organizer with the main task to promote the development of the Slovenian electricity market and market mechanisms in accordance with EU guidelines and contributes significantly to the proper functioning of the Slovenian power system, as well as aligning the Slovenian and EU legislation and integration of the Slovenian electricity market into the integrated European electricity market.

A reform of the energy sector came with the adoption of the new Energy Act in 2014.3 The reform was needed to

In Slovenia, large electricity producers and transmission/ distribution systems are owned by the State. The activities

Average gross electricity production for the period between 2010 and 2014 was 16,300 GWh per annum. In 2014, total electricity generation was at 17,437 GWh including 6,370 GWh from nuclear (36.5 per cent), 6,366 GWh from hydropower (36.5 per cent), 4,440 GWh from thermal (25.5 per cent), 257 GWh from solar (1.5 per cent) and 4 GWh from wind (0.02 per cent) power plants (Figure 1).1 Total installed capacity in 2014 was 3,453 MW, out of which 1,295 MW was from hydropower, 1,242 MW from thermal, 688 MW from nuclear, 224 MW from solar and 4 MW from wind power.1 FIGURE 1

Electricity generation in Slovenia by source (GWh) Nuclear power

6,370

Hydropower

6,366

Thermal power Solar power

4,440 257

Wind power 4

571

Southern Europe

4.3


of electricity transmission and distribution are mandatory national public services carried out by the electricity system operators that are also owned by the State. Small electricity producers (up to 10 MW), distribution companies and energy market suppliers can be publicly or privately owned, or as a public-private partnership (PPP). The total length of electric transmission network in Slovenia is 2,852 kilometres and connects major producers, big consumers and neighbouring countries (Austria, Croatia and Italy). The total length of the distribution network is around 65,000 kilometres (70 per cent is low-voltage network), which also includes street lighting and by which the Slovenian territory is efficiently covered for existing small producers. Domestic energy production covers more than 90 per cent of the Slovenian electricity demand.5 The total number of electricity consumers is around 935,000, of that around 89 per cent are household consumers, and the electrification rate is 100 per cent. The biggest consumers of electricity (56 per cent) are industry and enterprises, 25 per cent is households, 16 per cent transmissionnetwork consumers and 3 per cent is pump storage for the accumulation of water.5 Based on monthly consumption, there are no significant seasonal fluctuations. Considering the implementation of measures for efficient energy use, overall energy consumption should increase by less than 5 per cent and gross electricity consumption should increase by less than 10 per cent in Slovenia by 2020.8 Major challenges with the increase of electricity production from RES, especially from hydropower, are finding proper harmonization and balance with legitimate environment and nature preservation objectives; this requires more thorough collaboration between relevant competent authorities in the process of strategic decision making. To define and harmonize the strategic energy development of Slovenia, the Energy Concept of Slovenia is being prepared and is planned to be adopted in 2016. The main objectives of the document are a significant reduction of greenhouse gas emissions in the field of energy production (at least by 80 per cent by 2055) while taking into consideration sustainability, climate acceptability, supply reliability and competitiveness.15

operation. RES generating plants with nominal capacity of 5 MW and more are eligible only for the latter support option.4 Small hydropower sector overview and potential The definition of small hydropower (SHP) in Slovenia is up to 10 MW. Installed capacity of SHP is 157 MW: 119 MW of plants up to 1 MW and 38 MW of plants from 1 MW to 10 MW.1 According to overall estimations, in Slovenia there are around 2,000 MW of theoretical, 1,100 MW of technical, and 475 MW of economic potential for electricity production from SHP up to 10 MW of installed capacity.11 Between World Small Hydropower Development Report (WSHPDR) 2013 and WSHPDR 2016, Slovenia has witnessed an increase in both installed capacity and potential capacity of SHP (Figure 2). FIGURE 2

Small hydropower capacities 2013-2016 in Slovenia (MW) Potential capacity

2016 2013

Installed capacity

475 192 157 117

Sources: Statistical Office RS,1 WSHPDR 201313 Note: The comparison is between data from WSHPDR 2013 and WSHPDR 2016.

However, there are different definitions of SHP in Slovenia. From the point of water management SHP is defined as a hydropower plant (HPP) with installed capacity less than 10 MW. From the point of energy production from RES there are four categories divided by size: }} Micro: less than 50 kW; }} Small: between 50 kW and 1 MW; }} Medium: between 1 and 10 MW; }} Large: more than 10 MW.

Since the full opening of the market on 1 July 2007, the price of electricity supply has become the market value. So electricity prices for general industrial and household consumers in Slovenia are dependent on the wholesale market in Slovenia and in the EU.16 The average electricity price for households in Slovenia at the end of 2014 was EUR 0.158/kWh (US$0.18/kWh) and for industry without value added tax EUR 0.089/kWh (US$0.1/kWh).5 EU and Slovenian regulations support electricity production from RES and also consider high efficiency cogeneration. However, support is granted only for generating plants whose electricity generating costs exceed the price of electricity in the open electricity market. By the end of 2014, there were roughly 3,700 power plants included in the scheme, predominantly hydropower and photovoltaic (PV) ones. The total installed capacity is about 500 MW. Support is defined annually for new production and for up to 15 years, and can comprise guaranteed purchase of electricity or financial aid (operating support) for current

In 2014, there were 460 SHP plants operating and selling electricity to the grid. The number of water rights was higher (509), the difference is due to the fact that some are not operating, are under construction, produce electricity for own supply, or more than one water right is granted for the same SHP plants (split of electricity production/potential among the owners). The installed capacity is 157 MW and electricity production for the year 2014 was 496 GWh (246 GWh from plants up to 1 MW and 250 MW from plants from 1 MW to 10 MW).1 2014 was a rainy year; average for the period between 2004 and 2014 was around 385 GWh/annum.19 In comparison to electricity production from large HP in 2014 (around 5,870 GWh), the share of SHP is around 7.8 per cent of total electricity production from hydropower.1

572


locations for exploiting hydroelectric potential have been started. The sites are prepared according to the guidance for Alpine Space and Danube Basin with consideration of Article 4.7 of the Water Framework Directive and Article 6.4 of the Habitats Directive. The Water Framework Directive and also the Habitats Directive state that public interest must be taken into account and the benefits of new electricity production must outweigh environmental benefits.3,20 The main principle to be followed is that the higher the ecological value of a water stretch (water body) the higher the energy output must be. Therefore, the planning of hydropower favours larger hydropower plants; SHP plants as a rule are foreseen on already deteriorated stretches with a focus on optimization of existing exploitation as well as where multipurpose benefits are foreseen (e.g. flood protection, irrigation etc.).

The main strategic action plan concerning RE in Slovenia is the National Renewable Energy Action Plan 20102020 (NREAP); it plans 25 per cent of RES in the final energy consumption by 2020. It also covers the national policy of renewable energy sources, expected gross final energy consumption in the period between 2010 and 2020, targets and trajectories regarding renewable energy sources, measures for achieving binding target shares of renewable energy sources and estimation of the contribution of individual technologies to achieving the target shares of renewable energy sources, the costs of carrying out measures and impacts on the environment and job creation. The objectives of the national energy policy for RES are ensuring a 25 per cent share of RES in final energy consumption and a 10 per cent share of renewable energy in transport by 2020. In order to achieve these objectives, the NREAP states measures to be implemented for sectors of heating and cooling, electricity and transport. The competent authority for energy is the Energy Directorate within the Ministry of Infrastructure (previously within the Ministry of the Economy). In the measure Proactive Role of the State in Identifying Environmentally Acceptable Locations for Exploiting RE Potential, it is stated that the Ministry of the Environment and Spatial Planning will ensure the processing of already received petitions for initiating the procedure for allocating water rights for SHP plants, and the Ministry of Economy will provide a study of the costs and benefits of existing SHP plants, as a basis for sustainable criteria, wherein it takes account of environmental, social and economic impacts.8

In 2015 not many new SHP plants were planned in Slovenia; the most common were SHP projects on already existing water objects (e.g. construction of an SHP plant with installation of Environmental Flow instead of spilling it over the weir gates). There are currently more than 40 applications for water rights granting new SHP development at the Slovenian Environmental Agency. The last comprehensive analysis and planning of possible SHP projects on the national scale was done in 2007, where 33 SHP plants with capacity of 1-10 MW and 6 SHP plants with lower capacity were foreseen.9 Most of the locations of foreseen SHP plants were not harmonized with the Water Framework Directive (e.g. they are planned on reference river stretches) or were planned in protected areas outlined in the Natura 2000 EU framework. In Slovenia, financial support to SHP development is provided by supporting schemes. As mentioned previously, two types of support are possible: operating support (OS) and guaranteed purchase (GP) which are provided for a period of 15 years for new projects. The levels of support are defined each year and do not affect plants which are already included in the supporting scheme. The tariffs for 2015 are detailed in Table 1.4

In general, the support for hydropower development in Slovenia is mixed. Comprehensive studies, such as the preparation of a master plan to define possible locations that are also harmonized especially with environmental objectives, are necessary to be prepared and adopted between sectors. This need has been widely recognized and already supported by numerous studies and documents.10,12,14,18,19,20 It is important to raise the acceptance of SHP, but for those which can on one side produce not just renewable energy but also green energy, it requires full mobilization of mitigation measures to minimize negative effects on aquatic ecosystems and water status and also to support other water management related benefits.

TABLE 1

Tariffs for hydropower plants (US$/MWh) Support scheme


Micro hydro (< 50 kW)

Small hydro (50 kW-1 MW)

Medium hydro (1 MW-10 MW)

Large hydro (< 250 MW)

80.28

65.81

52.48

45.99

Micro hydro (< 50 kW)

Small hydro (50 kW-1 MW)

Medium hydro (1 MW-5 MW)

118.63

104.17

92.62

Operational support

According to the National Renewable Energy Action Plan 2010-2020 for SHP, the target capacity for foreseen for SHP plants of capacity 1-10 MW is 57 MW and for smaller SHP plants 120 MW.8 Thus, the total capacity of SHPPs is planned to reach 177 MW by 2020. A major challenge is to harmonize RES and ecological objectives, so the activities for identifying environmentally acceptable

Guaranteed purchase Source: Borzen 4

573

Southern Europe

4.3



disastrous events (e.g. floods). There is a need for: }} Better data generation and harmonisation }} Improved stakeholder involvement and communication }} Integration of the ecosystem service concept }} Implementation of strategic (spatial) planning approaches on various spatial levels

Although developed evaluation methods are in place on how to proceed with the analysis of available potential and how to balance different objectives, collaboration between sectors responsible for different objectives is poor. Each sector follows its own objectives and they do not properly apply the principles of sustainable development, which impedes the framework for managing resources and coordinating and integrating environmental, economic and social aspects in an equal way.

It should also be mentioned that especially in the environmental protection sector there is mistrust for new SHP development, since many of the existing SHP operators do not follow the obligations for ensuring environmental flow and other aquatic ecosystem protection issues.

In Slovenia the water management sector is inadequately supported by human and financial resources due to significant reductions in the last 25 years (especially compared to the growth of national GDP in that period). That is reflected in poor data management, lack of supervision and a stronger position of water management objectives in spatial planning and land use, inadequate maintenance of water infrastructure and watercourses and also in unclear and un-straightforward decision making. The State administration of the water sector has also been periodically reorganized, mostly following

One of the barriers for planning financially feasible and state-of-the-art SHP plants is inadequate technical, economic, environmental and risk awareness on the investor side, especially the smaller ones, who are not aware that investment in SHP with full consideration of all technical, safety and environmental aspects can require considerable time and financial resources.

574

4.3.10 Spain Cayetano Espejo and Ramon Garcia, Universidad de Murcia; Nathan Stedman, International Center on Small Hydro Power


46,404,6026

Area

505,000 km2

Climate

Temperate climate; summers are clear and hot in the interior of the country and more moderate and cloudy along the coast; winters are cloudy and cold in the interior and partly cloudy and cool along the coast. Average temperatures range between 6.6°C in January and 22°C in July.7

Topography

Large, flat to dissected plateau surrounded by rugged hills with average height of 610 metres above sea level. In the north the Pyrenees stretch approximately 400 km from the Atlantic coast; the mountains of the Cordillera Betica and Sierra Nevada transverse the far south. The highest point of mainland Spain is Mulhacen at 3,481 metres above sea level.8

Rain pattern

Average annual precipitation is 650 mm. In northern Spain rainfall reaches 1,000 mm, while in semiarid areas it is only 300 mm. The driest months are June to September, while the wettest is November, with an average of 73 mm.7


There are around 1,800 rivers in Spain, though many stay dry for much of the year. When filled with water, rivers quickly turn into raging and destructive torrents. Five major rivers follow the direction of the major mountain systems with four of them flowing into the Atlantic (the Duero, Tagus, Guadalquivir and Guadiana) and one (the Ebro) into the Mediterranean. All these rivers all dammed, as well as many of their numerous tributaries, and the reservoirs provide much of the water and electrical power for the country.8


The net demand in 2015 was approximately 263,094 GWh, up almost 2 per cent from 2014. Also in 2015, Spain generated 268,057 GWh, indicating an increase of 0.4 per cent from 2014. Hydropower production accounted for 31,396 GWh.1

Spain (the Iberian Peninsula and the isolated island network also known as the Balearic and the Canary islands as well as Ceuta and Melilla) has a total installed capacity of 108,299 MW (2015), comprised of 19 per cent from hydropower, 25 per cent from combined cycle gas turbine plants, 21 per cent from wind power, 11 per from cent coal-fired plants, 7 per cent from nuclear, 7 per cent from cogeneration, 6 per cent from solar, 3 per cent from fuel and gas-fired plants, and 1 per cent from renewable based thermal power (Figure 1).1

The Ministry of Industry, Energy and Tourism (Minetur) is responsible for formulating and implementing energy policy. The regulator for the energy sector is the National Commission of Markets and Competition (CNMV). The CNMV also cooperates with other regulators through the Council of European Energy Regulators (CEER) and the Agency for the Cooperation of Energy Regulators (ACER) for interconnections between neighbouring countries.10

FIGURE 1

In terms of installed capacity, the largest companies are Iberdrola, Endesa and Gas Natural Fenosa, which together control about 75 per cent of the capacity.10

Installed electricity capacity in Spain by source (MW) Combined Cycle

27,199

Wind power Hydropower

20,778

Coal

11,482

Nuclear power

7,866

Cogeneration / other

7,219

Solar power

6,967

Fuel / gas Other RE sources

The Spanish wholesale market is part of the Iberian power market (Mercado Ibérico de Electricidad – MIBEL) which includes both Spain and Portugal. OMIE in Spain manages the spot market while OMIP in Portugal manages the futures market. Red Eléctrica de España (REE) and Red Eléctrica Nacional (REN) are the two system operators.10

23,003

The Spanish transmission network is owned and operated by REE. In 2013, the transmission network had a total length of 40,000 km, of which 20,641 km was at 400 kV and included 5,216 substations with a transformer capacity of 80,695 MVA.

2,784 1,001

Source: Red Electrica de España1

575

Southern Europe

4.3


Endesa, Iberdrola, Gas Natural Fenosa, E.ON and HC Energia-EDP are the five major distributors. However, there are more than 300 smaller companies that also provide distribution services.10 The electrification rate in Spain is 100 per cent.

TABLE 1

Installed small hydropower capacity by region (MW) Region

The definition of small hydropower (SHP) in Spain is an installed capacity up to 10 MW. The SHP installed capacity is 2,104 MW from 1,091 plants. The SHP potential is 2,185 MW.2,4 Between World Small Hydropower Development Report (WSHPDR) 2013 and WSHPDR 2016, installed capacity has increased by 178 MW and the SHP potential remained the same. The increase in installed capacity is due to new installations, refurbishments of existing SHP plants, as well as access to more accurate data.

2010

2014

75.0

99.0

143.0

143.0

Aragón

150.0

255.0

254.0

257.0

Asturias

111.0

77.0

77.0

77.0

Canarias

0.5

0.5

0.5

0.5

Cantabria

60.0

67.0

71.0

72.0

Castilla-La Mancha

55.0

96.0

128.0

126.0

Castilla y León

128.0

207.0

246.0

256.0

Cataluña

192.0

264.0

278.0

286.0

7.0

31.0

31.0

31.0

C. Valenciana Extremadura

FIGURE 2

Small Hydropower capacities 2013-2016 in Spain (MW)

2016 2013

2005

Andalucía


13.0

20.0

20.0

23.0

Galicia

258.0

371.0

493.0

522.0

La Rioja

19.0

23.0

27.0

27.0

Madrid

63.0

63.0

44.0

44.0

Murcia

11.0

12.0

14.0

14.0

Navarra

104.0

116.0

151.0

171.0

50.0

65.0

53.0

54.0

1,296.5

1,766.5

2,030.5

2,103.5

Potential

2,185

País Vasco

capacity

2,185

Total

Installed capacity

Installed capacity (MW) 1998

Source: Comision Nacional del Mercado de Valores4

2,104 1,926

Renewable energy policy The resurgence of the SHP sector was due to the Government’s support of the producers of renewable energy. The Electricity Sector Law (54/1997) set a special regulation for sources of renewable energy with an installed capacity lower than 50 MW. Furthermore, the Law recognizes the environmental benefits of these sources by granting financial benefits. Therefore, renewable energy sources can compete with traditional sources of energy.1

Sources: WSHPDR 2013,5 Garcia y Espejo,2 Comision Nacional del Mercado de Valores4 Note: The comparison is between data from WSHPDR 2013 and WSHPDR 2016.

Most of the SHP plants are located in the north of Spain, in the regions where the larger number of river basins with more hydropower resources are located. SHP plants, due to the favourable administrative and legal framework, have considerably increased their capacity since the early 1990s, especially in the Galicia region where the SHP installed capacity has increased by more than 50 per cent (Table 1).3

The Royal Decree 436/2004 of 12 March 2004, as developed upon the Electricity Sector Law, set the legal and economic framework for the Special Regime, in order to consolidate the rules and to give more stability to the system. The Royal Decree 661/2007, published on 25 May 2007, superseded the previous decree and added another regulation to the production system. This decree set a new system aimed at renewable energy plants in order to achieve the targets of the Renewable Energy Plan 2005-2010.

From 1998 to 2014, the number of SHP plants has increased by 62.6 per cent and the SHP installed capacity has increased by the same percentage. The SHP plants have an important impact on the Spanish economy. In 2013, the SHP industry contributed EUR 518 million (US$571 million) to the national GDP.

The Spanish economic crisis, alongside the increase of tariffs, has led to the adoption of a series of contentious measures against renewable energy, as they were seen as the cause of this increase. The Royal Decree 6/2009 of 30 April 2009 set the quota for the maximum capacity that can be installed annually for all the renewable energy

The total theoretical hydropower potential in Spain is 162,000 GWh/year, the technically feasible potential is 61,000 GWh/year and the economically feasible potential is 37,000 GWh/year. The SHP potential generation has been estimated at 7,500 GWh/year.4

576

sources within the special regime. A register was created in order to allow plants falling under the special regime to get access to the financial benefits of the Royal Decree 661/2007. In the aforementioned register, renewable energy plants could only be registered if the limit of renewable energy plants has not been exceeded.

economic incentives for new power generation capacity involving cogeneration and renewable energy sources (RES-E).1 The move was a result of a tariff deficit of roughly EUR 26 billion (US$28.7 billion) in 2012, which was largely driven by the incentives to renewable energy sources.10

At the beginning of 2013, the new Electricity Sector Law (24/2013) was issued. The law foresees the possibility in certain exceptional cases, to establish retributive regimes in order to promote the production of renewable energy. The Royal Decree 413/2014 of 6 June 2014 regulates the generation of energy coming from renewable energy sources, cogeneration and waste.

The 2014 Royal Decree 413/2014 (RD 413/2014) replaced renewable energy feed-in tariffs with a “reasonable return” of 7.4 per cent over the lifetime of a plant. It was introduced alongside the Order IET/1045/2014, which specifies various parameters for calculating the return for different types of renewable energy plants.10 Barriers to small hydropower development

Legislation on small hydropower Although SHP has played an important role in electricity generation in the country, SHP development, particularly since the tariff deficit, currently faces several barriers:3 }} Some potential hydropower sites have not been studied in detail, thus, there is a lack of knowledge regarding their actual potential. }} In order to use water for hydropower purposes, licences need to be issued which requires an environmental authorization approval; the excessive waiting time to get approvals slows the development of potential projects. }} Difficulties in renewing the water concession periods of the current hydropower plants. This could lead to the abandonment of some existing SHP plants. }} The administrative process to get a licence is complex, even for small projects. }} There are obstacles in the procedure of getting authorization from regional and local organs.

There is currently no regulation published concerning the residual flow. A recommendation could be made in the sense that this flow should be variable during the year, to enable a better adjustment to the differences of the natural hydrological regime and to the spawning seasons. Until 2012, there were two different support options (under the previous promotion scheme as established by the Royal Decree 661/2007), a feed-in tariff (FIT) and a market premium with a cap and a floor, on the sum of market price and premium. Plants with a rated power less than 10 MW as well as those with a rated power greater than 10 MW (but less than 50 MW) were considered small-scale hydropower plants. However, on 27 January 2012, the Spanish Council of Ministers approved a Royal Decree-Law ‘temporarily’ suspending the FIT pre-allocation procedures and removing

577

Southern Europe

4.3

4.3.11 The former Yugoslav Republic of Macedonia Viktor Andonov, Ministry of Economy of the Republic of Macedonia


2,075,6251

Area

25,713 km2 1

Climate

Macedonia has a transitional climate from Mediterranean to continental. Warm and dry in the summer and autumn months between June and October with July and August being the warmest when, in some regions, the temperature exceeds 40°C. The country is relatively cold with heavy snowfall during the winter months between December and February. Average temperatures range between approximately 20°C in July and August to less than 0°C in January.2

Topography

Macedonia is a land-locked country framed along its borders by mountain ranges and with a central valley formed by the Varda River. The region is seismically active and has been the site of destructive earthquakes in the past. The highest point is Mount Korab at 2,764 metres.3

Rain pattern

Average annual precipitation varies between 1,700 mm in the western mountainous regions and 500 mm in the east. The wettest months tend to be November and December as well as April and May.2


The Vardar is the longest and most important river in Macedonia bisecting the country and forming a central valley. It is 388 km long and drains an area of approximately 25,000 km2. There are also three large lakes: Ohrid, Prespa and Dojran.3


Serbia and Bosnia. In 2014, 38 per cent of electricity (3,032 GWh) was imported (Figure 2).4

Electricity production in Macedonia is mainly from lignite and large hydropower. In 2014, total installed capacity was 2,011 MW consisting of: thermal power plants (50 per cent), large hydropower (30 per cent), combined heat and power plants (14 per cent), wind (2 per cent), small hydropower (SHP) (3 per cent) and photovoltaic (1 per cent) (Figure 1). This represents an increase of approximately 3 per cent compared to 2013.1

FIGURE 2

Annual electricity generation in Macedonia by source (GWh)

Large hydropower

FIGURE 1

Installed electricity capacity in Macedonia by source (MW)


Thermal power

1,010.0

Large hydropower

59.5

Wind power

36.8

Photovoltaic

14.7

Small hydropower

242

Cogeneration

190

Wind power

70

Solar power

14

The most important renewable resources in Macedonia are hydropower and biomass. Wind power is increasing with the first wind park, Bogdanci, having been commissioned, with a capacity of 36.8 MW installed in the first phase and a further 50 MW to be added in the second phase. Generation from solar power plants is also increasing however, due to the higher investment cost, the Government set a national limit of 18 MW and, with planned constructions, and this capacity has already been reached. Four biogas plants with a total installed capacity of 7 MW are planned to be put in operation in 2016-2017.4

287.0

Small hydropower

958

Source: ERC (2014)4

603.0

Cogeneration

3,506

Thermal power

Source: ERC (2014)4

In 2014, total electricity generation was 4,980 GWh. Thermal power plants contributed 3,506 GWh, large hydropower 958 GWh, wind 70 GWh, combined heat and power plants 190 GWh, SHP 242 GWh, and photovoltaic, 14 GWh. Macedonia is also dependent on imports of electricity, largely from Hungary, Romania, Bulgaria,

Large hydropower plants (HPP) are very important for Macedonia with several planned projects underway:. HPP 578

Boskov Most (70 MW) and the storage power plant Lukovo Pole with Crn Kamen (160 GWh additional generation in the system). Other plans include: Cebren (333 MW), Galishte (200 MW), Gradec (54 MW) and Veles (93.3 MW).5

TABLE 1

Electricity tariffs for households in Macedonia Tariff (EUR (US$) per kWh) Tariff type

The electrification rate is close to 100 per cent although some remote areas still lack access to the grid. The distribution grid is operated by EVN Macedonia and according to the Law on Energy, it is responsible for the development and upgrade of the network. Grid codes define how consumers can request access to the grid.1 Macedonia has implemented the Second EU Directive package which includes third party access. EVN Macedonia has announced that in the next 20 years they will invest EUR 1 billion (US$1.33 billion) in the modernization of the distribution grid.

2013

2014

2015

Households subject to SINGLE-TARIFF metering

0.0692 (0.0922)

0.0728 (0.0970)

0.0727 (0.0968)

Households subject to TWOTARIFF metering: peak tariff

0.0863 (0.1150)

0.0909 (0.1211)

0.0906 (0.1207)

Households subject to TWO-TARIFF metering: off-peak tariff

0.0433 (0.0577)

0.0455 (0.0606)

0.0454 (0.0605)

Source: ERC4

Macedonia has one of the lowest electricity tariffs for households in the region, and in Europe, ranging between EUR 0.0454 (US$0.0605) per kWh to EUR 0.0727 (US$0.0968) per kWh in 2015 (Table 1). The tariffs are set annually by the Energy Regulatory Commission and have been increasing incrementally year on year.4

The electricity sector of Macedonia consists of generation facilities, a transmission system, a distribution system and final consumers. The main electricity producer in Macedonia is the state-owned Joint Stock Company Macedonian Power Plants (JSC ELEM), which owns 90 per cent of total electricity production. The state-owned Joint Stock Company – Macedonian Transmission System Operator (JSC MEPSO) operates the transmission system while the market operator responsible for distribution is EVN Macedonia, which is 10 per cent state-owned with the remainder owned privately by EVN AG Austria. Two independent power producers (IPP), CHP TE-TO and CHP KO-GEL, are also present in the electricity market. EVN Macedonia also has SHP plants constructed between 1927 and 1953 in their portfolio, some of which have been renovated in the last several years. The country’s photovoltaic plants are constructed and operated by private domestic and foreign investors.7

SHP sector overview and potential Macedonia defines SHP as plants with an installed capacity of 10 MW or less. In 2014, SHP installed capacity was approximately 60 MW (3 per cent of the total installed capacity) generating 242 GWh.4 Potential capacity is estimated at 260 MW (Including at least 60 MW which will be constructed by 2018 according to obligations from concession agreements) indicating that 23 per cent of the country’s SHP potential has been developed. Compared to data from World Small Hydropower Development Report (WSHPDR) 2013, installed capacity has increased by more than 30 per cent while estimated potential has increased marginally by 4 per cent (Figure 3).‑

Macedonia is a candidate country for the European Union (EU) and a contracting party in the Energy Community. Thus, it is committed to applying the EU Community Acquis in domestic legislation. Accordingly Macedonia has been working on reforming the energy sector to achieve a single regional stable regulatory market framework capable of attracting investment in transmission networks and generation capacity as well as fostering competition and interconnectivity, thus ensuring supply and realizing economies of scale.

FIGURE 3

Small hydropower capacities 2013-2016 in Macedonia (MW) Potential 2016 2013

Installed capacity

The electricity market in Macedonia is liberalized and at present more than 45 per cent of the total consumption is traded between the traders, suppliers and other market players. Although households and some small companies are still on the regulated market, they are expected to move to the open market by 2020. The Government was expected to update the laws on energy and implement the Third EU Energy Package on the internal energy market by 1 January 2015. However, the deadline was missed and as of June 2016, new legislation was not yet in place.12 A project for strengthening the administrative capacities of the Energy Department in the Ministry of Economy and the Energy Agency of Republic of Macedonia was implemented in 2013 and 2015.

260

capacity

250 60 45

Sources: ERC,4 WSHPDR 20138 Note: The comparison is between data from WSHPDR 2013 and WSHPDR 2016.

SHP currently accounts for approximately 8.4 per cent of the total installed hydropower capacity and approximately 3 per cent of the country’s total installed capacity. However, Macedonia has a significant potential for SHP development with more than 400 identified sites throughout the country which could potentially meet up to 16 per cent of the country’s current electricity needs. The central study on SHP potential in Macedonia is the Feasibility Study for Small and Mini-hydropower produced in 1982 by the Faculty for Mechanical Engineering, Skopje 579

Southern Europe

4.3


University. The potential for the installed capacity in the study is approximately 250 MW with individual capacities ranging from 50 kW to 5,000 kW.9

constructing SHP plants. In 2014, they conducted the sixth procedure for granting water concessions for electricity production from SHP plants and in 2015, they signed concession agreements for constructing 19 SHP plants with a total installed capacity of 23 MW. The concession agreements are signed for a period of 23 years from which 3 years is given to obtain all the necessary licences and carry out the construction work. The concessionaires will produce electricity for a period of 20 years with guaranteed purchase by the market operator.

Renewable energy policy The renewable energy policy of Macedonia is defined within the Law on Energy and the Strategy for Higher Utilisation of Renewable Energy Sources. The current share of renewable energy sources of total final energy consumption is 15.6 per cent and, according to obligations from the Energy Community, the target is 28 per cent by 2020.5 However, some consider this to be too high, based on the inaccurate data provided on biomass potential. A survey by the State Statistical Office on energy consumption in households is underway that will give a more accurate account of biomass potential, after which the Government intends to request a revised target. At present, the Strategy for Higher Utilisation of Renewable Energy Sources is being updated for the period up to 2025.

With these signed agreements for concessions, alongside public private partnerships, it is estimated that Macedonia will have approximately 100 newly constructed SHP plants with an approximate installed capacity of 100 MW by 2019. TABLE 2

Feed-in tariffs in Macedonia for small hydropower plants by capacity Produced electricity per month (kWh)

In order to align its policies with the EU, the Government has made efforts to promote electricity production from renewable energy sources. Incentives are provided through feed-in tariffs (FIT) for the licensed producers of electricity with guaranteed purchase of the total amount of produced electricity for the period of using this preferential tariff. Renewable energy plants also have priority in dispatching by the market operator. The eligibility for application of FIT for SHP plants is an installed capacity up to 10 MW per plant and there is no national limitation on the number of SHP plants.11

FIT (EUR (US$) per kWh)

≤ 85,000

0.12 (0.16)

> 85,000 and ≤ 170,000 kWh

0.8 (1.07)

> 170,000 and ≤ 350,000 kWh

0.6 (0.80)

> 350,000 and ≤ 700,000 kWh

0.5 (0.67)

> 700,000 kWh Source: Energy Regulatory Commission

0.45 (0.60) 11

The Government of the Republic of Macedonia has supported the construction of SHP plants as a renewable energy source, including the introduction of feed-in tariffs in 2007. The tariff is a declining tariff based on monthly electricity production (Table 2). The Government has also signed several direct agreements with the European Bank for Reconstruction and Development (EBRD) for supporting their loan agreements with several concessionaires. This possibility is given to all investors who signed the agreements and are seeking loans from different financial institutions.11

The FIT proposed for wind power is for plants up to 50 MW while there is a total national installed capacity limit of 150 MW. For cogeneration plants using biogas and biomass, the national limit is set at 10 MW. This is primarily due to the relatively small potential of these renewable sources. For photovoltaic plants the national limit under the current FIT system is 18 MW with 4 MW assigned to plants with a capacity lower than 50 kW and 14 MW assigned to plants up to 1 MW. The Government sets FITs for all types of renewable energy sources except for geothermal energy.11



One of the most critical issues concerning the development of SHP plants in the future is the need for accurate hydrological data taken over an extended period of time, as some previous estimates of potential capacity have been criticized for overestimating the volume of water at some sites. Connection to the distribution grid is another crucial issue. Most of the potential SHP locations are in rural areas with either no connection or no stable, quality network. This means that the investment cost of grid connection is often very high. In the last several years a number of laws and sub-laws were amended in order to streamline the procedures for obtaining construction permits. However, another key challenge in the future is to establish a single authority for all the procedures, licences and permits in order to reduce the time needed to realize these projects.

SHP plants in Macedonia are constructed according to the Law on Waters and the Law on Concessions and Public Private Partnership.10 Between 2007 and 2011, the Ministry of Economy of the Republic of Macedonia conducted five tendering procedures for granting water concessions for electricity production from SHP plants. The Ministry of Economy signed 66 concession agreements with 23 concessioners, both foreign and domestic, with a combined installed capacity of 60 MW and estimated annual production of 240 GWh. The level of investment is expected to be between EUR 120 and 150 million (US$150 million To US$200 million). In 2011, the Ministry of Environment and Physical Planning became responsible for granting water concessions for 580

4.4

Western Europe Miroslav Marence, UNESCO-IHE


The electrical energy portfolio is different from country to country dependent on their strategy, as well as geographic and climate characteristics. Renewable energy sources in the north are ruled by onshore and offshore winds. Geothermal, biomass and solar power are being developed in all regions, especially in Germany with strong renewable policies. In the Alpine region, large and SHP have a dominant role in electrical energy production and contribute, as in Austria,1 up to 60 per cent of the country’s electrical energy production. The hydropower potential, especially of large hydropower, is nearly fully developed, and development is mostly still possible in the SHP sector. Although some countries increased the share of SHP, others saw a decrease (in some cases due to newer, more accurate data), while the overall share of SHP in the region remained around the same.

Western Europe includes nine countries, seven of which use small hydropower (SHP) (excluding Monaco and Liechtenstein). The geographic characteristics of the region can be characterized as mountainous in the south and south-east (Alpine region), over hilly uplands into broad low plants on the north and north-west, with a small part of Mediterranean in south-west. The dominant climate is continental and temperate, with a maritime climate on the coast. All countries of Western Europe have 100 per cent access to the electricity. As a part of the European market of the electrical transmission grids, all of these countries are strongly connected and working together under the coordination of ENTSO-E, the European Network of Transmission Systems. The national electrical grids, integrated in a cross-border electricity market, are challenged not to produce enough energy, but to secure and stabilize the whole European grid under very rigorous criteria for grid variation in frequency and voltage.

FIGURE 2

Net change in installed capacity of SHP (MW) from 2013 to 2016 for Western Europe 259

FIGURE 1


France 35%

Switzerland

Netherlands

Luxembourg

-79

Germany

Belgium 1%

Germany 25%

France

Austria 24%

Belgium

11 Austria

Luxembourg 0% Switzerlands Netherlands 15% 0%

99

94

Sources: WSHPDR 2013,20 WSHPDR 2016 21 Note: The comparison is between data from WSHPDR 2013 and WSHPDR 2016. A negative net change can be due to closures or rehabilitation of SHP sites, and/or due to access to more accurate data for previous reporting.


TABLE 1

Overview of countries in Western Europe (+ % change from 2013) Country

Total Population (million)

Austria

8.69 (+6%)

32

Belgium

11.25 (+8%)

France Germany

Rural National population electricity (%) access (%)





100

21,954 (+3%)

68,015 (–4%)

12,452 (–2%)

39,851 (–7%)

3

100

15,802 (+0%)

91, 000 (0%)

107 (0%)

300 (0%)

66.63 (+1%)

15

100

128,943 (+4%)

550,300 (0%)

25,419 (+19%)

68,000 (0%)

81.45 (0%)

26

100

199,200 (+16%)

647,000 (+6%)

4,350 (0%)

19,147 (0%)

Luxembourg

0.57 (+12%)

15

100

1,800 (9%)

2,859 (–37%)

40 (+1%)

102 (0%)

Netherlands

16.88 (0%)

17

100

31,250 (+17%)

116,800 (–1%)

37 (–2%)

109 (0%)

Switzerland

8.3(+4%)

26

100

17,855 (0%)

69,633 (9%)

12,297 (0%)

39,308 (+5%)

193.77 (+1%)

—

100

416,804 (+10%)

1,543,262 (+2%)

Total

Sources: Various1,2,3,4,5,6,7,20,21 Note: The comparison is between data from WSHPDR 2013 and WSHPDR 2016.

581

54,702 (+8%) 166,817 (–1%)


Regional SHP overview and renewable energy policy

In order for the European countries to achieve their renewable energy targets by 2020, including the integration of a large amount of wind and solar power to the European electricity transmission system, new infrastructure is crucial. New high voltage trans-boundary lines and enough electrical energy storage capacity are critical for net security and stability.

Austria, Belgium, France, Germany, Luxembourg, the Netherlands, and Switzerland are the seven countries that use SHP. SHP support mechanisms exist in all countries through tradable green certificates (Belgium), investment support or subsidies (the Netherlands, and for Austria from 2010 onwards), and feed-in tariffs (Austria, France, Germany, Luxembourg, Switzerland). The Water Framework Directive is being implemented in all European Union member states (only Switzerland is not part of the European Union).

TABLE 2

Classification of small hydropower in Western Europe Country

Small (MW)

Mini (MW)

Micro (kW)

Pico (kW)

Austria

2-10

0.5-2.0

50-500

Up to 50

Belgium

< 10

—

—

—

France

2-10

0.5-2.0

Up to 500

—

< 5 or < 1

—

—

—

Luxembourg

1-10

up to 1

—

—

Netherlands

< 10

—

—

—

Switzerland

1-10

0.1-1.0

—

—

Germany

The total installed SHP capacity (defined as up to 10 MW) is around 6,000 MW in Western Europe. France has the highest installed SHP capacity, followed by Germany, Austria and Switzerland. Table 3 shows the installed SHP capacities, most of the information on SHP potential was not available so planned capacity additions were reported instead. The Stream Map project reveals that during the last 10 years new SHP potential in Western Europe has been greatly affected by environmental legislation, especially for sites in designated areas, such as Natura 2000, and sites affected by the Water Framework Directive, among others.18

Sources: Various8,9,10,15,21

The pump-storage hydropower plants are still the most reliable electricity storage method of providing necessary power and capacity. Several pump-storage projects in the area are under construction with more pump-storage plants in the preparation phase, but development has been slowed down by low energy price levels in Europe in recent years.

Mitigation measures will add to the costs of electricity generation. Germany, the fourth largest country with regard to SHP installed capacity within the EU, experienced the largest reduction of its hydropower resource; only 7 per cent of the economically feasible potential can be realized under current conditions. Slightly larger environmentally compliant potential has been identified in France (some 50 per cent). In Austria, the Stream Map project, for example, recommends higher economic support to cover the additional environmental costs.18

Small hydropower definition While all the countries (except Switzerland) are part of the European Union, the SHP definition is not universal and various SHP definitions are applied (Table 2). All countries (except Switzerland) have published data on plans to increase SHP, in some cases significant increases can be expected.

Barriers to small hydropower development All countries have to increase their renewable energy share by 2020. The endeavoured share of the renewable

TABLE 3

Small hydropower in Western Europe (+ % change from 2013) Country

SHP potential (MW)

Planned SHP (MW)


Annual generation (GWh)

Austria

1,780 (+36%)

412

1,368 (+23.3%)

6,158 (+23.5%)

Belgium

103 (+11.9%)

31

72 (+18%)

352 (+84%)

France

2,615 (0%)

594

2,021 (–4.2%)

5,436 (–21.4%)

Germany

1,830 (0%)

N/A

1,826 (+5%)

8,043 (0%)

Luxembourg

44 (0%)

10

34 (0%)

100 (0%)

Netherlands

12 (+300%)

9

3 (0%)

8 (0%)

Switzerland

At least 859 (+13%)

N/A

859 (13%)

3,770 (10.8%)

7,243 (+9%)

>1,056

6,180 (+6%)

23,867 (+0.9%)

Total

Sources: Various Note: The comparison is between data from WSHPDR 2013 and WSHPDR 2016. 11,12,13,14,15,16,17,21

582

of the European Water Framework Directives,19 strict environmental conditions (ecological minimum flow, fish up- and downstream migration possibility, fish friendly turbines, free sediment transport along rivers, and influence of flow variation by hydropeaking) are restricting the energy production and jeopardizing technical and economic viability of new and also existing projects. Licensing procedures of the of the completely new hydropower sites must include comprehensive assessments of environmental (including limnological) concerns with respect to European, national and federal but also the welfare of stakeholders such as fisheries, tourist or recreation groups. Modification of the regulations and clarification of the environmental rules is expected in 2017 on the European level.

sources in the country energy mix is different for each of the countries, ranging from 34 per cent in Austria to just 14 per cents in the Netherlands. The difference is triggered by the regional availability of the renewable energy sources. The main natural limitation for hydropower is locally available hydrological potential of the region, especially available hydraulic head. In the countries with a low head potential such as the Benelux countries or North Germany, additional promising hydro-potential is in the installation of the plants on existing navigation and flood control weirs. However, with higher environmental expectations regarding hydromorphology due to the implementation

583

Western Europe

4.4

4.4.1

Austria Martina Prechtl-Grundnig and Thomas Buchsbaum, Kleinwasserkraft Österreich


8,699,7301

Area

83,878.99 km²

Climate

A temperate, continental climate. Cloudy, cold winters between December and January with frequent rain and some snow in the lowlands and snow in the mountains with temperatures averaging between –7°C and –1°C. Summers, between June and August, are moderate with occasional showers and temperatures averaging between 18°C to 24°C in July. There are three climatic regions: – East: Pannonian climate with a continental influence; low precipitation, hot summers, but only moderately cold winters; – Alpine Region: Alpine climate with high precipitation (except inner Alpine valley regions such as the upper Inntal), short summers, long winters; – Remainder of the country: transient climate influenced by the Atlantic (in the West) and a continental influence in the South East.2

Topography

Mountainous in the south and west (the Alps), along the eastern and northern borders the country is mostly flat or gently sloping. The Alpine regions comprise 67.1 per cent (56,244 km2) of Austria’s total land area. The highest point is Grossglockner at 3,798 metres.2

Rain pattern

Rainfall ranges from more than 1,020 mm annually in the western mountains to less than 660 mm in the driest region, near Vienna.2


Austria is situated in 3 transboundary river basin districts: Danube, Rhine, and Elbe. Overall, there are 7,339 river water bodies and 62 lakes. Approximately 96 per cent of Austria’s territory is part of the Danube River basin, which has an average flow of 1.955 m³/sec at the border to Slovakia. Approximately 3 per cent of the territory is part of the Rhine basin and 1.1 per cent the Elbe River basin.2


was 68,015 GWh, with hydropower (including small hydropower) contributing more than 39,851 GWh, or approximately 57 per cent.19 The total share of renewable energy in the electricity sector was 67 per cent.4 The exchange balance was 7,271 GWh with the majority of the imported electricity coming from Germany (50 per cent) and Czechia (42 per cent).4


Total installed capacity in Austria, as of 1 January 2016, was 21,954.89 MW. Slightly more than half (50.3 per cent) was from hydropower installations, including pumped storage facilities. Approximately 19 per cent came from gas powered plants, 10.5 per cent from wind energy, 4 per cent from coal, and the remainder from other sources including oil, solar, biomass and geothermal resources (figure 1).3

The electrification rate is 100 per cent and, aside from some remote mountain lodges, there is 100 per cent connection to the national grid. Following the Austrian Electricity Industry Organisation Act (EIWOG) in 2000, the Austrian Electricity market has become fully liberalized by adopting an unbundled market structure with E-control operating as the state-owned independent regulatory authority. Verbund is the largest electricity provider covering approximately 40 per cent of the country’s electricity demand with almost 90 per cent of its generation from hydropower plants. The company also has purchase rights to electricity generated from 20 hydropower plants owned by several other companies. Verbund is listed on the Vienna Stock Exchange as well as the Austrian Traded Index (ATX) with the Republic of Austria as the majority shareholder with 51 per cent of the shares. Other significant hydropower producers include

FIGURE 1

Installed capacity by source in Austria (MW) Hydropower

11,054

Gas

4,187

Other

3,589 2,306

Wind power Coal

819

Source: Austrian Power Grid3

In 2013, the total electricity generation in Austria

584

Energie AG Oberösterreich, Energie Steiermark, EVN Group, KELAG, Salzburg AG, TIWAG-Tiroler Wasserkraft AG, Vorarlberger Kraftwerke AG and others. Electricity is traded over-the-counter or on an energy exchange such as the European Energy Exchange (EEX) or the Energy Exchange Austria (EXAA). The EXAA is a public limited company, owned by the Vienna Stock Exchange as well as a number of different companies from the Austrian energy sector, which operates a day-ahead electricity spot market. The Austrian Power Grid (APG), a 100 per cent subsidiary of Verbund AG, operates the transmission grid, which is part of the trans-European transmission grid.

FIGURE 2

Small hydropower installed and potential capacities in Austria 2013-2016 (MW) Potential 2016 2013

1,780

capacity

1,300

Installed

1,368 1,109

capacity

Sources: Energie-Control Austria,7 WSHPDR 20138 Note: The comparison is between data from WSHPDR 2013 and WSHPDR 2016.

Austrian electricity consumers pay a price based upon three components: the amount charged by the supplier which is set by individual suppliers; a network charge to the system operator which is set by E-control and based upon the grid connection of individual consumers; and taxes and surcharges levied by the State, including VAT. In 2013, the average gross cost, including energy taxes and VAT, was EUR 0.205 (US$0.273) for households and EUR 0.106 (US$0.141) per kWh for industrial users.5

According to the Austrian Energy Strategy 2020, the new target for SHP is to achieve a generation of 8,000 GWh, from an installed capacity of approximately 1,780 MW by 2020 (Figure 3).9 Recent studies from three out of the nine federal states in Austria show there is still potential for SHP development. Considering all European directives and Austrian laws, especially those for nature conservancy and water protection, undeveloped SHP potential annual generation is estimated as at least 600 GWh/a in Tirol, 500 GWh/a in Styria, and 100 GWh/a in the large rivers of Upper Austria.10,11,12

Small hydropower sector overview and potential Regulated by ÖNORM, small hydropower (SHP) is defined as plants with a maximum capacity of 10 MW.6 Austria has an estimated total installed SHP capacity of 1,368.4 MW. However, there is no reliable data on the potential installed capacity in the country. Nonetheless, in the 2013 World Small Hydropower Power Development Report, potential capacity was based upon a government target of achieving 1,300 MW installed capacity from 2,870 SHP plants by 2020.

FIGURE 3

8 6 4

2020

2013

2012

2 0

Total annual production (TWh)

10

2011

With the current installed capacity of 1,368.4 MW (an increase of 23 per cent compared to data from 2013) with a valued production (based on average 4,500 full load hours) of 6,157.8 GWh from 2,986 plants, this target has already been achieved.7 A new target of 1,780 MW capacity has been set implying that there is, at least, this potential in the country, 76.9 per cent of which has so far been achieved (Figure 2). The Stream Map project has also detailed the potential within the country as 3,350 MW of theoretical potential, 2,450 MW of technically feasible potential and 2,100 MW of economically feasible potential. However, regarding economic potential with environmental constraints as of 2009, the amount was estimated at 1,650 MW.18

3.0 2.5 2.0 1.5 1.0 0.5 0.0

2010

Installed capacity (GW)

Small hydropower capacity and annual production in Austria 2010-2020

Sources: Erneuerbare Energie Österreich,9 ESHA18

Approximately 85 per cent of the total electricity produced in SHP plants in Austria receives a market price. In most cases, the plant operator sells directly to a trader in the private sector. In very few cases, the energy is traded at the EEX platform in Leipzig, Germany. In both instances, the obtained price is strongly linked to the Phelix Base Quarter Future derivatives, which is traded at EEX. A market based purchase price determined on the Phelix Base Quarter Future is also settled in the Austrian Green Electricity Act (ÖSG), which was last amended in 2012. This price is determined quarterly by Energie-Control Austria as shown in Figure 4.13

The 2,986 SHP plants identified above are certified as Green Power Plants by the Austrian authorities. However, not all SHP plants are identified as such. Thus the actual number of SHP plants, and therefore the total installed and generating capacity, has the potential to be significantly higher. Currently SHP accounts for approximately 11 per cent of the total installed hydropower capacity and approximately 15 per cent of the total annual generation.

Before 2003 the federal states of Austria had individual tariff regulations. Starting in 2003, a new tariff system was installed country-wide. The tariff was dependent on the amount of electricity delivered into the public grid. For new SHP plants (or those undergoing refurbishment that increases the mean annual production or capacity more than 50 per cent) the tariffs are shown in Table 1. 585

Western Europe

4.4

Market price for small hydropower in Austria (2003-2015) 120 100 US$/MWh


between investment support or the feed-in tariffs as shown in Table 4. SHP plants above 2 MW have to take an investment support equal to that of the 2010 installed system.

FIGURE 4

TABLE 3

80

Small hydropower investment support system in Austria 2010

60 40

Installed capacity

20 0 2003 2005 2007 2009 2011 2013 2015

Less than 50 kW

1,500 EUR/kW (US$2,000/kW)

500-2,000 kW

20-30 per cent of investment up to a max. EUR 1,000-EUR 1,500/kW (US$1,300-US$2,000/kW)

50-500 kW

30 per cent of investment up to a max. EUR 1,500/kW (US$2,000/kW)

2-10 MW

10-20 per cent of investment up to a max. EUR 400-EUR 1,000/kW (US$500US$1,300/kW)

Source: Energie-Control Austria 13 TABLE 1

Small hydropower feed-in tariffs for new plants in Austria 2003 Electricity delivered to the grid

Tariff (EUR (US$) per MWh)

Up to 1 GWh:

62.5 (83.25)

The next 4 GWh:

50.1 (66.73)

The next 10 GWh:

41.7 (55.54)

The next 10 GWh:

39.4 (52.48)

And if more than 25 GWh:

37.8 (50.35)

Support description

Source: Energie-Control Austria13 TABLE 4

Small hydropower investment support system in Austria 2010 Delivered electricity (MWh)

Source: Energie-Control Austria13

If the operator of the plant was able to refurbish the plant to increase the mean annual production or the capacity by more than 15 per cent, tariffs demonstrated in Table 2 were applied.

Feed-in tariffs (EUR (US$) per kWh) Refurbishment New SHP or > 15% refurbishment > 50%

0-500

0.0810 (0.1079)

0.1034 (0.1377)

500-1,000

0.0591 (0.0787)

0.0743 (0.0990)

1,000-2,500

0.0512 (0.0682)

0.0649 (0.0864)

2,500-5,000

0.0373 (0.0497)

0.0542 (0.0722)

TABLE 2

5,000-7,500

0.0345 (0.0460)

0.0512 (0.0682)

Small hydropower feed-in tariffs for refurbished plants (> 15%) in Austria 2003

7,500-10,000

0.0317 (0.0422)

0.0487 (0.0649)

Electricity delivered to the grid

Source: Energie-Control Austria

13

Tariff (EUR (US$) per MWh)

Up to 1 GWh:

59.6 (79.39)

The next 4 GWh:

45.8 (61.01)

The next 10 GWh:

38.1 (50.75)

The next 10 GWh:

34.4 (45.82)


Starting from 2010, an investment support system has been installed replacing the FIT system (Table 3). However, the new system is only valid for new plants constructed and set into operation after 2010. Existing plants running under the FIT system will continue to receive the tariffs.

The Austrian Energy Strategy 2020 aims to increase the share of renewable energy to 34 per cent, reduce greenhouse gas emissions in sectors not subject to emissions trading by at least 16 per cent, and to achieve a 20 per cent growth in energy efficiency by 2020.14 However, this is seen as an interim target between the longer term target of 100 per cent self-sufficiency by 2050.15 Studies by the Austrian Environment Ministry show this target to be technically feasible. They note, however, “that the room for manoeuvre for a 100-percent supply from renewable energy sources by 2050 is rather small”, predicting that in order to achieve this target more than half of the country’s energy demand will be met by biomass and hydropower.16

Since the Green Electricity Act was last amended in 2012, new SHP plants (or those undergoing refurbishment that increases the mean annual production or capacity more than 15 per cent) with a capacity below 2 MW can choose

The Austrian Eco-Electricity Act 2012 entered into law on 1 July 2012 and includes the following innovations: }} A one-off payment of approximately EUR 110 million (US$119.5 million) to reduce the waiting list for

And if more than 25 GWh: Source: Energie-Control Austria

33.1 (44.09) 13

586

}}

}}

}} }}

}}

}} R estructuring of the funding tools: Greater transparency in connection with considerable concessions for low-income households and energyintensive enterprises.17

projects dealing with wind, photovoltaics, and smallscale hydro power stations; Raising of the former annual subsidization budget of EUR 21 million (US$22.8 million) to EUR 50 million (US$54.3 million). Within 10 years this budget will be reduced by annually EUR 1 million (US$1.1 million), to an amount of EUR 40 million (US$43.5 million); New, binding, eco-electricity targets for the year 2020 based on gains in capacity (MW) and production (TWh) for eco-electricity generated from waterpower, wind energy, biomass/biogas, and photovoltaics; There will again be separate subsidization budgets for the individual technologies; The raw material surcharge for biogas plants was further developed and became a surcharge on operating costs; Useful incentives and measures to further enhance the efficiency of the subsidization scheme and the eco-electricity projects submitted;

Barriers to small hydropower development A very low market price for electricity, which has been below EUR 40/MWh (US$53/MWh) since the beginning of 2013, is creating pressure on the whole SHP sector, in particular for plants with a capacity higher than 2 MW and for operators who are forced to invest in fish bypass systems or build/refurbished a SHP plant with investment support. Requests from the Government regarding environmental concerns, such as fish bypassing and reserved flow, are increasing continuously, and sometimes the consensus reached is not stable and reliable. In general, public opinion towards SHP is good. However, some opposition to local development from local populations may cause delays in project realization.

587

Western Europe

4.4

4.4.2

Belgium Johanna D’Hernoncourt, Association for the Promotion of Renewable Energies (APERe); Sonya Chaoui, SPW-DGO4, Department for Energy and Sustainable Housing


11,258,4341

Area

30,527.92 km2

Climate

Maritime temperate, mild in the summer and in the winter, with differences between the coastal zone and the mainland. The average temperatures in January range between 0.7°C and 5.7°C, and in July between 14°C and 23°C.3

Topography

Coastal plain in the North west, central plateau (about 100 metres above sea level) and Ardennes uplands in the South-East (South of the Rivers Sambre and Meuse furrow) with highest peak: Signal de Botrange at 694 metres.2

Rain pattern

Precipitation in the form of rain is significant: between 700 mm and 850 mm annually, for 200 days on average, with a variability of about 25 days (230 days in the High Fens and 182 at the coast).3


Suspected to increase in the years to come due to climate change. Combined to smaller debits in the rivers in the summer, suspected to induce water shortages.4


With technical problems in three reactors out of seven during the 2014 winter, the country has been depending on imports, and needed to constitute strategic reserves to ensure electricity supply in case of a cold winter (in this case the demand is high in all of Western Europe). An energy pact to provide a view at the 2050 horizon (including development of renewable energy) is under discussion between the federal government and the regions.


Belgium is a federal state of three regions: the Flemish region, the Walloon region and the Brussels-Capital region. The evolution of the Belgian energy policy has been shaped by this system, and has led to the transfer of wide competences from the federal state to the regions. Energy consumption in 2013 was 405 TWh, of which fossil fuels accounted for 82 per cent and nuclear for 10 per cent. Since 2005, the renewable sources share in energy consumption have increased from 2.3 per cent to 7.7 per cent (31 TWh).5 The objective is to reach 13 per cent according to the European Directive on the promotion of the use of energy from renewable sources.6 The installed capacity for electricity production from renewable sources was 5.1 GW for a total capacity estimated to be 20.6 GW by the Transport System Operator Elia, of which 53 per cent for solar photovoltaic, 34 per cent for wind energy, 11 per cent for biomass, and 2 per cent for hydropower.15 In 2013, the production of electricity from renewable sources reached 3.7 TWh in Wallonia, 6.3 TWh in Flanders and 105 GWh in the Brussels Region.7

FIGURE 1

Electricity generation by source in Belgium (TWh) 40.6

Nuclear Gas

20.9

Other Wind

4.5 1.9

Biomass

1.7

Pumped storage

1.3

Hydropower 0.1 Solar 0.02

According to the World Bank, 100 per cent of the Belgian population has access to electricity.8 The Belgian grid is well developed, and the main challenge currently is its management of integrating variable and decentralized energy production.9

Source: Belgian Observatory of Renewable Energies7

In 1999, Belgium implemented the European Directive concerning the internal markets in electricity, which organized the unbundling of the roles in the electricity market (production, transport, distribution, supply, regulation, etc.) and included progressive privatization.10 The CREG (Commission de Régulation de l’Electricité et

Phasing out nuclear production is politically favourable but the timing is still under discussion at the federal level.

588

du Gaz) on the federal level and three regional entities act as regulators on the electricity and gas markets, and they control the distribution tariffs. In May 2015, the electricity for private use costs EUR 0.199/kWh (US$0.22/ kWh) with small differences between regions due to price differences for the distribution system operators.11

identified.17 A part of these historical heads could be equipped, for an estimated increased annual production of 2.6 GWh by 2020 and an additional 1.8 GWh by 2030.18 Most of these sites are in the private domain, with private investment for refurbishment. The development of citizen co-operatives for the investment in the refurbishment of small sites is progressing. Revamping of historical sites currently in operation is expected to bring a capacity gain of 5 per cent which corresponds to 18 GWh of increased annual production.19 Depending on the age of the installations, the revamping will be undertaken progressively in the coming 10 to 15 years. By the 2030 production of 460 GWh could be reached.

Small hydropower sector overview and potential The definition of small hydropower (SHP) in Belgium is up to 10 MW. Installed capacity of SHP is approximately 71.5 MW while the potential is estimated to be 103.4 MW indicating that 69 per cent has been developed. Between the 2013 and 2016 World Small Hydropower Reports installed capacity has increased by approximately 17 per cent while estimated potential has increased by approximately 12 per cent (Figure 2).

The Walloon government and the electricity and gas regulator CWaPE (Commission Wallonne pour l’Energie) have recently revised the supporting mechanism for new hydropower projects through green certificates. The aim is to reach an Internal Rate of Return for the projects of 7 per cent after tax.20 Moreover, since 2014, the public investment aid in Wallonia (up to 20 per cent of the total cost) also allows for the eligibility of environmental investments (fish licenses for a cost of a maximum 35 per cent of the total investment).21 Since environmental investments such as fish licenses constitute an economic barrier to large scale projects, this change in regulation brings new opportunities for SHP developments. Although the country’s hydropower potential is already well exploited, the economic incentives put in place and the equipment program of the navigable waterways are expected to bring the sector even closer to its technical potential.

FIGURE 2

Small hydropower capacities 2013-2016 in Belgium (MW) Potential 2016 2013

103.4 92.0


71.5 61.0

Sources: ICEDD,13 WSHPDR 2013 14 Note: The comparison is between data from WSHPDR 2013 and WSHPDR 2016.


With only two sites equipped with plants over 10 MW capacity (40.744 MW installed or 36 per cent of total installed capacity), most sites equipped in Belgium are considered SHP.12 Installed capacity in Belgium in 2014 was 112.216 MW on 115 sites,13 for a net normalized production of 351.8 GWh.6 In 2013, the production accounted for 0.46 per cent of the final electricity consumption. Most of the sites (85 per cent in terms of number, 99 per cent in terms of capacity) are installed in the southern part of Belgium, in the Walloon Region. About three quarters of installed capacity (on 14 sites) are on navigable waterways.7 The main remaining potential is situated on navigable waterways in the Walloon Region. The regional government and its management entity SOFICO have adopted the decision to concede for private operation (20 years) 21 public sites on the Rivers Meuse, Sambre and Ourthe,16 for a total of 71 GWh of increased annual production by 2020. These sites have smaller heads (2 to 3 metres) than sites that that have been exploited historically on navigable waterways. For a long time, it constituted a challenge to find an economically viable technical solution.

Belgium uses a tradable green certificate (TGC) system as its primary support mechanism for the deployment of renewable power technologies. There are four different TGCs (i.e. Federal, Flemish, Wallonian and Brussels green certificates) that vary in price and conditions. The Federal Government is currently working on an energy pact, to provide the country with a vision of its energy sector at the 2050 horizon. Each region is in charge of defining the roadmaps to reach regional targets for renewable energy production, in the framework of the national target of 13 per cent of the final gross energy consumption. During 2015, the Walloon government already drafted a roadmap for renewable energy development towards 2030.22 The roadmap still needs to pass a few legislative steps to be fully adopted and binding. It specifies the targets of respectively 380 and 420 GWh of annual hydropower production by 2020 and 2030. Belgium is progressing towards its objective of 13 per cent of renewable energy in energy consumption. A clear road map agreed by all regions is awaited to plan for the future years and beyond 2020. Barriers to small hydropower development

Belgium also has a strong history of hydropower exploitation on non-navigable waterways before and during the industrialization period. More than 2,500 sites of old mills or factories driven by water have been

Hydropower has historically been largely exploited in Belgium. In the Walloon Region, the equipment plan for

589

Western Europe

4.4


navigable waterways and the revision of financial support for SHP development are expected to bring the sector even closer to its technical potential. However, with higher environmental expectations regarding hydromorphology due to the implementation of the European Water Framework Directive,23 strict environmental conditions

(ecological minimum flow, free fish migration up- and downstream, fish friendly turbines, etc.) are imposed on investors and sometimes jeopardize the technical or economic viability of the projects. A change in regulation to help clarify the environmental rules is expected in 2017.24

590

4.4.3

France European Small Hydropower Association, Stream Map; Jean Marc Levi, France Hydro Electricité


63,697,8651

Area

549,000 km2

Climate

Three types of climate may be found; oceanic (west), continental (central, east) and Mediterranean (south), (except in the mountainous south-west). Average temperatures in northern Brittany are 6°C in winter and 16°C in summer. Paris averages a yearly temperature of 11°C. The southern coastal city of Nice experiences an annual average of 15°C.2

Topography

Mostly flat plains or gently rolling hills in north and west; the remainder is mountainous, especially the Pyrenees in the south and the Alps in the east. The country’s highest point is Mont Blanc at 4,807 meters.2

Rain pattern

Annual precipitation ranges from 680 mm in the central and southern region to 1,000 mm around Paris / Bordeaux. In the northern coastal and mountainous areas precipitation can reach more than 1,120 mm.2


Five major rivers create the drainage system of France. The Seine (780 km) flows through the Paris Basin and has three tributaries, the Yonne, Marne and Oise Rivers; it finally drains into the English Channel. The Loire (1,020 km) is the longest river in France and flows through the central region. The Garonne is the shortest of France’s major rivers. It rises in the Pyrenees, across the border with Spain, and empties into the Bay of Biscay at Bordeaux. The Rhône is the largest and most complex of French rivers. Rising in Switzerland, it flows southward through France for 521 kilometres, emptying into the Mediterranean. Lastly, the Rhine flows along the eastern border for about 190 kilometres (118 miles), fed by Alpine streams.2


Transport and Electricity. The French electricity market is open. However, it remains largely dominated by the formerly state-owned EDF. EDF had an installed capacity of 98,237 MW at the end of 2014 (76 per cent of the total installed capacity of France). The electrification rate of the country is 100 per cent.6

The total installed capacity in France at the end of 2014 was 128,943 MW (Figure 1).5 Approximately 49 per cent of the total installed capacity came from nuclear energy. Hydropower capacity was 19.7 per cent of the total installed capacity, while fossil fuel-fired thermal capacity represented 18.7 per cent. The total wind power capacity was 7 per cent, and the total solar energy capacity was 4 per cent. This offset 1,240 MW of closures at coal-fired plants, and 65 MW at oil-fired plants.5 Net electricity generation for 2015 was 37,921 GWh.

Small hydropower sector overview and potential In France, small hydropower (SHP) is defined as plants having an installed capacity up to 10 MW. The SHP installed capacity is 2,021 MW, and potential is approximately 2,615.7

FIGURE 1

Installed capacity by sources in France in 2014 (MW) FIGURE 2 Nuclear Hydropower

25,419

Fossil fuel Wind power Solar power

Small hydropower capacities 2013-2016 in France (MW)

63,130

24,441

Potential

9,121

2016 2013

5,292

Installed capacity

Source: Ministry of Energy5

2.615 2.615

capacity 2,021 2,100

Sources: Eurobserver,7 WSHPDR 20139 Note: The comparison is between data from WSHPDR 2013 and WSHPDR 2016.

The Ministry of Ecology, Sustainable Development and Energy is in charge of regulating energy matters. The electricity grid is owned and operated by Réseau de 591

Western Europe

4.4


For small hydro, the total potential is estimated at 527 new Greenfield sites (1,214 MW and 4,368 GWh), and at equipping 734 of existing small weirs (303 MW and 1,068 GWh). To estimate the feasible potential, the following ratio was applied: cut one third for economic and technical constraints and another third for environmental constraints (revision of classification in course), i.e. 419 power plants, 525 MW and 1,812 GWh by 2020.

and by geographical area, qualitative and quantitative regional targets for the valorization of potential territorial renewable energy, taking into account the national targets. In practice, this means identifying all sources for the production of renewable energies and of energy savings according to socio-economic and environmental criteria, and defining, in association with the local stakeholders (infra-regional authorities, companies and citizens), the level of regional contribution in achieving the targets set by France. This plan represents a strategic planning tool to guide the activities of local and regional authorities.6 SRCAE is in progress.

A commitment agreement for the development of sustainable hydropower in compliance with aquatic environments restoration requirements was signed in June 2010 to promote hydropower, if deemed suitable considering the environmental specifications. A part of the agreement directly concerns the equipment of existing weirs. The methodology and the “suitable conditions” to build a power plant onto existing weirs need to be made more precise. A guidebook Towards the Hydroelectric Plant of the 21st Century for the development of SHP plants with regard to the natural environment is available.10 It defines standards for the conception of a highly environmental quality plant. This guide is recognized and disseminated by national administrations.

SRCAE, for hydropower potential, is based on producers’ data and compatibility with lists of no-go rivers and restoration of river continuity priorities. France was the second largest producer of renewable energy in the EU in 2012. The strong points of the country are hydro, biofuels, and geothermal energy used in heating networks. France has the potential to achieve important targets in the renewable energy production. The 2012 share of renewable energy in France amounted to 13.7 per cent; the target for 2012 has been defined as 23 per cent.

The French water administration drafted an inventory of obstacles in rivers, and aims to assess the degree to which those obstacles block the movement of species and sediment. A database was created in May 2012, including more than 60,000 obstacles such as dams, locks, weirs, and mills no longer in operation. A protocol called Informations sur la continuité écologique (ICE) has been also created to measure the capacity of obstruction of these obstacles.6 This vast project, brings together a large number of partners, identifies the installations causing the greatest problems and makes it possible to set priorities for corrective action. It will be also a good tool to identify new potential sites for SHP.

In August 2015, the Energy Transition Law was promulgated. This law set the framework for the energy transition towards a greener and cleaner energy. Legislation on small hydropower The maximum duration of permits is 75 years for big concessions. For relicensing, the duration is 20 years if there is no particular investment, and around 30 to 40 years if there is a significant investment. France has a lot of perpetual old permits for former mills subject to new environmental restrictions. The Government’s priority is a simplification of the legislation; some measures like “Unique Authorization” are removed. The idea is to comprise the different authorizations within one category in order to accelerate the process and relieve the administrative burden.

The Government and EDF are working on a guidebook for the environmental compliance of hydropower plants in France. The total hydropower potential in France is about 200,000 GWh/year. In 2014, there was 25,410 MW of hydropower capacity in operation therefore the SHP capacity constitutes about 9 per cent.3

Residual flow regulation exists, i.e. 10 per cent of interannual average flow, and for modules over 80 m3/s, 5 per cent of the module is admissible.8 While the minimum (10 or 5 per cent) is set by the law, the adapted minimum ecological flow is set case by case through environmental assessments. The most used method is the microhabitats method (EVHA), but there are other possible methods adopted when EVHA does not suit the type of river. Since 1984, the reserved flow was around 10 per cent of the average annual flow. Since 2006, 10 per cent is the minimum, and local administrators often ask for more (12 to 17 per cent), without any justification on improvement or maintenance of the ecological status. In periods of extreme low water levels, the Préfet, head of the Department (French subdivision) can decide to lower temporarily the residual flow. A feed-in tariff (FIT)

The Government sees renewable energy as playing an increasingly important role in meeting energy needs. According to a study released in November 2013 by the Ministry of Environment, France has the potential to increase its hydropower.7 Renewable energy policy A regional plan for climate, air and energy (Schéma régional du climat de l’air et de l’énergie, SRCAE), was jointly developed by the State and the regional authorities.11 In particular, this plan defines, for 2020

592

for installed capacity not exceeding 12 MW (art. 10 par. 2 Loi n°2000-108; art. 2 Décret n°2000-1196) has been established. H97 is a 15-year contract that was signed in 1997. This was renewed in October 2012 for another 15 years against a plan of investment.8 H97 FIT is between EUR 55 and EUR 65/MW (US$72 and US$85/MWh). H07 is a 20-year contract for new SHP plants or for the plants which are renewed (investment of EUR 1,172/kW (US$1,525/kW). The H07 FIT is between EUR 60 and EUR 100/MWh (between US$78 and US$130/MWh). Plants over 400 kW of installed capacity do not qualify for the tariff (threshold effect).

71 per cent of the hydropower potential) The French producers who cannot or do not wish to invest to benefit from a new FIT contract will have to sell their production directly on the market. The market price does not take into account specificities of the SHP production (i.e. the green value and the decentralized decentralized production. The level of market price (around EUR 38/ MWh in 2015) does not permit any investment, and may push some small units into bankruptcy. Conflict between river protection and hydro development is rising. The French Government is carrying out a pre-planning mechanism. The Government classifies the rivers in order to determine absolute-protected rivers for water bodies of high status, migratory species or ‘biodiversity reservoirs’ while areas with renewable potentials are designated at the regional level.

Barriers to small hydropower development One of the main barriers for SHP is the classification of rivers carried out by the Government in 2012 (affecting

593

Western Europe

4.4

4.4.4

Germany Stephan Theobald, Universität Kassel


81,459,0004

Area

357,340 km2

Climate

Warm and humid temperate mid-latitude climate, oceanic influence weakens from the northwest to the south-east, relatively mild winters and summers, occasionally very cold winters and very hot and dry summers. Mean temperature in winter (December – February) is 0.9°C and in summer (June – August) 16.3°C.9

Topography

Coasts and lowlands in the north, uplands in the centre, Bavarian Alps in the south with the highest altitude at Zugspitze peak (2,963 metres).10

Rain pattern

The average annual precipitation is 789 mm. The amount of rainfall decreases across the country from west to east.10


The main flow direction of rivers is from the southern Alpine region and central mean range mountains to the north (Rhine River, Elbe River, Weser River) and to the east (Danube River).10


may rise due to uncontrolled fluctuations of electricity production by some renewable energies like small photovoltaic electricity production facilities, efforts might be undertaken to upgrade necessary installations. Average electricity price in 2014 for households was EUR 0.297, but for industry EUR 0.144.12

The installed electricity generation capacity in 2015 was 199.2 GW.1 The gross power production in Germany in 2015 was 647 TWh.3 Of those, 161 TWh (26 per cent) came from renewable power sources (Bundesverband der Energie- und Wasserwirtschaft BDEW 2015) (Figure 1).


FIGURE 1


Electricity generation by source in Germany (TWh) Lignite Hard Coal Nuclear Energy Wind power Natural Gas Biomass Photovoltaic Others Hydropower Mineral Oil Waste

The definition of small hydropower (SHP) in Germany is up to 1 MW. However, definitions of up to 5 MW or even 10 MW can be seen in different documents.13 As of 2013, Installed capacity of SHP up to 10 MW in Germany was 1,826 MW (up to 5 MW was 1,372 MW and up to 1 MW was 660 MW; Figure 3)14 while the potential is estimated to be 1,830 MW indicating that nearly all currently identified SHP potential has been developed. Between the 2013 and 2016 World Small Hydropower Reports installed capacity has increased by 5 per cent while estimated potential has not changed (Figure 2).

155 118 91 86 57 44 38 26 20 5 5

Efforts on SHP are focused on modernization existing SHP. Additional SHP is often hindered by environmental concerns on stream ecology while the benefit of hydropower for climate protection is widely accepted. SHP projects are mainly financed by private companies.

Source: Federal Ministry for Economic Affairs and Energy7 Note: Data from 2015.

The rate of electrification is 100 per cent. Electricity is mainly produced by private companies with a minor portion of photovoltaic electricity production by private households. The power grid is run by private companies. Prices are partly guaranteed by feed-in tariff (FIT) for renewable energy and with power trading on the electricity stock exchange. Problems in grid stability

Renewable energy policy Renewable energy sources including those for electrical energy production are supported by a renewable energy feed-in tariff (FIT) under the legislation of the 594

FIGURE 2

The duration of a FIT is 20 years, while the tariffs are revised every four years. The FIT is set to: }} 12.52 EUR cents/kWh ≤ 500 kW; }} 8.25 EUR cents/kWh ≤ 2 MW; }} 6.31 EUR cents/kWh ≤ 5 MW; }} 5.54 EUR cents/kWh ≤ 10 MW; }} 5.34 EUR cents/kWh ≤ 20 MW.

Small hydropower capacities 2013-2016 in Germany (MW) Potential 2016 2013

1,830 1,830

capacity Installed

1,826 1,732

capacity

The EEG also includes additional regulations on annual decreases and on the fulfilment of environmental protection standards.

Sources: Bundesnetzagentur für Elektrizität, Federal Ministry for the Environment,14 WSHPDR 201311 Note: The comparison is between data from WSHPDR 2013 and WSHPDR 2016. 10 MW definition is used. Does not include pumped storage. 1

Besides the Renewable Energies Act, the European Water Framework Directive is influential on the development of SHP.6 A main objectives of the directive is “to establish a framework for the protection of inland surface waters” on water basin levels. This results in very relevant restrictions for the design and operation of new as well as for existing hydropower.

FIGURE 3

Small hydropower installed capacity in Germany by definition (MW)