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ARTIGO 01: Bloomberg - Outubro/2012 (nossos comentários) As eólicas alemãs estão provocando problemas para os vizinhos. Os que mais estão reclamando são os poloneses e checos. Eles estão instalando disjuntores nas fronteiras para se desconectarem do sistema europeu, a partir da Alemanha, toda vez que as eólicas criarem sérias instabilidades ao sistema devido a gerações intensas em períodos de bons ventos. Quando isso ocorrer, ficará pior ainda para a Alemanha, pois a carga interligada que recebia a intermitência vai diminuir. ARTIGO 02: The Financial Times - Novembro/2012 (nossos comentários) Este artigo mostra claramente os problemas que o sistema europeu de geração elétrica está enfrentando com a maior participação de fontes renováveis de baixo Fator de Capacidade, como eólica e solar na matriz energética. Com o despacho irregular (intermitente) e a necessidade de priorizar estas fontes quando geram, as fontes térmicas (carvão, gás e biomassa) que entram para regularização e atendimento da demanda de pico, estão sofrendo em suas margens a ponto dos governos (incluindo Alemanha, França e Reino Unido) estarem estudando a criação de remuneração de disponibilidade para garantir que estas fontes fiquem conectadas e disponíveis, garantindo as indisponibilidades e flutuações das fontes eólica e solar. Esta remuneração de disponibilidade das térmicas deverá representar um acréscimo de cerca de 3% nas contas dos consumidores. Este valor não é pouco, pois existe cerca de 10% dessas fontes renováveis no sistema, e mesmo assim aumentará 3% em 100% da energia, ou seja, essas fontes intermitentes estão sendo responsáveis por um aumento de 30% se essa correção fosse ser atribuída aos preços das eólicas e solares. ARTIGO 03: Duke Energy - Janeiro/2013 (nossos comentários) Para cada problema existe sempre uma ou mais soluções. A Duke Energy em parceria com o Governo Americano vem desenvolvendo desde 2009 e entrou em funcionamento a partir de dezembro de 2012, um mega sistema de estocagem de energia elétrica em bancos de baterias para resolver o problema de intermitência de um parque eólico de 153 MW. O investimento total foi de US$ 44 milhões, sendo metade do governo americano e metade da Duke Energy. Para tanto esse sistema foi dimensionado com 36 MW, ou seja 23,5% da potencia instalada em aerogeradores. Neste caso, em momentos de maior geração de energia, parte desta é armazenada quimicamente no banco de baterias para ser devolvida ao sistema nos momentos onde o parque eólico está gerando menos. Vale a pena ressaltar que estes 23,5% representam em

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ARTIGO 01: Bloomberg - Outubro/2012 (nossos comentários)

As eólicas alemãs estão provocando problemas para os vizinhos. Os que mais

estão reclamando são os poloneses e checos. Eles estão instalando

disjuntores nas fronteiras para se desconectarem do sistema europeu, a partir

da Alemanha, toda vez que as eólicas criarem sérias instabilidades ao sistema

devido a gerações intensas em períodos de bons ventos. Quando isso ocorrer,

ficará pior ainda para a Alemanha, pois a carga interligada que recebia a

intermitência vai diminuir.

ARTIGO 02: The Financial Times - Novembro/2012 (nossos comentários)

Este artigo mostra claramente os problemas que o sistema europeu de geração

elétrica está enfrentando com a maior participação de fontes renováveis de

baixo Fator de Capacidade, como eólica e solar na matriz energética. Com o

despacho irregular (intermitente) e a necessidade de priorizar estas fontes

quando geram, as fontes térmicas (carvão, gás e biomassa) que entram para

regularização e atendimento da demanda de pico, estão sofrendo em suas

margens a ponto dos governos (incluindo Alemanha, França e Reino Unido)

estarem estudando a criação de remuneração de disponibilidade para garantir

que estas fontes fiquem conectadas e disponíveis, garantindo as

indisponibilidades e flutuações das fontes eólica e solar.

Esta remuneração de disponibilidade das térmicas deverá representar um

acréscimo de cerca de 3% nas contas dos consumidores. Este valor não é

pouco, pois existe cerca de 10% dessas fontes renováveis no sistema, e

mesmo assim aumentará 3% em 100% da energia, ou seja, essas fontes

intermitentes estão sendo responsáveis por um aumento de 30% se essa

correção fosse ser atribuída aos preços das eólicas e solares.

ARTIGO 03: Duke Energy - Janeiro/2013 (nossos comentários)

Para cada problema existe sempre uma ou mais soluções. A Duke Energy em

parceria com o Governo Americano vem desenvolvendo desde 2009 e entrou

em funcionamento a partir de dezembro de 2012, um mega sistema de

estocagem de energia elétrica em bancos de baterias para resolver o problema

de intermitência de um parque eólico de 153 MW. O investimento total foi de

US$ 44 milhões, sendo metade do governo americano e metade da Duke

Energy. Para tanto esse sistema foi dimensionado com 36 MW, ou seja 23,5%

da potencia instalada em aerogeradores. Neste caso, em momentos de maior

geração de energia, parte desta é armazenada quimicamente no banco de

baterias para ser devolvida ao sistema nos momentos onde o parque eólico

está gerando menos. Vale a pena ressaltar que estes 23,5% representam em

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média a grandeza do problema, com um custo associado de R$

660.000,00/MW instalado de aerogeradores. Incrementando hoje cerca de

16,5% ao EPC de um parque eólico. Com a produção em escala desta solução

rapidamente custará cerca de 10% do EPC.

ARTIGO 04: Bloomberg - Março/2013 (nossos comentários)

A Bulgária também está tendo problemas com as fontes intermitentes. Querem

interromper o suprimento em até 40% da geração eólica e solar como parte do

esforço de estabilização do sistema elétrico do país. A rede está sofrendo com

sobrecarga causada pelo rápido aumento da geração eólica num momento que

houve redução da demanda decorrente da economia em crise. Trata-se do

problema clássico produzido pelas fontes intermitentes, que se inicia sempre

quando a potência instalada de eólicas ultrapassa 5% da carga do sistema,

comparando-se ao valor mínimo ao longo do dia e não pela média ou valor de

pico desta carga.

ARTIGO 05: Revista Opiniões – Março/2013 (nossos comentários)

O primeiro passo para a solução do problema é o reconhecimento do mesmo.

O Dr. Hermes Chipp, Diretor-Geral do ONS, em artigo publicado na revista

Opiniões em março de 2013, reconhece e alerta para o problema das

intermitências das eólicas com a seguinte declaração:

“Logicamente, as usinas eólicas e, futuramente, as solares são alternativas bastante interessantes para

diversificar nossa matriz de produção, mas são fontes intermitentes, ou seja, em algum momento, deixa

de ventar ou o sol não é suficiente para manter a geração instalada.

Nesses momentos, outros recursos têm de estar prontamente disponíveis para que os consumidores de

energia sejam plenamente atendidos, o que conduz à implantação de usinas termelétricas convencionais.

Hoje, esse é um dos maiores desafios do setor elétrico brasileiro. Como conviver com as fontes

intermitentes quando elas atingirem participação significativa na nossa matriz de produção?

Vemos duas alternativas: ou instalamos usinas térmicas a óleo para imediatamente serem acionadas

(usinas de backup), e, assim mesmo, alguma parcela já deveria ficar ligada como reserva girante, que é

uma geração que pode ser instantaneamente utilizada, ou deixamos essa reserva por conta de usinas

hidráulicas, bem mais rápidas para o aumento instantâneo de sua geração, desde que tenhamos água

suficiente para que essa oferta maior seja atingida, ou seja, é fundamental que as novas hidrelétricas

tenham reservatórios de acumulação.”

O nosso entendimento é exatamente esse que o Dr. Hermes expõe com muita

clareza. Em futuro próximo, teremos que escolher entre usar óleo para cobrir

os vazios da geração intempestiva das eólicas e/ou termos mais reservas

girantes nas hidroelétricas. As turbinas irão trabalhar em carga parcial,

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acarretando dois problemas: diminuição da eficiência da geração hidráulica e

em muitos casos trabalhando em zonas de cavitação.

O primeiro grande passo foi o reconhecimento do problema. O segundo deverá

ser analisar com profundidade, aproveitando-se da experiência europeia e

americana, quantificado esses fortes indícios de instabilidade que teremos em

futuro próximo no SIN. O terceiro passo será a implantação destas soluções

em paralelo com as novas contratações dos parques eólicos .

ARTIGO 06: GE - Maio/2013 (nossos comentários)

Na mesma linha da estocagem em baterias de parte da energia elétrica

produzida para mitigar a amplitude da intermitência, a GE está fabricando 03

turbinas eólicas de um total de 86, onde o banco de baterias está colocado na

própria torre eólica.

ARTIGO 07: Bloomberg - Agosto/2013 (nossos comentários)

Os japoneses desenvolveram e instalaram na Ilha de Hokkaido, uma bateria de

vanádio de 60 MW, ao custo de US$ 203 MM (US$ 3,383/KW), objetivando

amenizar (ou eliminar) a intermitência da energia gerada por fontes renováveis

(solar e eólica). O foco comercial principal da Sumitomo é a regularização das

eólicas no mercado europeu.

ARTIGO 08: The Financial Times - Fevereiro/2014 (nossos comentários)

As geradoras alemãs começam a divulgar balanços com prejuízos enormes,

resultado das políticas que priorizaram as energias renováveis (solar & eólica),

ao mesmo tempo que exigiam que as térmicas (principalmente à carvão)

ficassem garantindo a confiabilidade do sistema.

ARTIGO 09: The Financial Times - Março/2014 (nossos comentários)

Artigo do Financial Times sustenta que o programa de energia (renovável) da

Alemanha é caro, prejudicial e com visão de curto prazo. Desde 2000, os

preços da energia Alemanha subiram cerca de 80% em termos reais, e hoje

estão 48% acima da média Européia para os consumidores residenciais,

segundo estudo da consultoria McKinsey. A tarifa industrial já custa 19% acima

daquela praticada no conjunto da Comunidade Européia. As empresas Alemãs

já anunciam que irão fazer seus investimentos fora de lá para manter a

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competitividade, e pior, além de terem aumentado a dependência do gás

Russo após a paralisação das centrais nucleares, todo o esforço de

investimento em cima da energia renovável, que custará cerca de 100 bilhões

de Euros nos próximos 20 anos em subsídios, representa apenas 0,7% de toda

a energia primária consumida no país, e só contribuirão com apenas 37 horas

de sobrevida no aquecimento global ao final do século, segundo artigo

publicado no Der Spiegel. A Alemanha é um exemplo de como não se produzir

"energia verde", conclui o Artigo.

ARTIGO 10: Bloomberg - Julho/2014 (nossos comentários)

Entendemos que o governo, EPE, ANEEL, MME e ONS deveriam se reunir e

estudar, provavelmente contratando uma consultoria internacional que já

conhece esse problema, para termos certeza de que a boa modicidade tarifária

que as eólicas estão trazendo para o sistema não será revertida em poucos

anos devido ao aumento da potência instalada e consequente compra de

disponibilidade de outros geradores. Vejam a confusão que a geração

intermitente (eólica + solar) está criando para o sistema alemão, e afetando

principalmente as grandes geradoras. Necessita agora de um mercado de

capacidade de reserva para socorrer a rede em até 30 segundos, 5 minutos, 15

minutos, etc, remunerando a preços que podem chegar a 400 vezes o preço de

contratos de longo prazo. O mercado denominado de balancing market, já paga

cerca de US$ 1,1 bilhões por ano para as empresas que participam. Vejam que

o risco de um blackout potencial aumentou cinco (05) vezes em relação a 4

anos atrás. Desta forma se promove leilões diários e semanais para estas

empresas que entram neste mercado de capacidade e que podem iniciar um

suprimento em poucos minutos para garantir a estabilidade do sistema, e que

recebem um pagamento mesmo sem fornecer nenhuma energia à rede, mas

apenas para ficar disponível. Dependendo da hora do dia, estas empresas já

chegaram a receber até 13.922 euros (isto mesmo, treze mil novecentos e vinte

e dois euros por MW de capacidade de reserva disponível). Esta reserva de

capacidade ainda é pequena (cerca de 2,2% da potência total instalada no

país), mas está crescendo. Nesta semana, por exemplo, o sistema solicitou

que as geradoras participantes do programa reservem 3.898 MW numa

capacidade instalada total de 183.649 MW da Alemanha.

ARTIGO 11: WSJ - Agosto/2014 (nossos comentários)

Saiu no final da semana passada no WSJ um interessante artigo sobre o

programa energético da Alemanha sob um título que diz tudo: " O Caro Jogo

em Energia Renovável da Alemanha". O preço médio da eletricidade para as

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empresas aumentou cerca de 60% nos últimos 05 anos devido ao custo

repassado pelo governo dos subsídios pagos para as energias renováveis,

afetando seriamente a competitividade da indústria alemã e com possíveis

reflexos em toda Comunidade Europeia. Os preços da energia na Alemanha já

são mais de duas vezes os preços da energia nos EUA. Para implementar o

plano da Sra. Merkel (40% da geração total de renováveis até 2025 e 80% até

2050), os alemães terão gasto até 2040 aproximadamente US$ 1,4 trilhões, ou

50% do PIB alemão atual. Enquanto isso os demais países estão se

sustentando nos níveis mais baixos da meta para energia renovável e

segurando a energia nuclear na matriz, ao contrário dos alemães, para ver no

que vai dá. Como resultado desta política 75% das empresas alemães

disseram, numa pesquisa recente, que os altos custos da energia são o maior

risco que enfrentam e, a gigante da indústria química BASF, cuja maior planta

na Alemanha consome tanta energia anualmente quanto toda a Dinamarca,

informou que irá reduzir seus investimentos anuais na Alemanha de 1/3 dos 20

bilhões de euros que investe atualmente no país, para 1/4, redirecionando seus

investimentos para a Ásia e os EUA, especificamente por causa dos altos

custos da energia elétrica. A sobretaxa repassada aos consumidores de

eletricidade triplicou nos últimos 04 anos e agora representa cerca de 18% da

conta de luz média, totalizando cerca de 24 bilhões de euros anualmente.

Segundo o pesquisador Daniel Yergin do IHS, inicialmente houve um

entusiasmo de que os alemães estavam puxando a fila e sendo protagonistas

na energia renovável, mas agora os alemães olham para trás e descobrem que

não tem muita gente seguindo esta tendência. Energia renovável pode custar

muito mais caro do que se imagina.

O que está escrito acima é o resumo do texto, inclusive as conclusões do

jornalista para o caso da Alemanha. Agora eu vou fazer as minhas

considerações para o caso do Brasil, a luz dessa experiência alemã.

Os países frios, já aproveitaram o potencial de sua hidrografia e têm muita

dificuldade em produzir biomassa, uma árvore que fazemos no Brasil em sete

anos, eles precisam de trinta e cinco anos em média, além de ocupar um

espaço precioso para quem precisa produzir alimentos em países de alta

densidade demográfica.

A eles resta portanto a fonte eólica e a solar. Por isso investem nelas, por não haver outras opções viáveis em termos de renováveis. O resultado está sendo muito ruim, por terem subestimado o fantasma da intermitência dessas duas fontes.

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ARTIGO 12: Bloomberg - Julho/2015 (nossos comentários)

A França passou em 23/07/2015 no seu parlamento, Lei limitando as emissões

de CO₂, com consequente elevação da tonelada de CO₂ emitida dos atuais €

14.50/Ton para € 56.00/Ton em 2020, e € 100.00/Ton em 2030. A Lei também

determinou que o limite da capacidade instalada em geração nuclear no país

será dos atuais 63.200 MW, e todo o crescimento futuro será em outras fontes.

ARTIGO 13: Bloomberg - Agosto/2015 (nossos comentários)

O preço da energia no mercado Spot na Alemanha caíu abaixo dos € 30 /MWh

(R$ 124 / MWh) atingindo o preço mais baixo desde Outubro/2003, e está

derrubando o valor das ações das maiores geradoras como a E.ON (-33%) e

RWE (-48%) só este ano, basicamente decorrente da maior geração solar e

eólica na rede que está apertando os geradores tradicionais baseados em

carvão e gás. Segundo o artigo, mesmo a geração nuclear terá dificuldades em

pagar seus custos de produção, acelerando o processo de fechamento das

centrais nucleares, mesmo antes da data fixada para a desativação em 2022.

ARTIGO 14: Financial Times - Abril/2016 (nossos comentários)

Esta matéria informa que uma comissão do governo alemão finalmente fixou o

valor do custo de desmontar, limpar os resíduos radioativos e armazenar tais

resíduos em local seguro das usinas nucleares do país, que deverá ser feito

pelas duas principais empresas de eletricidade do país, RWE e E.ON, até

2022. Do valor total estimado em € 38 bilhões, as empresas deverão depositar

de imediato € 17 bilhões num fundo criado especificamente para este fim, e

contratar um seguro de risco adicional que custará mais € 6,3 bilhões,

totalizando um desembolso de € 23,3 bilhões, e ficarão isentas de

responsabilidades sobre novos custos, se necessários, no futuro. Apesar dos

protestos das duas empresas, alegando que causará grande pressão financeira

sobre as mesmas, a recomendação da comissão segue agora para se

transformar em Lei.

ARTIGO 15: Financial Times - Maio/2016 (nossos comentários)

A nova CEO da ENGIE (ex-GDF SUEZ/TRACTEBEL) afirma que os preços de

energia barata na Europa chegaram para ficar, e anuncia que a empresa irá se

desfazer de cerca de € 15 bilhões em ativos de geração não-renovável nos

próximos 03 anos, e investir € 22 bilhões em energia renovável, serviços de

energia, como redes de aquecimento e refrigeração, e tecnologias de energia

distribuída. A nova CEO assume a empresa num momento de grande transição

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do negócio de energia, e onde a ENGIE apresentou prejuízo líquido em 2015

de € 4,6 bilhões. A ENGIE tem 155.000 funcionários operando em 70 países.

ARTIGO 16: Bloomberg - Maio/2016 (nossos comentários)

No domingo 15/05/2016, às 14 horas, a geração renovável (hídrica, biomassa,

solar e eólica) na Alemanha atingiu 99,3% da demanda (45,5 GW de uma

demanda total de 45,8 GW), por algumas horas, provocando uma queda no

preço SPOT horário, que chegou a (-) € 50/MWh (negativo). No Domingo

anterior havia chegado a 95% da demanda pela primeira vez.

Suprimento de Energia por hora em 15/05/2016 na Alemanha:

ARTIGO 17: EIA - Junho/2016 (nossos comentários)

A EIA (Energy Information Administration) do Departamento de Energia dos

EUA, divulgou estudo onde avalia os impactos da ampliação do Canal do

Panamá, inaugurado no último dia 26/06/2016, sobre o mercado de GNL para

os EUA e, eventual redução de custos pela utilização de navios de maior porte

e pela redução substancial no tempo de viagem para os principais mercados

asiáticos. O canal que permitia a passagem de navios de 19.8 milhões de m³

de GNL (6% da frota mundial atual de navios GNL), agora poderá acomodar

navios de até 110 milhões de m³ de GNL (90% da frota mundial atual de navios

GNL). Este evento, poderá ocasionar mudanças anteriormente não previstas

sobre o mercado de geração térmica, e de usos industriais, em toda Ásia,

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notadamente no Japão, Coréia do Sul, Indonésia e China. Esta nova fronteira

comercial para o GNL produzido no Golfo do México, deverá aumentar o preço

do GNL para o Brasil.

ARTIGO 18: FORBES – Dezembro/2016 (nossos comentários)

Este artigo traz uma informação importante sobre a produção de baterias de

grande capacidade para integração às redes (no caso são baterias de

tecnologia diferente das utilizadas pelos japoneses da NGK que usam Sódio-

Enxofre). Estas baterias, denominadas de Fluxo de Vanádio, estão sendo

produzidas por um consórcio da empresa americana UET – UniEnergy

Technologies e a chinesa Rongke Power e, segundo o artigo, seu custo de

armazenagem seria atualmente o mais baixo do mundo (US$ 50/MWh), o que

significaria um custo de armazenagem de cerca de 45% daquele obtido hoje

pelos japoneses da NGK (US$ 110/MWh). O consórcio UET/Rongke está

fabricando um sistema para os chineses da China National Energy

Administration com 200 MW/800 MWh (serão 10 containers de 20 MW/80

MWh, cada) na península de Dalian, China. Se este custo de armazenagem se

confirmar, já conseguiram chegar hoje nos custos que estavam projetados para

2020 pela BNEF (Bloomberg New Energy Finance). Ou seja, já seria possível

agora gerar energia [intermitente –solar/eólica] despachável por menos de US$

100/MWh (R$ 330/MWh). À exemplo do que ocorreu com o preço da geração

solar FV que em 05 anos caiu 70% no Capex, parece que a corrida por

armazenagem de energia elétrica vai ser ainda mais feroz! Nos 09 primeiros

meses de 2016, a China anunciou 1GW de projetos de armazenagem de

energia, entre eles um que terá 400 MW/1.600 MWh de capacidade utilizando

tecnologia de supercapacitores (vide último artigo abaixo).

ARTIGO 19: Bloomberg – Dezembro/2016 (nossos comentários)

Energia de graça para os alemães durante o período de Natal. Os grandes

consumidores podem ser pagos para consumir energia. Temperaturas mais

amenas e fortes ventos durante este período são os responsáveis.

ARTIGO 20: The Wall Street Journal – Janeiro/2017 (nossos comentários)

A situação da geração nuclear não está fácil nos EUA. Continuam em

dificuldade, e muitas fechando, porque não conseguem competir com a

geração à gás natural, principalmente.

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ARTIGO 01: Bloomberg – Outubro/2012 - Germany's windmill

Windmills Overload East Europe’s Grid Risking Blackout:

Energy

By Ladka Bauerova and Tino Andresen - Oct 25, 2012 8:01 PM GMT-

0300

Germany is dumping electricity on its unwilling neighbors and by

wintertime the feud should come to a head.

Germany is dumping electricity on its unwilling neighbors and by wintertime the feud should come to a head.

Germany installed more than 8,885 megawatts of wind energy since 2007, mostly in the north. Photographer: Michele Tantussi/Bloomberg

Central and Eastern European countries are moving to disconnect

their power lines from Germany’s during the windiest days. That’s when they get flooded with energy, echoing struggles seen from

China to Texas over accommodating the world’s 200,000 windmills.

Renewable energy around the world is causing problems because

unlike oil it can’t be stored, so when generated it must be consumed or risk causing a grid collapse. At times, the glut can be so great that

utilities pay consumers to take the power and get rid of it.

“Germany is aware of the problem, but there is not enough political

will to solve the problem because it’s very costly,” Pavel Solc, Czech deputy minister of industry and trade, said in an interview. “So we’re

forced to make one-sided defensive steps to prevent accidents and destruction.”

The power grids in the former communist countries are “stretched to

their limits” and face potential blackouts when output surges from wind turbines in northern Germany or on the Baltic Sea, according to

Czech grid operator CEPS. The Czechs plan to install security switches near borders by year-end to disconnect from Europe’s biggest

economy to avoid critical overload.

Wind Farms

The bottleneck is one of many in the last eight years as $460 billion

of wind farms were built worldwide on plains, hills and at sea before networks were fully expanded to deliver the power to consumers.

Upgrading Germany’s system alone to address capacity and technical

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shortfalls will cost at least 32 billion euros ($42 billion), its four grid

operators said in May.

Germany installed more than 8,885 megawatts of wind energy since

2007, mostly in the north. Now it’s studying how to build the power backbone to connect to the industrialized south, home to hundreds of

factories such as those of chemicals manufacturer Wacker Chemie AG (WCH) and Siemens AG. (SIE) The electricity detours through the

Czech Republic and Poland when German cables can’t handle the load as the countries’ grids are interconnected.

The problem may intensify with the approaching winter. With an insufficient north-south connection, Germany’s power network came

close to a collapse last February when high winds in the Baltic sea flooded it with power and the Czech Republic and Poland threatened

to disconnect their grids. The coming winter can be critical, German Economy Minister Philipp Roesler said last week.

Aging Plants

Chancellor Angela Merkel’s decision to shut down aging atomic plants and exit nuclear power by 2022 following last year’s reactor

meltdowns in Fukushima, Japan, exacerbated the power imbalance. Germany more than ever will have to rely on power generated in the

more windy north.

“We do understand that the Czech and the Polish grid operators are concerned about market and system security,” Volker Kamm, a

spokesman for grid operator 50Hertz Transmission GmbH, said in a

phone interview from Berlin. “We are seeking a constructive solution.”

Lack of grid connections, such as in China, or oversupply as in Texas

have made wind energy’s global rollout a lumpy process. Wind farms in West Texas earlier this year were paying utilities to use their

electricity on particularly gusty days because they can still earn $22 a megawatt-hour in federal tax credits.

Excess Flows

Utilities like Prague-based CEZ AS (CEZ) and Warsaw-based PGE SA (PGE) are occasionally forced to disconnect some coal-fired plants in

the western parts of the Czech Republic and Poland because of excess power flowing from Germany. CEZ’s Prunerov plant is often a

casualty of the unplanned flows, CEPS said.

“Measures we’re using are costly and at times not sufficient,” said

Jerzy Dudzik, an executive from Poland’s grid operator PSE. PGE had

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to adjust generation schedules at its Dolna Odra and Turow plants, he

said.

Both Poland and the Czech Republic are planning to install so-called

phase-shifter transformers in the trans-border area with Germany to regulate power flows and protect their transmission networks. While

the Czechs are still negotiating with Germany on other short-term solutions and pushing for a creation of smaller power-trading areas

with realistic capacity allocation, they’re already counting on installing four transformers by 2017, CEPS said.

‘Free Lunch’

“The Germans are using our infrastructure in an excessive manner,” CEPS board member Zbynek Boldis said in an interview in Prague. “At

this point they’re getting a free lunch.”

Germany’s eastern neighbors have also said that the common

German-Austrian power market puts them at a disadvantage since they must reduce cross-border transmission capacity because of

trades between the two nations and have to take costly measures to protect their grids.

Southern Germany imports power from Austria’s pumped- storage

hydroelectric power stations in the Alps during peak periods, again using the Czech grid while excluding the Czechs from the benefits of

trading within a single-border area.

“Traders within the Austrian-German common zone don’t need to bid

for capacity in auctions even though they’re using up the capacity of its neighbors, who do have to pay,” CEPS’s Boldis said. “That’s

discrimination.”

The German-Austrian common market’s physical transmission capacity doesn’t correspond with the volume of transactions between

the two countries, so they end up using the Czech, Polish, Slovak and

Hungarian grids, Boldis said. The four countries want Germany and Austria to redraw the power-trading map, creating smaller areas that

would better reflect electricity flows.

“Electricity follows a path of least resistance in the grid, according to the laws of physics,” Boldis said. “The result is that our transmission

system is overloaded, we have security threats.”

To contact the reporters on this story: Ladka Bauerova in Prague at

[email protected]; Tino Andresen in Dusseldorf at [email protected]

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ARTIGO 02: The Financial Times - Novembro/2012

Utilities warned of risk from renewablesBy Pilita Clark, Environment

CorrespondentWind and solar plants are having a “profound negative impact”

on Europe’s gas and coal generators, the rating agency Moody’s has warned, in

a fresh sign of how quickly the growth of green power is transforming energy

markets.

“What were once considered stable companies have seen their business

models severely disrupted,” Moody’s said in a report. published on Tuesday.

“Given that further increases in renewables are expected, these negative

pressures will continue to erode the credit quality of thermal-based utilities in

the near to medium term.”

The report follows a similar warning in July from UBS analysts, who said

European utilities risked having as much as half their power generation profits

wiped out by 2020 as renewables reshaped the energy landscape. UBS

downgraded utilities, including Germany’s RWE and EDF of France, as a result.

Nearly 100 gigawatts of renewable generation have been installed in western

European countries since 2006, notably in Germany, Spain and Italy.This

means green power now accounts for more than a third of Europe’s total

installed capacity base, Moody’s said, a proportion set to rise to 50 per cent by

2020 when a further 150GW of renewables are expected to be added to

electricity networks.

Because wind and solar plants have very low marginal costs, they can displace

traditional gas and coal generators, and push down wholesale power prices.

That means the conventional plants face both lower market prices and fewer

running hours. This can make them less profitable even though it is critical for

them to stay online to make up for the intermittent nature of renewables.

As a result, several European countries, including Germany, the UK and

France, are looking at bringing in so-called capacity payments for conventional

generators to encourage them to stay online.

But as Moody’s points out, such payments could add as much as 3 per cent to a

typical household electricity bill in a country such as Germany, where the cost of

subsidising renewables is already politically sensitive.

The report’s conclusions about the risks renewable power sources pose to gas

and coal generators are well known in the industry, said a spokesman for Eon,

Germany’s largest utility by sales.

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“We and our competitors have already said we need to have a close look at the

profitability of our thermal generation assets, power plant by power plant, to ask

is it still earning enough money for us,” he said.

The impact of renewables also underlines the benefits of being an early investor

in clean energy, he added, pointing out that Eon had spent more €8bn on

renewable power worldwide in the past five years, mostly on wind farms,

boosting its renewable capacity tenfold to more than 4.3 gigawatts since 2007.

This had “massively contributed” to the companies’ earnings, he said, adding

“this is the other side of the story”.Copyright The Financial Times Limited 2012.

ARTIGO 03: Duke Energy – Janeiro/2013

Duke Energy Renewables completes Notrees Battery Storage Project in Texas; North America's largest battery storage project at a wind farm January 23, 2013

CHARLOTTE, N.C. -

Duke Energy Renewables, part of Duke Energy’s Commercial Businesses, announced today the completion of its 36-megawatt (MW) energy storage and power management system at its Notrees Windpower Project in west Texas. The system completed testing and became fully operational in December, 2012.

“Battery storage is an important innovation to address the variability of wind and solar energy generation,” said Duke Energy Renewables President Greg Wolf. “Developing an expertise in this advanced technology will enable us to expand the use of renewable energy, better integrate it into the power grid and become even more efficient at serving our customers.”

In late 2009, Duke Energy announced plans to match a $22 million grant from the U.S. Department of Energy (DOE) to install large-scale batteries capable of storing electricity produced by the company’s 153-MW Notrees wind farm, located in Ector and Winkler counties. The grant was made possible by the American Recovery and Reinvestment Act of 2009.

“Completion of this project represents a singular success for Duke Energy, for the DOE, and for the entire energy storage community in the U.S.” said Dr. Imre Gyuk, program manager for energy storage at the U.S. Department of Energy. “It will demonstrate the capability of energy storage to mitigate the variability of wind energy and to contribute to the stability of the grid”.

Austin-based Xtreme Power designed and installed the 36 MW-capacity Dynamic Power Resource™ at Notrees and will continue to operate the system. The battery storage project will help mitigate the variability of wind power, storing excess wind energy and discharging it whenever demand for electricity is highest.

In addition to increasing the supply of renewable energy during periods of peak demand, the system will help stabilize the frequency of electricity traveling throughout the power grid. Duke Energy is working closely with the Energy Reliability Council of Texas (ERCOT), which signals to the battery storage system to either dispatch stored energy to increase frequency or absorb energy to decrease frequency.

The Electric Power Research Institute (EPRI) will collect performance data from the battery storage system and help assess the potential for broader adoption of energy storage solutions throughout the industry. Technical and economic data will also be analyzed for DOE by Sandia National Laboratory. Results from the storage project at Notrees wind farm will be shared publically through the DOE’s Smart Grid Information Clearinghouse.

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About Duke Energy Renewables

Duke Energy Renewables, part of Duke Energy’s Commercial Businesses, is a leader in developing innovative wind and solar energy generation projects for customers throughout the United States. The company’s growing portfolio of commercial renewable assets includes 15 wind farms and 14 solar farms in operation in nine states, totaling more than 1,700 megawatts in electric-generating capacity. Learn more at www.duke-energy.com/renewables. Headquartered in Charlotte, N.C., Duke Energy is a Fortune 250 company traded on the New York Stock Exchange under the symbol DUK. More information about the company is available on the Internet at: www.duke-energy.com.

About DOE ARRA Storage Projects.

DOE’s Office of Electricity Distribution and Energy Reliability (OE) has the mission to lead national efforts to modernize the electric grid, enhance security and reliability of the infrastructure, and facilitate recovery from disruptions to energy supply. As part of this mission, OE has awarded 16 grants for energy storage projects under the American Recovery and Reinvestment Act of 2009 (ARRA) for a total of $185M. Each project is at least 50% cost shared. The projects cover diverse technologies such as compressed air energy storage, flywheels and advanced batteries. Applications include frequency regulation, smoothing of a photovoltaic installation, ramping for wind, and time shifting for a fossil fuel plant. ARRA projects are an integral part of OE’s Energy Storage Program. Project management is provided by the National Energy Technology Laboratory (NETL).

About Xtreme Power

Founded in November 2004, Xtreme Power designs, engineers, installs, and monitors integrated energy

storage and power management systems for Independent Power Producers, Transmission and

Distribution Utilities, and Commercial & Industrial End Users, among others. Xtreme Power’s technology

delivers on its promise to solve complex grid challenges and our customers rely upon our staff of over 100

power systems engineers and professionals to design and implement a solution specific to each

customer’s need.

Xtreme Power is a privately held company and has raised in excess of $90 million since its founding.

Current investors include SAIL Capital Partners, Bessemer Venture Partners, The Dow Chemical

Company, BP and Fluor, among others. These multimillion-dollar investments have yielded tremendous

growth and accolades, including the following: Bloomberg 2012 New Energy Pioneer Award, R&D 100

Award, one of 4,000 companies selected for the Global Cleantech 100 Award, and most recently honored

by Inc. Magazine as the 15th fastest growing company in the nation. For more information, please visit

http://www.xtremepower.com

ARTIGO 04: Bloomberg – Março/2013

Bulgaria to Suspend Up to 40% of Wind, Solar Power Capacity

By Ladka Bauerova - Mar 27, 2013 8:05 AM GMT-0300

Bulgaria may suspend as much as 40 percent of wind and solar power capacity as part of its effort to stem oversupply and stabilize electricity generation

About 40 percent of wind and solar power producers aren’t providing real-time information to the country’s central electricity dispatcher, jeopardizing the safety of Bulgaria’s transmission network, Energy Minister Asen Vasilev said in a document posted on the ministry’s website. They will be temporarily disconnected, he said.

Bulgaria’s grid is suffering from power overloads caused by a rapid increase in wind and solar capacity coupled with decreasing domestic consumption in the face of a weak economy. The government wants

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to relax the restrictions on electricity trading with neighboring Turkey, according to the document.

Protests against high electricity bills and poverty toppled the government of Boyko Borissov on Feb. 20. President Rosen Plevneliev appointed an interim government led by Prime Minister Marin Raikov on March 12 to organize and hold early elections on May 12.

To contact the reporter on this story: Ladka Bauerova in Prague at [email protected]

ARTIGO 05: Revista Opiniões – Março/2013

A importância da diversificação

Hermes Chipp

Diretor-geral do ONS

035-02

Em dezembro de 2012, a participação das usinas hidroelétricas na matriz de energia elétrica brasileira era

de aproximadamente 78%; as usinas térmicas (carvão, gás natural, óleo, nuclear e biomassa) respondiam

por cerca de 20%, e as eólicas, apenas 2%.

A matriz de energia elétrica é expandida, na sua maior parcela, por meio dos leilões públicos de energia

nova para o Ambiente de Contratação Regulada - ACR, reaIizados pelo Ministério de Minas e Energia -

MME, a ser contratada ao menor preço por todas as distribuidoras que declaram os montantes necessários

de nova oferta para o atendimento do consumo de seus clientes cativos.

O governo também pode fazer leilões de energia de reserva, ou seja, independentemente das

necessidades declaradas pelas empresas distribuidoras. Os leilões de energia de reserva estão baseados,

em geral, na geração eólica e na biomassa de bagaço de cana-de-açúcar.

No contexto desse processo, nos próximos cinco anos, até 2017, a participação da geração térmica deverá

evoluir para algo em torno de 31.000 MW, o que representará 22% da nossa capacidade instalada, já

contratada na forma de leilões de energia nova. A realização, nos próximos anos, de outros leilões de

energia nova (chamados de leilões A-3, realizados com três anos de antecedência em relação à entrada

em operação) ainda poderá aumentar essa participação até 2017.

No horizonte 2013/2017, o destaque é o crescimento da participação das usinas eólicas, que atingirão o

montante de cerca de 8.300 MW, o que representará um aumento de aproximadamente 325%,

representando 5,7% da nossa matriz de energia elétrica.

Historicamente, nossa matriz sempre teve predominância da hidroeletricidade e, em razão do regime

altamente sazonal dos nossos rios, com abundância de água em cada estação chuvosa (entre novembro e

abril) e recessão em cada estação seca (entre maio e outubro), foram construídos importantes

reservatórios de acumulação plurianual de água, justamente para compensar essa diferença de períodos

das chuvas. Assim, a água guardada no período chuvoso vira energia na estação seca, podendo, inclusive,

ser utilizada nos anos seguintes.

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Merece destaque também a complementaridade hidrológica entre as regiões do País, razão pela qual as

extensas linhas de transmissão – hoje em torno de 100.000 km em tensão igual ou superior a 230 kV,

conhecida como Rede Básica do Sistema Interligado Nacional (SIN) – cumprem importante função de

firmar energia no sistema, como se fossem usinas virtuais.

Essa característica peculiar do SIN permite, inclusive, a postergação de investimentos em nova geração de

energia, o que não seria possível sem um sistema de transmissão que interconectasse todo o território

nacional e sem a atuação de uma organização como o Operador Nacional do Sistema Elétrico (ONS), que

coordenasse o despacho hidrotérmico buscando o atendimento à demanda ao menor custo com

confiabilidade.

Já nas últimas décadas, as exigências ambientais para a construção de novos reservatórios de acumulação

tornaram praticamente inviável a construção de usinas hidrelétricas de regularização. Com isso, a maioria

das novas usinas passou a ser o que se conhece por usina "a fio d'água", ou seja, só geram energia

elétrica com a água que chega, não podendo estocar os excedentes na estação chuvosa, gerando menos

na estação seca.

Esse novo paradigma da matriz brasileira exigiu (e exigirá) a construção das chamadas fontes

complementares, ou seja, aquelas que compensam a baixa geração hidrelétrica nas estações secas, tais

como as usinas a biomassa, que geram na safra da cana-de-açúcar, entre maio e outubro, as usinas

eólicas, que apresentam maior disponibilidade de ventos na estação seca, e as usinas térmicas

convencionais (gás natural, nuclear, carvão e óleo), que, em princípio, mantidas as condições de logística

de entrega e disponibilidade do combustível, apresentam uma boa previsibilidade de operação e,

dependendo do montante instalado, representam um "seguro" importante para o SIN em condições de

secas mais severas.

Esse é o grande trade-off que a sociedade brasileira terá de enfrentar: ou se decide pela construção de

reservatórios de acumulação de água, mesmo com menor capacidade de acumulação do que aqueles

construídos em décadas passadas, para se precaver de secas severas, ou serão necessariamente

construídas novas usinas térmicas, para não ficarmos tão dependente das estações chuvosas e, com isso,

reenchermos nossos reservatórios de acumulação, para que possamos garantir o atendimento à demanda,

mesmo nas condições hidrológicas não favoráveis em períodos úmidos.

Com o objetivo de viabilizar a agregação de fontes térmicas convencionais, torna-se necessário, em

função da localidade e da disponibilidade dos recursos naturais, promover leilões regionais por fontes.

Dessa forma, seria equacionada a questão de diferentes riscos hidrológicos regionais, como é o caso da

região Sul, e reduzida a extensão da rede de transmissão.

Logicamente, as usinas eólicas e, futuramente, as solares são alternativas bastante interessantes para

diversificar nossa matriz de produção, mas são fontes intermitentes, ou seja, em algum momento, deixa

de ventar ou o sol não é suficiente para manter a geração instalada.

Nesses momentos, outros recursos têm de estar prontamente disponíveis para que os consumidores de

energia sejam plenamente atendidos, o que conduz à implantação de usinas termelétricas convencionais.

Hoje, esse é um dos maiores desafios do setor elétrico brasileiro. Como conviver com as fontes

intermitentes quando elas atingirem participação significativa na nossa matriz de produção?

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Vemos duas alternativas: ou instalamos usinas térmicas a óleo para imediatamente serem acionadas

(usinas de backup), e, assim mesmo, alguma parcela já deveria ficar ligada como reserva girante, que é

uma geração que pode ser instantaneamente utilizada, ou deixamos essa reserva por conta de usinas

hidráulicas, bem mais rápidas para o aumento instantâneo de sua geração, desde que tenhamos água

suficiente para que essa oferta maior seja atingida, ou seja, é fundamental que as novas hidrelétricas

tenham reservatórios de acumulação.

Para energias renováveis não convencionais, entendemos por pertinente a busca da expansão que leve

em conta o mínimo custo global, observando conjuntamente as opções de geração e os investimentos

associados em transmissão.

Esse aspecto da transmissão seria identificado com antecedência, alocando-se preferencialmente a

geração nas localidades em que menos se necessitaria da expansão das redes de transmissão e

distribuição.

Diversificar a matriz é muito importante para o País.

É uma diretriz que irá permitir preparar a indústria de energia elétrica para o dia em que nosso potencial

hidrelétrico esteja todo aproveitado (só exploramos, até hoje, cerca de 30% do economicamente

aproveitável).

Portanto todas as fontes de energia serão sempre bem-vindas, mas a equação de responsabilidade

ambiental tem um custo para a sociedade, e, em última instância, caberá a ela eleger a solução que irá

pautar o desenvolvimento econômico do País de forma sustentável, contribuindo para a modicidade

tarifária e reduzindo as desigualdades sociais.

ARTIGO 06: GE – Maio/2013

GE Wins Order for Three Wind Turbines With Storage Technology

By Christopher Martin - May 1, 2013 10:21 AM GMT-0300

General Electric Co. (GE), the biggest U.S. supplier of wind turbines, will supply three systems that include battery storage to Invenergy LLC for a Texas wind farm.

The agreement is part of an 86-turbine order that Chicago-based Invenergy plans to install at its Goldthwaite Wind Energy facility in Mills County, Texas, GE said today in a statement.

It’s the first order for the 2.5-120 Brilliant turbine that Fairfield, Connecticut-based GE announced in January, incorporating short-term power-storage capabilities. The system uses software to analyze wind speeds and retains excess power during gusty periods that’s fed to the grid when breezes wane.

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Renewable-energy developers are showing increasing interest in storage technology to offset the intermittent availability of wind and sunshine, Keith Longtin, GE’s general manager for wind products, said in the statement.

Integrating batteries in turbines will let wind-farm operators boost “efficiency and short-term predictability,”Longtin said

ARTIGO 07: Bloomberg – Agosto/2013

Japanese Battery Trial Seeks to Transform How Grids Work: Energy

By Chisaki Watanabe - Aug 7, 2013 11:17 AM GMT-0300

On a windy island 500 miles north of Tokyo, Japan is about to experiment with a battery designed to transform the way electricity is supplied and at the same time boost Prime Minister Shinzo Abe’s economic rescue plan.

The Ministry of Economy, Trade and Industry is investing 20 billion yen ($203 million) on a Sumitomo Electric Industries Ltd. (5802)device to be used by Hokkaido island’s utility to store excess solar and wind power, stabilizing flows to consumers.

A member of the media walks past a redox flow battery at Sumitomo Electric Industries Ltd.'s

plant in Yokohama, Japan. The Hokkaido project gives Japan and Sumitomo a chance to

showcase the vanadium redox flow technology to utilities around the globe that need to integrate

renewables into the grid. Photographer: Tomohiro Ohsumi/Bloomberg

July 25 (Bloomberg) -- Areva SA Chief Financial Officer Pierre Aubouin talks about the outlook for

nuclear energy and the company's acquisition plans. He speaks from Paris with Francine Lacqua

on Bloomberg Television's "On the Move." (Source: Bloomberg)

Since the earthquake in 2011, Japan has redoubled work to upgrade power systems and spur exports that can revitalize the economy. The Sumitomo device is meant to give Japan the kind of market leadership it had in the 1970s with cheap calculators made by Casio Computer Co. (6952) and this century with Toyota Motor Corp. (7203)’s fuel-saving hybrid cars.

“It’s great timing to make inroads into Europe and the U.S. and to supply the system in Hokkaido toward commercialization,”said Keisuke Murakami, a trade ministry official in charge of the project.

The battery, which uses the metal vanadium to store electrical energy in electrolyte tanks, has been researched from Australia to China and promises to handle the sort of large power surpluses that can develop on a transmission grid.

Hokkaido island was picked because it’s isolated from the mainland’s electricity network and has open land ideal for arrays of solar panels and wind turbines. Success would benefitSharp Corp. (6753)

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and SoftBank Corp. (9984), which are among the investors that have sought to build solar projects with four times the capacity Hokkaido’s grid can handle. Installation is set for completion by March 2015.

Abe’s Program

Energy storage is one of the technologies Abe and Japan’s previous government have been working on to modernize the grid, whose structure has been fixed since World War II.

Utilities in Japan such as Tokyo Electric Power Co. (9501) andKansai Electric Power Co. (9503)

have experimented with energy storage. In the U.S., Electric Transmission Texas and PG&E Corp. (PCG) are among the companies that have experience with the technology.

Aside from cost, one of the biggest obstacles is the potential for battery systems to overheat and cause fires. Last August, a 15-megawatt lead-acid battery backup system for a wind farm in Hawaii caught fire and destroyed its warehouse, forcing a temporary closure of First Wind Holdings Inc.’s 30-megawatt wind farm.

Problems associated with more prolific lithium-ion batteries have grounded Boeing Co. (BA)’s Dreamliner jets and led to the bankruptcy of U.S. government-backed A123 Systems Inc. (AONEQ)

Battery Fires

In September 2011, a fire started at a 2-megawatt storage system developed by NGK Insulators Ltd. (5333) Production of sodium-sulfur batteries was suspended. In May, NGK announced it signed an agreement to supply a battery system with the capacity of as much as 490 megawatt-hours to Terna SpA (TRN) of Italy.

Trials on Hokkaido are aimed at answering how to integrate bursts of power on sunny, windy days into a grid designed to handle constant output from generators driven mainly by nuclear reactors and fossil fuels typically run day and night.

“The project will enable gathering data and integrating more clean energy onto the grid,” said Takahiko Date, a senior researcher at the ICT innovation department of the Mitsui Global Strategic Studies Institute in Tokyo. “Once batteries’performance is proven, it becomes easier to deploy them abroad.”

Grid Bottlenecks

Not everyone is convinced the battery project will fix the grid. “This may be a good pilot project to improve the technology, but it won’t solve the problems Hokkaido is facing,” said Ali Izadi-Najafabadi, an analyst for Bloomberg New Energy Finance. “It doesn’t help much with the issue of Hokkaido’s overall electricity demand being low,” where renewable generation is increasing and there’s not enough capacity to transfer electricity to the mainland, he said.

Alternatives to batteries have been working for years for utility-scale power storage. Pumped hydroelectric power is the most common, with more than 127 gigawatts of capacity worldwide,

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according to the U.S. Electric Power Research Institute. Those pump water into a reservoir where it can be released later to drive hydroelectric turbines.

The Hokkaido project gives Japan and Sumitomo a chance to showcase the vanadium redox flow technology to utilities around the globe that need to integrate renewables into the grid. It relies on almost three decades of research by Sumitomo on rechargeable batteries.

Research History

The U.S. National Aeronautics and Space Administration was developing the vanadium redox flow technology in the 1970s. Sumitomo started research in 1985 and suspended work because the batteries kept charge more briefly than expected.

It resumed in 2008 and this year set up a division to promote the technology, said Mitsuyo Tsuruta, a Sumitomo spokeswoman. It has been conducting pilot projects and wants to commercialize the battery as early as next year.

With a capacity of 60 megawatt-hours, the battery will be installed at Hokkaido Electric (9509)’s Minami Hayakita substation in the town of Abira, according to a joint statement from Sumitomo and the utility. One megawatt is enough to power about 333 homes in Japan.

The trade ministry said there is an increasing need for storage in Europe for wind power, and the system on trial in Hokkaido shows promise.

Murakami, the trade ministry official, said, “that is why Sumitomo is betting on a technology it once gave up.”

To contact the reporter on this story: Chisaki Watanabe in Tokyo at [email protected]

To contact the editor responsible for this story: Reed Landberg at [email protected]

ARTIGO 08: The Financial Times - Fevereiro/2014

RWE expected to declare €3bn net loss

By Jeevan Vasagar in Berlin

Cooling towers operate at the RWE AG coal-fueled power plant in Weisweiler, Germany

RWE, Germany’s second biggest utility, is expected to declare a net loss of about €3bn for 2013, in the latest sign of the crisis gripping European power producers.

The company will reveal the figure, the first time it has reported a full-year net loss, next Tuesday. An RWE spokeswoman would not comment.

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The net loss, first reported in the newspaper Handelsblatt, is attributable to writedowns for the year of €4.8bn, most of which is due to declining earnings from conventional power generation.

Profits of these power generators have been battered by the boom in subsidised renewable energy in Germany, where clean energy has favourable access to the grid. Utilities are also suffering from low wholesale power prices and weak demand because of the eurozone crisis.

RWE’s net income for 2012 was €1.3bn. Its dividend payments will be based on a ratio of its recurrent net income, which was €2.5bn in 2012.

ARTIGO 09: The Financial Times - Março/2014

Germany’s energy policy is expensive, harmful and short-sighted

March 16, 2014 5:08 pm

By Bjorn Lomborg

Berlin is failing the poor while protecting neither security nor the

climate, writes Bjorn Lomborg

The Ukrainian crisis has again put German energy policy in the spotlight. As long as Europe’s green energy is expensive and unreliable, it favours Russian gas and leaves the continent’s energy policy unsustainable.

Germany’s energiewende, the country’s move away from nuclear and fossil fuels towards renewable energies has been regarded by some commentators as an example for the rest of the world. But now Germany shows the globe how not to make green policy. It is failing the poor, while protecting neither energy security nor the climate.

Last month, the government said that 6.9m households live in energy poverty, defined as spending more than 10 per cent of their income on energy. This is largely a result of the surcharge for renewable energy. Between 2000 and 2013, electricity prices for households have increased 80 per cent in real terms, according to data from the OECD and the International Energy Agency.

This means more and more money is going from the poor to the rich. Low-income tenants in the Ruhr area or Berlin are paying high energy prices to subsidise wealthy homeowners in Bavaria who put solar panels on their roofs.

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Some have argued that Germany’s energy policy could be seen as a huge bet on developing the energy of the future – and if it works, it would secure Germany’s engineering future.

However, most of Germany’s money was spent, not on research into future technology, but on buying existing inefficient green technology. Three weeks ago, in a report to the German parliament, a group of energy experts delivered a damning indictment of the current subsidies. They said that the policy has had a “very low technology-specific innovation impact in Germany”. Essentially, it is much safer for companies to keep selling more of the old technologies of wind, solar and biomass because these are already getting huge subsidies instead of trying to develop new and better technologies that have similar pay-offs but much higher risk.

The legislation does not offer more protection for the climate. Instead, it makes such protection much more expensive. ”There is no justification for a continuation of the Renewable Energies Act”, the report concludes.

German energy policy is an expensive way to achieve almost nothing. For solar alone, Germany has committed to pay subsidies of more than €100bn over the next 20 years, even though it contributes only 0.7 per cent of primary energy consumption. These solar panels’ net effect for the climate will be to delay global warming by a mere 37 hours by the end of the century, according to a report cited in Der Spiegel.

A McKinsey study published earlier this year found that Germany energy prices for households are now 48 per cent above the European average. At the same time, European power prices have risen almost 40 per cent since 2005, while US electricity prices have declined.

Despite exemptions from renewable obligations for energy-intensive companies, German industrial power costs are 19 per cent higher than the EU average. German industrial costs have risen 60 per cent since 2007, compared to increases of about 10 per cent in the US and China. This makes Germany an ever less attractive place for industry. German chemical giant BASF has already said it will make most if its future investments outside of Europe.

Green energy cannot meet Germany’s need for reliable electricity. That is why Germany still needs copious amounts of fossil fuels; German CO2-emissions have risen since the nuclear power phase-out of 2011, despite the incredible subsidies for renewables.

Germany is an example of how not to do green energy. Instead the solution is to research and develop better green energy technology. A study by some of the world’s top climate economists including three Nobel Laureates for the Copenhagen Consensus Center shows that subsidising existing renewables does so little good that for every euro spent, 97 cents are wasted. However, every euro spent on green innovation could avoid €11 in long-term damages from global warming.

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If we can reduce the price of future green technology below the cost of fossil fuels, everyone will switch. And such cheap green energy will not leave us at the mercy of Russia, it will actually fix global warming – and it will help rather than hurt the poor.

The writer is director of the Copenhagen Consensus Center

ARTIGO 10: Bloomberg - Julho/2014

German Utilities Bail Out Electric Grid at Wind’s Mercy

By Julia Mengewein Jul 25, 2014 8:13 AM GMT-0300

Photographer: Krisztian Bocsi/Bloomberg

Wind turbines operate beyond a field of rapeseed in Altentreptow, Germany. Germany's... Read More

Germany’s push toward renewable energy is causing so many drops and

surges from wind and solar power that the government is paying more

utilities than ever to help stabilize the country’s electricity grid.

Twenty power companies including Germany’s biggest utilities, EON SE and

RWE AG, now get fees for pledging to add or cut electricity within seconds to

keep the power system stable, double the number in September, according to

data from the nation’s four grid operators. Utilities that sign up to the 800

million-euro ($1.1 billion) balancing market can be paid as much as 400 times

wholesale electricity prices, the data show.

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Germany’s drive to almost double power output from renewables by 2035

has seen one operator reporting five times as many potential disruptions

as four years ago, raising the risk of blackouts in Europe’s biggest

electricity market while pushing wholesale prices to a nine-year low. More

utilities are joining the balancing market as weak prices have cut

operating margins to 5 percent on average from 15 percent in 2004, with

RWE reporting its first annual loss since 1949.

“At the beginning, this market counted for only a small portion of our earnings,”

said Hartmuth Fenn, the head of intraday, market access and dispatch at

Vattenfall AB, Sweden’s biggest utility. “Today, we earn 10 percent of our plant

profits in the balancing market” in Germany, he said by phone from Hamburg

July 22.

Price Plunge

In Germany’s daily and weekly balancing market auctions, winning bidders

have been paid as much as 13,922 euros to set aside one megawatt

depending on the time of day, grid data show. Participants stand ready to

provide power or cut output in notice periods of 15 minutes, 5 minutes or

30 seconds, earning fees whether their services are needed or not.

German wholesale next-year electricity prices have plunged 60 percent since

2008 as green power, which has priority access to the grid, cut into the running

hours of gas, coal and nuclear plants. The year-ahead contract traded at 35.69

euros a megawatt-hour as of 1:12 p.m. on the European Energy Exchange AG

in Leipzig, Germany.

Lawmakers last month backed a revision of a the country’s clean-energy law to

curb green subsidies and slow gains in consumer power prices that are the

second-costliest in the European Union. Chancellor Angela Merkel’s energy

switch from nuclear power aims to boost the share of renewables to at least 80

percent by 2050 from about 29 percent now.

Power Premium

Jochen Schwill and Hendrik Saemisch, both 33, set up Next Kraftwerke

GmbH in 2009 to sell power from emergency generators in hospitals to

the power grid. Today, the former University of Cologne researchers employ

about 80 people and have 1,000 megawatts from biomass plants to gas units at

their disposal, or the equivalent capacity of a German nuclear plant.

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“That was really the core of our founding idea,” Schwill said by phone from

Cologne July 21. “That the boost in renewable energy will make supply

more intermittent and balancing power more lucrative in the long run.”

Thomas Pilgram, who has sold balancing power since 2012 as chief executive

officer of Clean Energy Sourcing in Leipzig, Germany, expects the wave of

new entrants to push down balancing market payments.

“New participants are flooding into the market now, which means that prices are

coming under pressure,” Pilgram said. “Whoever comes first, gets a slice of the

cake, the others don’t because prices have slumped.”

Increased Competition

German grid regulator Bundesnetzagentur welcomes the increase in balancing

market participants.

“That’s in our interest as we want to encourage competition in this market,”

Armasari Soetarto, a spokeswoman for the Bonn-based authority, said by

phone July 18. “More supply means lower prices and that means lower costs for

German end users.”

The average price for capacity available within five minutes has dropped

to 1,109 euros a megawatt in the week starting July 14, from 1,690 euros

in the second week of January, Next Kraftwerke data show. Payments for

cutting output within 15 minutes dropped to 361 euros from 1,615 euros in

January.

The number of participants has increased as the country’s four grid operators

refined how capacity is allocated. In 2007, the grids started one common

auction and shortened the bidding periods. Since 2011, power plant operators

commit their 5-minute capacity on a weekly basis instead of a month before.

Balance Payments

Balancing-market payments to utilities totaled 800 million euros last year,

similar to the amount in 2012, grid data show. Utilities were asked to

reserve 3,898 megawatts this week, which compares with Germany’s total

installed power generation capacity of 183,649 megawatts as of July 16.

One megawatt is enough to power 2,000 European homes.

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Tennet TSO GmbH, Germany’s second-biggest grid operator, told power

plant operators to adjust output 1,009 times to keep the grid stable last

year, compared with 209 times in 2010. The interventions, used alongside the

balancing market, are expected to be as frequent this year as in 2013, Ulrike

Hoerchens, a spokeswoman for the Bayreuth, Germany-based company, said

by phone on July 23.

To adapt to volatile supply and demand, RWE invested as much as 700

million euros on technology for its lignite plants that allow the units to

change output by 30 megawatts within a minute. The coal-fired generators

were originally built to run 24 hours a day.

RWE’s lignite generators, which have a total capacity of 10,291

megawatts, are flexible enough to cut or increase output by 5,000

megawatts on a sunny day, when power from solar panels floods the grid

or supply vanishes as skies turn cloudy, according to Ulrich Hartmann, an

executive board member at RWE’s generation unit.

“Back in the days, our lignite plants were inflexible, produced power around the

clock and were always earning money,” Hartmann in Bergheim, Germany, said

in a July 9 interview. “Now they are as flexible as gas plants.”

To contact the reporter on this story: Julia Mengewein in Frankfurt

[email protected]

To contact the editors responsible for this story: Lars Paulsson

at [email protected]; Dan Stets at [email protected] Rob

Verdonck

ARTIGO 11: WSJ - Agosto/2014

Germany's Expensive Gamble on Renewable

Energy

Companies Worry Cost of Plan to Trim Nuclear, Fossil Fuels Will

Undermine Competitiveness

By

MATTHEW KARNITSCHNIG

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Aug. 26, 2014 10:30 p.m. ET

Germany's biggest North Sea wind farm, Bard 1, has 80 turbines and is expected

to produce enough energy to power a city the size of Munich. Agence France-

Presse/Getty Images

WILSTER, Germany—In a sandy marsh on the outskirts of this medieval hamlet,

Germany's next autobahn will soon take shape.

The Stromautobahn, as locals call it, won't carry Audis and BMW's BMW.XE -1.24% ,

but high-voltage electricity over hundreds of miles of aluminum and steel cables

stretching from the North Sea to Germany's industrial corridor in the south.

The project is the linchpin of Germany's Energiewende, or energy revolution, a

mammoth, trillion-euro plan to wean the country off nuclear and fossil fuels by

midcentury and the top domestic priority of Chancellor Angela Merkel.

But many companies, economists and even Germany's neighbors worry that the

enormous cost to replace a currently working system will undermine the country's

industrial base and weigh on the entire European economy. Germany's second-

quarter GDP decline of 0.6%, reported earlier this month, put a damper on overall

euro-zone growth, leaving it flat for the quarter.

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Average electricity prices for companies have jumped 60% over the past five years

because of costs passed along as part of government subsidies of renewable energy

producers. Prices are now more than double those in the U.S.

"German industry is going to gradually lose its competitiveness if this course isn't

reversed soon," said Kurt Bock, chief executive of BASF SE, BAS.XE -0.65% the

world's largest chemical maker.

The European Union has set a series of binding renewable energy targets for all of

its members. The goals, in which about 35% of Europe's electricity is projected to

come from renewable sources by 2020, are considered ambitious by international

standards. But Germany's "lonely revolution," as some call it, goes much further.

By 2025, Germany aims to produce 40%-45% of its electricity from renewable

sources, rising to at least 80% by 2050. Most countries in the EU are holding to the

lower target for now and are continuing to use nuclear energy.

Ms. Merkel, who ordered Germany's accelerated exit from nuclear power after the

Fukushima disaster in 2011, has declared the Energiewende both a major contribution in

the battle against global warming and a historic step toward ending the world's reliance

on nuclear power.

"No country of Germany's scale has pursued such a radical shift in its energy supply,"

Ms. Merkel said in a speech earlier this year. "I'm convinced that if any country can

successfully implement the Energiewende, it's Germany."

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One government estimate projects the Energiewende by 2040 to cost up to €1

trillion, or about $1.4 trillion, or almost half Germany's GDP and nearly as much

as the country spent on the reunification of East and West Germany.

Despite the weak second quarter, Germany's economy—Europe's largest—is still

benefiting from strong demand for German machinery and autos in China and

elsewhere, which helped Germany weather the Continent's debt crisis with little

damage. This year, the economy is expected to expand by about 1.5%, solid growth by

European standards.

Yet nearly 75% of Germany's small- and medium-size industrial businesses say

rising energy costs are a major risk, according to a recent survey by

PricewaterhouseCoopers and the Federation of German Industry.

A similar percentage of the U.S. companies

operating in Germany said the Energiewende had

made the country a less attractive place for business,

according to a separate poll by the U.S. Chamber of

Commerce. And for the first time since 2008,

German companies cited rising overall costs at home

as a motivation to invest abroad in a recent survey by

the German Chambers of Commerce and Industry.

"Germany's current path of increasingly high-cost

energy will make the country less competitive in the

world economy, penalize Germany in terms of jobs

and industrial investment, and impose a significant

cost on the overall economy and household income,"

warned Daniel Yergin, vice chairman of research

firm IHS. IHS -0.31%

The German government says it is committed to limiting the negative impact on the

broader economy. Once Germany's renewable infrastructure is complete, electricity

prices should fall, the government has said.

The government also argues that by establishing German industry as the leader in green

technology, the Energiewende will give German business another lucrative export. Ms.

Merkel has pointed to eventual technological advances in solar and wind power

generation, grid management systems and power storage technologies.

BASF, which consumes as much electricity every year at its main German plant as

the entire country of Denmark, said in May it would substantially reduce its

investments in Germany as a result of the country's energy policy. It said its plan

for the next five years is to cut investment in Germany to one-fourth the €20 billion

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global total investment, from one-third currently, and that it would invest in Asia

and the U.S. instead. BASF has more than 50,000 employees in Germany, about

half the company's total workforce.

SGL Carbon, SGL.XE +0.28% a maker of carbon-based products, in May decided to

invest an additional $200 million to its plant in Washington state on top of $100 million

previously invested instead of investing in its home base of Germany. The company,

which makes carbon fibers used to lighten the body of BMW's new electric car at the

Washington facility, said electricity at the site costs less than one-third German rates.

Basi Schöberl GmbH, an industrial gases company based in southwestern Germany,

shelved plans this year to expand production at home. Instead, it will invest more than

€10 million to build out its French base near Strasbourg. An investment in Germany

was too risky due to uncertainty over government policy and the effect the

Energiewende will have on energy prices, said Chief Executive Ingo Nawrath. "We're

standing with our backs up against the wall," he said.

So far, the main beneficiaries of the Energiewende are investors in wind and solar

installations. Private individuals and local community groups control about half of

Germany's onshore wind and solar energy markets. Institutional investors, including

many insurance companies, own roughly half of the country's solar energy and 40% of

its onshore wind power generation. Germany has few hydropower resources.

Rewiring the world's fourth-largest economy hasn't been easy. The undertaking, the

biggest infrastructure project in Germany since World War II, has been plagued by cost

overruns, regulatory disputes and questions of conservation. One issue: how to keep

bats and endangered birds from flying into the rotors of thousands of wind turbines

going up across the country.

A more immediate concern is the soaring cost of energy.

A worker constructs an

electrical transmission

tower near Lüssow,

Germany, that will

transmit power

generated by offshore

wind farms. Getty Images

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To encourage the expansion of green power production, the government guaranteed

prices for electricity fed into the grid from renewable sources, such as wind turbines or

solar panels. The price guarantees, which vary depending on when the system was

installed and its generating capacity, are binding for 20 years.

The government passes the subsidy cost on to consumers in a surcharge. While the

flood of new energy sources has lowered market prices for electricity, consumer

prices have actually increased as the surcharge has risen to make up the difference

between the market and government-guaranteed prices. On the spot market, a

kilowatt-hour of electricity costs 3.2 cents, half what it did in 2011. The average

guaranteed price under the government's price fixing regime is 17 cents. The

renewable energy surcharge levied on German households and businesses has

nearly tripled since 2010 and now accounts for about 18% of a German

household's electric bill. All told, the subsidies amount to about €24 billion a year,

according to Germany's economics ministry.

Alarmed by the rising costs, Ms. Merkel's government revised the law authorizing the

green energy subsidies in June. With a combination of caps on the number of new

solar and wind installations eligible for the subsidy and other measures, it hopes to

forestall further surcharge increases.

About 2,000 of Germany's heavy industrial users—including BASF and SGL—are

largely exempt from paying the surcharge until at least 2017, when the EU wants to

scrutinize whether the exemption is an unfair trade support, among other issues.

Berlin has vowed to fight any attempt by the EU to fundamentally change the subsidy

program.

The companies, which save about €5 billion annually because of the surcharge

exemption, say the questions surrounding the program make it impossible to plan and

say the higher energy costs are passed on to them from smaller suppliers and contractors

who aren't exempted.

Nonexempt companies also complain of the disparity. "Whereas some sectors are

exempt from the renewable-energy surcharge, high-tech companies have to bear an

additional burden," Infineon Technologies AG IFX.XE +0.73% Chief Executive

Reinhard Ploss complained to investors earlier this year. Mr. Ploss said his company,

Germany's largest chip maker, would pay €25 million less in Austria for the power it

uses in Germany this year.

The incentives, introduced in 2000, have worked to increase renewable-energy

production. Wind turbines now dot the horizon in almost every corner of the country.

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Farmers and suburbanites from Bavaria to Berlin have installed solar panels on their

barns and homes to earn extra money from the government subsidy.

But not all rollouts have been smooth. In the north, to protect Germany's shoreline

ecosystems and ocean views, the government ordered wind parks be built as far as 60

miles off the coast. Rough conditions in the North Sea, coupled with depths of more

than 150 feet have hampered the projects and sent costs soaring.

Last August, Germany's biggest North Sea wind park went into operation, three years

over schedule and with a price tag of about €3 billion, nearly double the projected cost.

Called Bard 1, the farm's 80 turbines can produce enough electricity to power Munich.

But a fire in a transmission station in March and other problems forced it to shut down.

Bard's management says that it hopes to get the wind park up and running by September

and that it has put together a task force to determine the cause of the technical problems.

Overall, distributing the power has proved more complicated than producing it.

Electricity generated from wind in Germany's gusty northern reaches must be moved to

the country's energy hungry industry in the south.

Germany doesn't have a single north-south power transmission corridor. The country's

grid evolved over decades around local power plants that served their communities so

there was no need to send power across long distances.

The government wants to build and modernize more than 4,000 miles of high-voltage

power lines, both offshore and through densely populated areas. So far, amid delays and

indecision, only 220 miles of the expansion have been completed, meaning power can't

get to users.

Günther Oettinger, Europe's top energy official, compares Germany's strategy to

building a train station before the tracks have been laid. Germany has built "wind park

after wind park after wind park" instead of focusing on how it will transmit the

electricity to where it is needed, he said.

Winning over local communities along the main grid corridors is the biggest hurdle

toward construction.

The Wilster Marsh is the on-ramp for the Stromautobahn, which translates as

"electricity highway," and would be a 500-mile-long north-south corridor. The region, a

windswept landscape of dairy farms about 45 miles north of Hamburg on the Elbe

River, is where the power from more than 1,000 off- and onshore wind farms will flow

through a converter station and be shipped south.

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Though most locals here support the Energiewende, few want to see 230-foot

transmission towers in their neighborhood.

"Some people who were for this are now on their back foot saying, 'but not in my

backyard,' " said Matthias Block, the chief of Wilster's department of building.

At a recent meeting in Bad Brückenau, a resort town in northern Bavaria, officials of

TenneT, the state-owned Dutch company building the transmission corridor, were

greeted by hundreds of protesters carrying noisemakers and homemade signs saying

"Stop the power-line madness" and other slogans. A score of similar citizen groups have

sprouted along the Stromautobahn route.

"The corridor they're planning would destroy everything we've done to improve the

environment in this region," said Ingo Queck, a local organizer of a citizen action

committee that wants to prevent construction of the line.

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Mr. Queck and the other groups worry power lines will destroy the landscape and make

the region unattractive for tourism, and say radiation from the high-voltage lines could

damage health. TenneT says the electromagnetic radiation from the lines would be well

within accepted limits and say it has taken pains to ensure as little impact as possible to

the environment by proposing a corridor along existing infrastructure, such as

highways.

Polls show strong support in Germany for the Energiewende. Germans' embrace of

renewable energy is rooted in their visceral opposition to nuclear power. The movement

has been gathering strength since the 1960s, and popular and political opposition was

intensified after a violent confrontation between police and 100,000 demonstrators

against a new nuclear power plant in 1981 in the Wilster Marsh.

With Germany's nine remaining nuclear power plants set to be closed by 2022, a

substantial delay in building the transmission corridor could force the country to revert

to conventional energy sources.

The nuclear exit has already triggered an increase in Germany's greenhouse gas

emissions over the past two years, because utilities have turned to cheap coal to replace

the power capacity lost from the eight nuclear plants that have already been switched

off.

The government says the trend is temporary and that emissions will drop once more

wind and solar farms go into operation.

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But critics say "grid instability," or the unpredictable nature of renewable power,

could force the continued use of coal plants.

Because the technology is so new and no one has ever built a renewable-based

infrastructure on this scale before, there is concern among industry about the

reliability of the electricity supply—in precision manufacturing, a power loss for

even a millisecond can throw a production line out of kilter. That presents a

particular risk for companies such as Infineon and other tech hardware

companies.

Skeptics, meanwhile, say the program's overall environmental impact will be

limited if other big countries don't follow suit. Germany accounts for just over 2%

of global greenhouse gas emissions.

In June the EU admonished Berlin to "keep the overall costs of transforming the energy

system to a minimum" and said Germany needed to do more to coordinate its energy

policy with neighboring countries, which worry about the stability of their own

infrastructure.

"Initially, there was this enthusiasm that Germany would be at the head of the

parade," said IHS's Mr. Yergin, who has chronicled the global energy sector for

decades. "But now the Germans look back and see there aren't that many people

behind them."

Write to Matthew Karnitschnig at [email protected]

ARTIGO 12: Bloomberg - Julho/2015

France Passes New Energy Law Quadruples Carbon

Price

by Tara Patel

July 23, 2015 — 8:25 AM BRT

French lawmakers adopted a long-delayed energy law that will

reduce the country’s reliance on nuclear reactors and raise carbon

prices almost fourfold.

Lawmakers late Wednesday passed legislation that included a last-

minute amendment initially rejected by the government to increase

the target price of carbon to 56 euros ($61.48) a ton in 2020 and 100

euros a ton in 2030, according to the National Assemblywebsite. The

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rate, now 14.50 euros a ton, climbs to 22 euros a ton in 2016 and is

integrated in a levy on fossil fuels.

The rise provides “visibility” to the business community on how carbon prices

will evolve, Environment Minister Segolene Royal said. Higher taxes on fossil

fuels will be offset by lower levies on other products, she also said.

The new energy transition law, passed by a show of hands with no count to be

published, reflects a campaign pledge three years ago by President Francois

Hollande to cut France’s nuclear-energy reliance in favor of renewables.

The law stipulates that nuclear reactors should provide half of all power output

“by around” 2025. Electricite de France SA’s 58 reactors currently provide about

three-quarters of French electricity production.

Engie Chief Executive Officer Gerard Mestrallet said Thursday on France Inter

radio that he favors a carbon price. Business leaders including six European oil

majors had come out in recent months for a carbon-pricing mechanism as an

incentive to move to cleaner energies and cut climate-changing emissions.

The law, which also caps nuclear capacity at today’s 63.2 gigawatts,

had been delayed by industry resistance and ministerial changes. The

opposition-led Senate watered down nuclear provisions and backed the higher

carbon price.

UN Summit

France, host of a United Nations climate summit at the end of the

year, will have to raise the proportion of renewable energy to 23

percent of total consumption by 2020 and 32 percent by 2030 when

renewables have to make up 40 percent of power output, according

to the new law.

France will also have to lower carbon emissions by 40 percent by 2030

compared with 1990. The law stipulates lowering energy consumption by a fifth

by 2030 and by half by 2050 as well as reducing “primary” fossil-fuel

consumption by 30 percent in 2030 compared with 2012.

An increase in the carbon price in 2016 will raise the price of diesel by 2 cents a

liter and 1.7 cents a liter for gasoline, according to calculations by the French oil

lobby Union Francaise des Industries Petrolieres. A boost to 56 euros a ton in

2020 will add 9 cents a liter to the price of diesel and 7 cents a liter to gasoline

compared with 2016 prices.

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ARTIGO 13: Bloomberg - Agosto/2015

German Power Slumps Below 30 Euros as EON, RWE

Fall to Records

Rachel MorisonTino Andresen Weixin Zha

August 24, 2015 — 6:55 AM BRTUpdated on August 24, 2015 — 1:29 PM BRT

Germany's Operational Nuclear Power Plants Ahead Of 2022 National Shut Down

Krisztian Bocsi/Bloomberg

German power prices sank below 30 euros ($34) a megawatt-hour for the

first time in more than a decade, signaling more pain for utilities from EON

SE to RWE AG, already trading at record lows.

Electricity for year-ahead delivery, a benchmark European contract, fell 2.1

percent to its lowest level since October 2003. EON, Germany’s biggest utility,

declined 8.6 percent, the most since November 2012, while RWE dropped 9.1

percent, the biggest slump since August 2011.

Next-year power in Europe’s biggest market is headed for a fifth annual

drop as Chancellor Angela Merkel’s unprecedented shift toward an

economy based on renewable energy boosts output of solar and wind

electricity to record and squeezes generation from traditional coal and

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gas plants. Until now, the 30-euro level was a psychological barrier for the

year-ahead price, according to Bruno Brunetti, senior director of electricity, at

Pira Energy Group in New York.

“We are approaching an unhealthy level,” Omar Ramdani, head of analysis at

RheinEnergie Trading GmbH in Cologne, said Monday by phone. “It wouldn’t

surprise me if we would trade below in the short term, but we should actually

hold the 30,” which is near the floor price, he said.

The contract exceeded 90 euros in July 2008, just before the financial crisis

took hold of the markets. It dropped as low as 29.73 euros a megawatt-hour

on Monday on the European Energy Exchange.

25 Euros

“Who says there is an end at 30 euros?” Ricardo Klimaschka, a trader at

Energieunion GmbH, said by phone Monday. “Renewable generation will rise

in Germany and modern hard coal plants can produce already at 25 euros.

These round figures are purely psychological.”

RWE and EON are the worst performers this year on Germany’s DAX Index of

leading shares. EON on Monday fell below 10 euros for the first time since it

was formed 15 years ago and closed at 9.57 euros in Frankfurt, while RWE

closed at 13.22 euros. EON dropped 33 percent this year and RWE sank 48

percent. RWE spokeswoman Vera Buecker, analysts and fund managers

from Union Investment to Independent Research have attributed the

decline to sliding wholesale power prices.

Georg Oppermann, an EON spokesman, pointed to the falling stock market and

commodities environment, without being more specific, when commenting on

the slump in shares.

“Major German power generators have already hedged large amounts of power

forward, so I think the pain will be felt in the longer term,” rather than

immediately, Brunetti said.

Rising Renewables

Renewable energy’s share of gross German power consumption increased by

2.4 percentage points last year to 27.8 percent, according to the Economy and

Energy Ministry. Coal, lignite and nuclear accounted for 59 percent of German

generation in 2014, according to AG Energiebilanzen e.V., an association of

energy lobbies and economic-research institutes.

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Some coal and nuclear plants will struggle to cover their fixed costs with power

prices below 30 euros, Brunetti said.

Coal for next-year delivery fell to its lowest level since at least 2007, according

to broker data compiled by Bloomberg. The fuel accounts for about 18 percent

of Germany’s electricity and price swings impact power prices. Brent crude

plunged 57 percent in the past year in London trading.

Germany is scheduled to shut its eight remaining nuclear reactors by 2022.

EON’sGrafenrheinfeld plant closed on June 27, before its operating license

expired, because of waning profitability amid the increase in renewable

generation and a tax on nuclear fuel.

Power prices below 30 euros in Germany in the long term “would create

more incentive for remaining nuclear to retire earlier than the set dates,”

Brunetti said.

ARTIGO 14: Financial Times - Abril/2016

German utilities told to pay €23bn to nuclear clean-up

Power groups reject idea but shares rally in relief at solution

RWE's nuclear power plant at Emsland in Germany © Bloomberg

by: Guy Chazan in Berlin

Shares in Germany's big utility companies surged on Wednesday after a

government commission said they should pay €23.3bn towards the cost of

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storing nuclear waste — removing an uncertainty that has weighed on the

groups for months.

But despite the market’s positive reaction, RWE and Eon — the country’s two

biggest utilities — immediately rejected the proposal, saying it “placed too much

of a strain … on their economic capacity”.

They said that in dismissing the deal they were acting “out of a sense of

responsibility to their employees, customers and investors”.

For the past six months, a 19-strong commission of experts has been trying to

work out how to divide the costs of Germany's multibillion-euro nuclear clean-

up between the utility companies and the state.

Its aim was to find a compromise that did not impose too heavy a financial

burden on Germany’s utilities — which are already suffering the effects of low

electricity prices and a boom in wind and solar power — while achieving a fair

deal for German taxpayers.

Shares in Eon and RWE, Germany's two biggest utilities, have slid sharply in

recent months, in part due to the uncertainty over the nuclear costs. After

Wednesday’s announcement, however, they rose: Eon’s shares 3.95 per cent

to €9.44 and RWE’s 7.5 per cent to €13.40.

“It’s a relief rally, in response to the partial lifting of the nuclear overhang,”

said Deepa Venkateswaran, a utilities analyst at Bernstein Research. She said

the €23.3bn figure was a "worst case scenario" which the power companies

would probably not end up paying in full.

Germany decided to close its nuclear power stations after the 2011 Fukushima

disaster in Japan. Initially, the plants’ operators were made liable for all clean-

up costs and so far they have put aside about €38bn.

But the government has been eager to move those funds from the companies’

balance sheets, concerned that taxpayers could end up footing the bill if the

utilities were to run into financial difficulties.

Under the proposals unveiled on Wednesday, the utilities’ nuclear provisions

will be split. They would keep about €20bn to cover the cost of

decommissioning their reactors and transfer sums earmarked for nuclear waste

storage — about €17bn of the €38bn — into a state-controlled fund.

In addition, the commission proposed that the companies pay a “risk premium”

of 35 per cent to cover any gap between their provisions and the actual costs of

intermediate and final storage. That took the total amount to be transferred into

the fund to €23.3bn. In exchange, the companies would no longer be liable for

any future costs.

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Some members of the commission had sought a risk premium of 100 per cent,

while the companies themselves balked at paying such a premium at all.

Matthias Platzeck, one of the three heads of the commission, said it had to deal

with a basic question: “Is it better and safer for the future to leave everything as

it is now, that is, let the companies retain these provisions in the hope they will

still be there in 50 years, or to secure them for the future?” He added that the

commission was “firmly convinced” that the solution it had come up with would

be “safer for the taxpayer”.

Its proposals will now be sent to the German government and are likely to

become law by early next year.

ARTIGO 15: Financial Times - Maio/2016

Low European power prices here to stay, says utility CEO

Wholesale electricity prices have no reason to rise, says

incoming head of Engie

Isabelle Kocher says the price of electricity has no reason to rise © FT

by: Michael Stothard in Paris

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Low European electricity prices are here to stay, according to the

new chief executive of Engie, the world’s largest non state-owned

producer of electricity.

“I do not think that this is cyclical. I think that the price of electricity

has no reason to rise. It will never be like it was before,” Isabelle

Kocher told the Financial Times.

The bleak outlook from Ms Kocher, who was last week formally appointed at

Engie’s annual general meeting, goes against predictions by some companies

that a painful five-year trend of falling prices will soon reverse.

Jean Bernard Levy, chief executive of French utility EDF, last week said: “We

are faced with a historical, record low in wholesale electricity prices … The price

of a megawatt hour in western Europe has virtually divided by two.”

In Germany it has fallen from €60 per megawatt-hour in 2011 to

around €25 this year. The French price has moved from around €56

per MWh to around €30. Some companies, including EDF, have

predicted electricity prices in Europe will start to go up again after

two or three years.

Ms Kocher told the FT that while fluctuations are possible, sluggish economic

growth and the energy transition in Europe and around the world, which is

putting a much greater focus on subsidised renewable energy, is set to keep

prices “structurally” low for the foreseeable future.

The drop has had a deep effect on power providers. Paris-based Engie has

written off nearly €24bn worth of assets over the past two years, as many of its

gas power plants become uneconomical.

German operators of conventional power plants such as E.ON and RWE have

faced an existential threat, with problems compounded by the government

decision to close all nuclear power stations.

Last week RWE said its operating result for its conventional power generation

dropped 20 per cent in the first quarter to €354m, mainly due to lower

wholesale electricity prices.

Share prices have also collapsed: for EDF a fall of 63 per cent since the start of

2011, while the RWE share price has fallen 75 per cent and Engie 50 per cent

over the same period.

Engie is making a push to reshape its business model, selling over

the next three years €15bn worth of non-renewable energy

assets, mostly in exploration and production, coal-fired

power plants and US gas plants.

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It will then invest €22bn in renewable energy, energy services such

as heating and cooling networks, and decentralised energy

technology, Ms Kocher said. It will also try to find regulated, not

market based, energy contracts to protect itself from further price

declines.

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Isabelle Kocher, Engie — a new kind of power

The head of the French utility company on dealing with climate change

and crisis

by: Michael Stothard in Paris

When she took the helm of Engie, the world’s biggest non state-owned

electricity company this month, Isabelle Kocher became the first Frenchwoman

in the chief executive role at a company in Paris’s CAC 40 stock market index.

The company, which changed its name from GDF Suez last year, sells

electricity and natural gas to millions of homes around the world,

employing 155,000 people in 70 countries. The appointment makes

Ms Kocher one of the most powerful people in the European energy

sector.

But asking Ms Kocher what her appointment means for gender equality in

France’s male dominated business world yields a muted response. “I understand

that my nomination represents something, but to be honest I was never very

feminist and I never suffered from being a woman in my career. Really, it was

never much of an issue for me.”

She is much more interested in talking about the crisis affecting Engie,

which reported a net loss of €4.6bn last year, and the profound

changes taking place in the European energy markets.

It quickly becomes clear that Ms Kocher has a no-nonsense, engineer’s mind:

above her desk on the 35th floor of Engie’s headquarters on the outskirts of

Paris is a framed poster of gas pipes from the group’s GRTgaz subsidiary,

instead of a work of art.

The world of energy is going through a “structural shift”, she says

over coffee and croissants, with demand for big, traditional

hydrocarbon power plants falling sharply. At the same time, demand

for more decentralised renewable energy is soaring. This is an

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significant challenge for Engie because most of its power is produced

from natural gas and, to a lesser extent, coal. Renewable energy

counted for only 17 per cent of its output, according to 2014 figures.

The long-term shift towards renewables is being driven by growing awareness of

climate change, she says. “People have woken up to the fact that we need to

completely reassess our economy to avoid climate disaster,” she says, adding

that a turning point was the Paris Climate Accord struck last November to agree

to limit emissions.

“People [today] understand that we need more wind, solar and hydro. We need

to replace coal with gas. We need to leave oil in the ground. This is

fundamentally challenging the model of all the energy companies.”

France warns on ‘colossal’ cost of building Hinkley Point plant

Energy minister says EDF was ‘carried away’ and fears £18bn nuclear plant will

damage utility

She says this is having an immediate effect on the group. This is in part because

the introduction in Europe of renewable energy subsidies, along with the more

recent fall in oil prices, has helped sharply reduce the cost of electricity, making

many gas and coal plants uneconomic. Engie has written down billions of euros

of assets, and it is not alone. The European utility sector overall has been forced

to close or mothball more than 50,000MW worth of gas-fired capacity in

Europe — equivalent to 50 nuclear plants — over the past seven years.

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Rival European utilities such as RWE and Eon have in many

respects suffered much worse than Engie, their problems compounded by the

decision in Germany to close their nuclear power plants.

Engie, says Ms Kocher, “simply has to adapt to the new world order”.

That is why her first announcement as head of Engie was that the group would

over the next three years sell €15bn worth of assets, mostly in exploration and

production, coal-fired power plants and US gas plants. It will then invest €22bn

in renewable energy, energy services such as heating and cooling networks, and

decentralised energy technology. It will also try to find regulated, not market

based, energy contracts to protect itself from price fluctuations. “This is the way

to create shareholder value at Engie … The question today is less about how we

expand the group internationally, but how we move away from a model which

no longer works,” she says.

To stamp her authority, Ms Kocher has undertaken an overhaul of management,

reorganising the team globally into 24 business units, with the majority taking

charge of a single region in a bid to get closer to clients. Friends and colleagues

of Ms Kocher say her management style is direct, that she makes rapid decisions

and likes meetings to be as short as possible.

In her youth, she did not waste much time either. Ms Kocher had a privileged

upbringing in the Paris suburbs but worked hard and followed a classic path to

becoming a chief executive, going to the top schools, working for the state and

joining one of the largest companies. Her father was a senior manager at French

telecoms group Alcatel and her mother a biblical scholar, so she grew up around

God and business.

CV

Isabelle Kocher

Born

December 1966, Neuilly-sur-Seine

Education

Ecole Normale Supérieure, Corps des Mines Engineering School

Career

1992-97: Project manager at Société Européenne de Propulsion

1997-99: French economy ministry

1999-2002: Industrial affairs adviser to prime minister Lionel Jospin

2002-07: Joins strategic and development department of Suez (part of what is

now Engie)

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2005-07: Senior vice-president at Suez

2007-11: Chief operating officer of Lyonnaise des Eaux

2011-15 Executive vice-president and CFO, GDF Suez (now Engie)

2016: Becomes Engie chief executive

Interests

Piano, sculpting, fencing and swimming

Ms Kocher attended the prestigious École Normale Supérieure, where she was a

researcher into theoretical physics, initially working on artificial intelligence. It

taught her, she says, “that there are always people much smarter out there than

you”. She also studied at the engineering school Ecole des Mines at the same

time as Patrick Pouyanné, CEO of oil group Total, and Jean-Laurent Bonnafé,

CEO of BNP Paribas.

She spent time in government working on industrial issues for then prime

minister Lionel Jospin, before joining French utility Suez in 2002. By 2008,

Suez had merged with French group Gaz de France, becoming GDF Suez.

Ms Kocher became chief financial officer in 2011, and the protégé of Gérard

Mestrallet, who ran the group after its creation in 2008, pursuing a strategy of

internationalising the group away from stagnant European markets.

Mr Mestrallet had planned to leave once Ms Kocher took over, but by February

he had a change of heart and was named chairman of the board. This caused

rumours of tensions.

Ms Kocher says: “I asked him to stay on. Normally people at the top want

everything [in terms of power], but I asked him to stay. There is a massive

revolution in the world of energy and his presence on the board is important.”

Although she is the first Frenchwoman to run a CAC 40 company, the accolade

of first woman overall went to Pat Russo, the American CEO of Alcatel-Lucent,

in 2006.

Engie was not the first CEO job offered to Ms Kocher, she says. In 2011 she

turned down the role at the nuclear group Areva. This turned out to be a good

move, as four years later Areva was forced into a state bailout. “I was happy at

Engie, first of all,” she says of her decision. “But also, much as I believe in keep-

ing our existing nuclear fleet, I think there is less and less space for new nuclear

today. This was already my feeling at the time, and it is much more so today.”

As for dealing with the upheaval ahead and the effect on her working life, she

points out that she has risen before 5am for years and sleeps little. She always

travelled a lot, especially in her role as CFO. “I will still take my holiday. I will

still take weekends when I can,” she says. Ms Kocher, one of a handful of French

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chief executives who are practising Roman Catholics, says spirituality is

important to her, particularly in what she says is her mission to make Engie a

driver of the global energy transition.

“Whatever religion or wisdom, spirituality and values are important to me and

to the business,” she says. “We have the way to help people get out of poverty, to

contribute the emergence of a different way of living that is more respectful [of

the planet].” It is not only a sense of social responsibility though. “We need to

create shareholder value. That is why I am here, that is what I need to do.”

Second opinion: the adviser

Benoit d’Angelin, co-founder of advisory boutique Ondra Partners, who has

known Isabelle Kocher since she became chief financial officer of Engie and has

worked with her closely, says she is an “excellent listener”, “very focused”,

“decisive” and has a “strategic vision” for the group.

As CFO she took time to listen to shareholder views and so “understands

extremely well the balance required between growth, investment and the need

for healthy returns [at Engie]”.

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using our article tools. Please don't cut articles from FT.com and redistribute by

email or post to the web.

ARTIGO 16: Bloomberg - Maio/2016

Germany Just Got Almost All of Its Power From

Renewable Energy

Jessica Shankleman Jess_Shankleman

May 16, 2016 — 8:37 AM BRT

Wind, solar, biomass and hydro met demand on Sunday afternoon

Angela Merkel’s Energiewende is squeezing coal and gas margins

Clean power supplied almost all of Germany’s power demand for the first time

on Sunday, marking a milestone for Chancellor Angela Merkel’s

“Energiewende” policy to boost renewables while phasing out nuclear and fossil

fuels.

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Solar and wind power peaked at 2 p.m. local time on Sunday, allowing

renewables to supply 45.5 gigawatts as demand was 45.8 gigawatts,

according to provisional data by Agora Energiewende, a research institute

in Berlin. Power prices turned negative during several 15-minute periods

yesterday, dropping as low as minus 50 euros ($57) a megawatt-hour,

according to data from Epex Spot.

Germany’s power supply by hour

Source: Agora Energiewende

Countries around Europe are building increasing amounts of renewable

capacity in order to reduce their carbon emissions and boost supply security.

Last year Denmark’s wind farms supplied 140 percent of demand, while the

U.K. had no coal-fired power stations meeting electricity demand for about four

hours on May 10 as a result of plant breakdowns.

“Events like this highlight that eventually we may need to start curtailing

because of market-wide oversupply,” said Monne Depraetere, an analyst for

Bloomberg New Energy Finance. “In the long-run, that may provide a case to

build technologies that can manage this oversupply -- for example more

interconnectors or energy storage.”

Renewables were only able to meet demand because of Germany’s strong

export capability, the analyst said. Even when solar and wind peaked,

conventional power plants were still supplying 7.7 gigawatts.

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Merkel’s unprecedented shift to clean energy has squeezed margins at coal and

gas plants while driving up costs for consumers in Europe’s biggest power

market. The increased flows of clean energy have also put pressure on the grid

to the point that the country is considering excluding certain regions from future

onshore wind power auctions if local grids are already struggling to keep up with

large volumes of renewable energy supplies.

“If Germany was an island, with no export cables, this would be technically

impossible because you always need to have some thermal generation running

as a back up supply for when the wind or solar drops off,” Depraetere said.

“Germany consumed 100 percent renewable energy yesterday, but we’re

unlikely to see clean energy supply 100 percent of generation anytime soon,” he

said.

ARTIGO 17: EIA (Energy International Agency) - Junho/2016

Expanded Panama Canal reduces travel time for shipments of

U.S. LNG to Asian markets

Source: U.S. Energy Information

Administration calculations based on

IHS and other sources

Note: Calculations assume export

from the Sabine Pass liquefaction

terminal at an average LNG Carrier

speed of 19.5 knots and one-day

transit time through the Panama and

Suez Canals.

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The newly expanded Panama Canal will be able to accommodate 90% of the

world's current liquefied natural gas (LNG) tankers with LNG-carrying capacity

up to 3.9 billion cubic feet (Bcf), or 110 million m³. Prior to the expansion, only

30 of the smallest LNG tankers (6% of the current global fleet) with capacities

up to 0.7 Bcf, or 19.8 million m³, could transit the canal. The expansion has

significant implications for LNG trade, reducing travel time and transportation

costs for LNG shipments from the U.S. Gulf Coast to key markets in Asia and

providing additional access to previously regionalized LNG markets.

The new locks in the canal provide access to a wider lane for vessels and are

180 feet (55 m) across, compared with 109 feet (33 m) in the original locks.

Only the 45 largest LNG vessels, 4.5-Bcf (127 million m³) to 5.7-Bcf (161 million

m³) capacity Q-Flex and Q-Max tankers used for exports from Qatar, will not be

able to use the expanded canal.

Transit through the Panama Canal will considerably reduce voyage time for

LNG from the U.S Gulf Coast to markets in northern Asia. Four countries in

northern Asia—Japan, South Korea, China, and Taiwan—collectively account

for almost two-thirds of global LNG imports. A transit from the U.S. Gulf Coast

through the Panama Canal to Japan will reduce voyage time to 20 days,

compared to 34 days for voyages around the southern tip of Africa or 31 days if

transiting through the Suez Canal. Voyage time to South Korea, China, and

Taiwan will also be reduced by transiting through the Panama Canal.

The wider Panama Canal will also considerably reduce travel time from the U.S.

Gulf Coast to South America, declining from 20 days to 8-9 days to Chilean

regasification terminals, and from 25 days to 5 days to prospective terminals in

Colombia and Ecuador. For markets west of northern Asia, including India and

Pakistan, transiting the Panama Canal will take longer than either transiting the

Suez Canal or going around the southern tip of Africa.

In addition to shortening transit times, using the Panama Canal will also reduce

transportation costs. The Panama Canal Authority has introduced new toll

structures for LNG vessels designed to encourage additional LNG traffic

through the Canal, especially for round trips. Transit costs through the Panama

Canal for an average 3.5 Bcf LNG (99 million m³) carrier are estimated at $ 0.20

per million British thermal units (MMBtu) for a round-trip voyage, representing

about 9% to 12% of the round-trip voyage cost to countries in northern Asia.

Based on IHS data, the round trip voyage cost for ships traveling from the U.S.

Gulf Coast and transiting the Panama Canal to countries in northern Asia is

estimated to be $0.30/MMBtu to $0.80/MMBtu lower than transiting through the

Suez Canal and $0.20/MMBtu to $0.70/MMBtu lower than traveling around the

southern tip of Africa. Transiting the Panama Canal offers reduction in

transportation costs to northern Asian countries such as Japan, South Korea,

Taiwan, and China and may offer some minimal cost reductions to countries in

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southeast Asia (Malaysia, Thailand, Indonesia, and Singapore), depending on

transit time. U.S. LNG exports to India, Pakistan, and the Middle East are not

expected to flow through the Panama Canal because alternative routes, either

the Suez Canal or around the southern tip of Africa, have lower transportation

costs.

Currently, about 9.2 billion cubic feet per day (Bcf/d), or 260 million m³/day, of

U.S. natural gas liquefaction capacity is either in operation or under construction

in the United States. By 2020, the United States is set to become the world's

third-largest LNG producer, after Australia and Qatar. More than 4.0 Bcf/d (113

million m³/day) of U.S. liquefaction capacity has long-term (20 years) contracts

with markets in Asia, of which 3.2 Bcf/d (90 million m³/day) is contracted to

Japan, South Korea, and Indonesia.

Source: U.S. Energy Information Administration calculations based on IHS and trade

press

Note: Calculations of the number of vessels transiting Panama Canal assume the largest

LNG vessel size allowed to transit the expanded Canal (approximate LNG-carrying

capacity 3.9 Bcf).

An additional 2.9 Bcf/d (82 million m³/day) of U.S. liquefaction capacity currently

under construction has been contracted long-term to various countries.

Flexibility in destination clauses allows these contracted volumes to be taken to

any LNG market in the world. Assuming all contracted volumes transit the

Panama Canal, EIA estimates that LNG traffic through the Canal could reach

more than 550 vessels annually, or 1-2 vessels per day, by 2021.

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ARTIGO 18: FORBES - Dezembro/2016

Vanadium-Flow Batteries: The Energy Storage Breakthrough We've Needed

FORBES

DEC 13, 2016 @ 06:00 AM

James Conca ,

CONTRIBUTOR

The latest, greatest utility-scale battery storage technology to emerge

on the commercial market is the vanadium redox battery, also

known as the vanadium flow battery.

V-flow batteries are fully containerized, nonflammable, reusable

batteries, using 100% of the energy stored. Presently, the largest V-

flow battery in the U.S. is a 2MW/8MWh installed at the SnoPUD

Everett Substation in Washington State by UniEnergy Technologies

that is scheduled to come online in January 2017. Source: UET

V-flow batteries are fully containerized, nonflammable, compact,

reusable over semi-infinite cycles, discharge 100% of the stored

energy and do not degrade for more than 20 years.

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Most batteries use two chemicals that change valence (or charge or redox state)

in response to electron flow that convert chemical energy to electrical energy,

and vice versa. V-flow batteries use the multiple valence states of just vanadium to

store and release charges.

V can exist as several ions of different charges in solution, V(2+,3+,4+,5+), each

having different numbers of electrons around the nucleus. Fewer electrons gives

a higher positive charge. Energy is stored by providing electrons making

V(2+,3+), and energy is released by losing electrons to form V(4+,5+).

Vanadium flow batteries use the multiple valence states of

vanadium to store and release charges. Energy is stored by

providing electrons making V(2+,3+), and energy is released by

losing electrons to form V(4+,5+). Source: UET

Flow batteries consist of two tanks of liquid, which simply sit there until needed.

When pumped into a reactor, the two solutions flow adjacent to each other past

a membrane, and generate a charge by moving electrons back and forth during

charging and discharging.

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This type of battery can offer almost unlimited energy capacity simply by using

larger electrolyte storage tanks. It can be left completely discharged for long

periods with no ill effects, making maintenance simpler than other

batteries. Because of these unique properties, the new V-flow

batteries reduce the cost of storage to about 5¢/kWh.

These batteries are rather large and best suited to industrial and utility scale

applications. They could never fit in an electric car, so the Tesla battery is safe

for now. But the V-flow battery outcompetes Li-ion, and any other solid battery,

for utility-scale applications. They’re just safer, more scalable, longer-lasting

and cheaper - less than half the cost per kWh.

Unlike solid batteries, like lithium-ion or lead-acid, that begin

degrading after a couple of years, V-flow batteries are fully

reusable over semi-infinite cycles and do not degrade, giving them

a very, very long life. Source: UET

New battery technology is essential in our new energy future. According to the U.S.

Energy Storage Monitor, energy storage demand, especially at the business and utility

scales, will increase ten times in just the next five years, fueled in major part by

the extension of the federal Investment Tax Credit (ITC) for five more years. The

Energy Storage Association states that corporate investments in energy storage

reached $660 million in just the third quarter of 2016.

UniEnergy Technologies (UET) of Seattle produces the largest MW-scale

vanadium flow batteries yet, using a molecule developed at the Pacific Northwest

National Laboratory. PNNL’s breakthrough was to introduce hydrochloric acid into

the electrolyte solution, almost doubling the storage capacity and making the

system work over a far greater range of temperatures, from -40°C to 50°C (-

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40°F to 122°F), removing a large previous cost of maintaining temperature

control.

Presently, the largest installed V-flow battery in the U.S. is a UET 2MW/8MWh

(power/total dischargeable energy in a single full charge) system in Washington

State at the Snohomish County Public Utility District’s Everett Substation.

This vanadium battery can keep the lights on in 1,000 homes for eight hours.

A V-flow battery system planned for Dalian China by UET's sister

company Rongke will soon be the largest battery in the world at

200MW/800MWh.

“Cost-effective, reliable, and longer-lived energy storage is necessary to truly

modernize the grid,” said Dr. Imre Gyuk, energy storage program manager for

DOE’s Office of Electricity Delivery and Energy Reliability, of UET’s system. “As

third-generation vanadium flow batteries gain market share, it is essential to

increase our understanding of storage value and optimization to accelerate

adoption of integrated storage and renewable energy solutions among utilities.”

No matter how you cut it, energy storage has generally been very expensive. And

no matter how good ordinary batteries are, they cost about 30¢ to store 1 kWhr,

essentially tripling the cost of generating that energy.

Storage has primarily been done only when necessary for logistical reasons, like

storing solar power generated that day for use that night in a remote area. Or

when you want a flashlight to use without dragging a hundred-foot cord around.

No one thinks about the absurdly high cost of that electricity since it’s usually

such a small amount needed to power a flashlight or a remote appliance. Twenty

hours of continuous use, more or less, is what you’ll get from a common battery.

But storing energy for the future is becoming more important as power

generation evolves and we need to be more creative, and less costly, than we’ve

been so far. Hence, the importance of the V-flow batteries.

In addition to batteries, there are other technologies for storing intermittent

energy, such thermal energy storage. However, the most widely used storage

method is pumped hydro storage, which uses surplus electricity to pump water up

to a reservoir behind a dam. Later, when demand for energy is high, the stored

water is released through turbines in the dam to generate electricity. Pumped

hydro is used in 99 percent of grid storage today, but there are geologic and

environmental constraints on where pumped hydro can be deployed.

For now, V-flow batteries offer the best deployable large battery

storage technology developed thus far.

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http://www.uetechnologies.com/

UniEnergy Technologies Strategic Partner to Deliver World’s Largest Battery

MUKILTEO, WA — UniEnergy Technologies (UET)'s strategic partner and affiliate

Rongke Power will deploy the world's largest battery, rated at 800 Megawatt-hour

(MWh). UET and Rongke Power have worked closely together since 2012 to develop

large-scale Vanadium Flow Batteries (VFB's) to meet the challenges of grid

modernization, renewable penetration, and resiliency.

The VFB battery will provide peak-shaving and enhance grid stabilization on the Dalian

peninsula in northern China. Even more storage capacity is anticipated in the future to

facilitate additional intermittent renewable energy deployment in the region. The China

National Energy Administration approved the strategic application of Rongke's VFB

into the utility grid due to its competitive price and lack of emissions, as well as

demonstrated longevity, operational flexibility, and class-leading performance.

Flow batteries were originally invented by utilities in the United States to offer

Megawatt (MW)-scale buffer capacity. After decades of development and deployments,

only close collaboration between the US and China has yielded the scientific and

engineering breakthroughs needed to meet stringent requirements for utility

performance, reliability, and safety.

Collaboration between UET and Rongke Power will be memorialized in a US-China

EcoPartnership signing ceremony attended by U.S. Secretary of State John Kerry in

Beijing on June 7, 2016. UET will be represented by Rick Winter, UET's President and

Chief Operating Officer.

The battery arrays approved by the China National Energy Administration will be

made up of ten (10X) 20MW/80MWh VFB systems deployed on the Dalian

peninsula, which during extreme weather events has experienced stress on the

electricity grid. After full commissioning, the VFB battery will be able to peak-shave

approximately 8% of Dalian's expected load in 2020. In addition, the large-scale battery

will form an additional load center, which will enhance grid stabilization including

securing the power supply and providing black-start capabilities in the event of

emergency.

The VFB battery will be built at Rongke Power's new GigaFactory to be opened in the

fall of 2016, with a phase 1 capacity of 300MW of VFB electrode stacks, a phase 2

capacity of 1GW, and a phase 3 capacity of 3GW. Both Rongke Power and UET's

deployments of VFB systems will be supported by production from Rongke Power's

GigaFactory.

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UET President and COO Rick Winter stated: "This visionary project is a watershed

moment for the energy storage industry, vaulting China's electric grid into the 21st

century, supplying tremendous resilience and enabling seamless deep penetration of

renewables. The massive scale of the project was made possible by years of reliable

field performance of vanadium flow batteries, and allows us to rapidly optimize our

supply chain across our product lines."

About UET

UET manufactures its breakthrough MW-scale containerized advanced vanadium flow

battery products in a 60,000 square foot manufacturing facility near Seattle,

Washington. Prior to launching UET in 2012, its founders led the core technology

development at Pacific Northwest National Laboratory in Washington State for 5 years

with U.S. DOE Office of Electricity funding. The technology safely delivers the

smallest bulk energy footprint in the industry with unlimited cycle life over 20 years.

UET now has almost 20MW/80MWh of energy storage systems deployed, ordered, or

awarded. Reference customers include the utility, microgrid, and commercial &

industrial sectors. More information on UET is at www.uetechnologies.com.

About Rongke Power

Dalian Rongke Power Co., Ltd. is a vertically-integrated manufacturer of vanadium

flow batteries. Jointly founded by Dalian Bolong Holding Group and Dalian Institute of

Chemical Physics - Chinese Academy of Sciences in 2008, the company is located in

the Dalian High-Tech Zone in Dalian, China. Rongke Power leads the way in producing

key battery materials and providing turn-key energy storage solutions. With a strong

intellectual property portfolio, the company has deployed almost 30 energy storage

projects in market sectors such as renewable energy integration, microgrids, and

isolated power systems. More information on Rongke Power is at

www.rongkepower.com.

China announced nearly 600MW of energy storage in Q3 2016

By Andy Colthorpe

Dec 15, 2016 12:48 PM GMT

China’s deployment of energy storage looks set to continue an upward

trajectory, with almost 600MW in the pipeline as of the third quarter this year.

According to figures released by the China Energy Storage Alliance

(CNESA), 14 new projects were announced in Q3 2016 totalling 587MW.

This includes projects that are in planning stages, under construction and that

have gone online in the quarter. This appears to represent a significant boost to

the sector, and is a vast 586% increase on the same period of last year. Up until

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the beginning of the quarter, CNESA found, 170.6MW of energy storage was in

operation in the country.

The bulk of this large figure is contributed by a single project, a touted

400MW supercapacitor storage station with storage duration of four hours

in Guazhou County, in the northern Gansu province, a couple of hundred

kilometres south of the border with Mongolia. This project will be used to

demonstrate the use of storage in preventing wind power capacity

curtailment on a microgrid. The project, by Shidai Jiahua Co, requires

US$680 million in investment and has an expected payback time of 16 to

18 years.

There was also a 160MW local government project in Inner Mongolia, another

microgrid to be used for renewables integration. The local authority of Xilin Gol,

one of Inner Mongolia’s 12 sub-divided regions, is keen to trial retail sales of

electricity from independent suppliers and this project represents a major step

forward in this regard.

While these two huge projects are in northwestern regions of China, Jiangsu in

the east will get some significant new projects including a 1.5MW/12MWh

project from partners including battery maker Narada Power, inverter maker

Sungrow and project developer GCL Power, which is an arm of one of China’s

biggest PV groups, GCL Poly. Narada Power was also involved in a

15MW/120MWh project in Jiangsu’s Wuxi City Xingzhou Industrial Park.

Overall, renewables integration appears to be the biggest application driver for

energy storage in China, as seen in the diagram below. While big

announcements were plentiful, only 1.5MW of storage actually came online in

Q3, which was nonetheless a 50% increase on the same period of 2015.

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Image: CNESA.

Regional reforms, big factories and major investments

CNESA also reported that there have been several rounds of regional-level

reforms including the establishment of electricity trading centres, the approval of

various reform plans by the National Energy Administration and the start of

development of power trading markets in various regions.

There was also major news in terms of production centres for energy storage

technologies with Sungrow’s partnership with Samsung SDI expected to reach

100MWh production capacity this year and 500MWh next year. GCL Integrators

is also building a large facility, a 500MWh battery factory. GCL is investing

US$13 million in that plant.

In terms of significant investments in energy storage reported on by CNESA,

Shanghai Electric Power has committed to investing US$870 million in the next

three years on 100 to 200 energy storage projects in Wuxi, Jiangsu province.

The company will make an even bigger investment in Hubei province, central

China, putting in US$4.3 billion for more than 1,000 storage projects over the

next five years. Meanwhile lithium-ion battery maker Zhuhai Yinlong Co. was

purchased by appliances manufacturer Gree for US$1.8 billion.

ARTIGO 19: Bloomberg – Dezembro/2016

Germany Gets Free Power for Christmas as Wind Power Set

to Surge

By Rachel Morison

22 de dezembro de 2016 09:41 BRT

Electricity prices turn negative amid mild weather, low demand

Negative rates mean large consumers can be paid to use power

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Wind turbines operate in

Bedburg, Germany.

Photographer: Martin

Leissl/Bloomberg

The price of power for delivery on Christmas Day in Germany turned negative as a

surge in wind generation is forecast to boost supply.

Prices may be below zero for hours or even whole days during the holiday season as

German wind output is predicted to climb to near-record levels and temperatures are set

to increase more than 5 degrees Celsius (9 Fahrenheit) above normal.

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The negative prices are “driven by low power demand during the holiday season when

factories are shut, and people go on vacation or visit their families,” Elchin Mammadov,

an analyst at Bloomberg Intelligence said. “There are far fewer outages this year than

the same time last year and wind availability is expected to be high.”

Germany’s grid operators can struggle to keep the network balanced when there are

high amounts of wind generation that need to be moved from the north to demand

centers in the south. Negative prices mean that producers must either shut down power

stations to reduce supply or pay consumers to take the electricity off the grid.

Wind generation is forecast to peak at 31.3 gigawatts on Dec. 25 before rising to

33.7 gigawatts on Dec. 27, close to the record 33.8 gigawatts in February,

according to Bloomberg’s wind model and data from the European Energy

Exchange AG. One gigawatt is enough to power 2 million European homes.

Mild weather can reduce heating demand. High pressure is forecast to spread across

Europe during the next five days, bringing widespread above-normal temperatures,

according to MDA Information LLC. The warmest conditions are expected in Germany.

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Power for delivery on Dec. 25 dropped to minus 10.95 euros ($11.45) a megawatt-

hour, according to broker data compiled by Bloomberg. German power prices

have turned negative in previous holiday periods. The day-ahead price fell to

minus 56.87 euros a megawatt-hour on Dec. 24, 2012, and was also negative at

Christmas in 2013, according to Epex Spot SE in Paris.

Storm Barbara is expected to boost wind levels in the U.K. to record levels on Friday.

The Met Office has issued a weather warning as 90 mile-an-hour winds are forecast in

Scotland.

ARTIGO 20: The Wall Street Journal – Janeiro/2017

Nuclear Plants Fall Victim to Economic Pressures

New York’s Indian Point plant is expected to be latest casualty as political

opposition, fracking take a toll

New York’s Indian Point nuclear plant, shown in 2011. Many U.S. utilities are closing their

nuclear power facilities. PHOTO: DON EMMERT/AFP/GETTY IMAGES

By RUSSELL GOLD andMCASSANDRA SWEET

Jan. 9, 2017 5:30 a.m. ET

Utilities are closing U.S. nuclear-power plants at a rapid clip as they face

competition from cheaper sources of electricity and political pressure from critics. New York’s Indian Point plant about 35 miles north of Manhattan, a major source of

power for the city and its surrounding suburbs, looks to be the latest casualty.

Owner Entergy Corp. and New York Gov. Andrew Cuomo, who has long criticized the

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plant as a safety threat, are expected to announce a deal this week to close it, say people

familiar with the matter. Its closure would bring the tally of plants set to close by 2025 to four,

including PG&E Corp.’s Diablo Canyon plant in California and Entergy’s Palisades

unit in Michigan. Four others have already closed in the past four years,

including Dominion Resources Inc.’s Kewaunee plant in Wisconsin. The retirements are poised to leave 61 nuclear plants in the U.S. by the middle of the

next decade. That includes two facilities that are building new reactors. A small number

of nuclear plants have closed in the past due to safety or the need for expensive repairs.

What’s new is the number of plants closing that are licensed and operational, but no

longer profitable in competitive markets.

Nuclear plants everywhere are facing a powerful economic foe:

fracking. The extraction technique has unlocked vast amounts of natural gas,

making generating electricity from that fuel much less expensive and lowering

power prices across the country.

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Nuclear plants generated 20% of U.S. power in the past 12 months, following

natural gas at 35% and coal at 30%, according to federal energy data. The balance

was 7% hydro, 6% wind and 1% solar.

The increasingly poor economics of nuclear power have led nuclear plant operators in

New York, Illinois and elsewhere to seek new state subsidies to keep the plants

operating. The owners argue that they create high-paying jobs in rural areas, and are

critical tools to combat air pollution and climate change because they produce

emissions-free electricity.

Lawmakers in Connecticut, Ohio and Pennsylvania are expected to face tough choices

in the next couple of years: Approve rate increases or other changes to bolster the

finances of nuclear plants, or prepare for them to close. Exelon Corp., the nation’s largest nuclear-power plant operator, has succeeded in

persuading states to provide new financial incentives to keep its nuclear-power plants

open. Last month, Illinois lawmakers voted to allow Exelon to collect up to $235 million

annually from customers in exchange for keeping two nuclear-power plants open.

Earlier in 2016, the New York Public Service Commission agreed to pay as much

as $480 million annually to keep three upstate nuclear plants open. Exelon operates two

of the three, and has a deal to purchase the third from Entergy, pending federal

approval.

Joe Dominguez, Exelon’s executive vice president for public policy, said states were

paying for clean electricity, similar to how the federal government subsidizes wind and

solar energy. Nuclear power “is the cheapest and most reliable zero-carbon

resource,” he said. FirstEnergy Corp. said recently it could close three plants in Ohio and Pennsylvania if it

couldn’t arrange better compensation for the power they provide. A FirstEnergy

spokeswoman said the company had watched the Illinois legislation closely and hoped

to negotiate something similar. Kristine Hartman, who tracks energy laws for the National Conference of State

Legislatures, said she expects Arizona, New Jersey and New Mexico to consider

modifying laws that encourage wind and solar to include nuclear as a power source free

of greenhouse-gas emissions.

Without additional support, “you will continue to see plants that are challenged,”

said Maria G. Korsnick, the president and chief executive of the Nuclear Energy

Institute, an industry advocacy group. An analysis by the U.S. Energy Information Administration found that when

nuclear plants were closed, states increased their use of natural gas and coal to

generate power.

Jessica Lovering, director of the energy program at the Breakthrough Institute, an

environmental think tank, said a modern gas plant can have just a dozen employees,

while nuclear plants need upward of 1,000.

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But those large workforces are proving to be a political selling point as owners argue to

state legislators that nuclear-power plants have great economic importance in rural

areas. All five nuclear-power plants receiving new subsidies in Illinois and New York

are located in rural areas.

Still, the deals have been controversial. “I am pronuclear power, but I am not pro-

bailing nuclear out,” said Jeanne Ives, a Republican state representative from

Wheaton, Ill.

In New York, the deal brokered by Mr. Cuomo, a Democrat, to keep three upstate

nuclear-power plants alive has been met by protests against what activists claim is a

nuclear tax.

The new subsidies have also riled up independent power producers, which claim that

nuclear operators are being given an unfair advantage. Dynegy Inc. and NRG Energy Inc., which operate coal- and natural-gas-fired

power plants, are suing New York regulators to reverse their decision to

provide what they estimate could be more than $7 billion in subsidies to nuclear

plants. Bob Flexon, chief executive of Houston-based Dynegy, said he hopes the Trump

administration will set a national energy policy that allows for a level playing field. “Someone needs to let them know that you’re killing coal if you throw billion-dollar

subsidies to nuclear,” Mr. Flexon said. —Mike Vilensky contributed to this article. Write to Russell Gold at [email protected] and Cassandra Sweet

at [email protected]