Как выбрать гостиницу для кошек
14 декабря, 2021
Here is the firm’s assessment of the U.K.
Clearing the EC Hurdle
The U.K.’s transition to a competitive auction mechanism that awards contract for difference (CfD) FITs received state aid clearance from the European Commission (EC) in late July, representing another milestone in the execution of the Government’s Electricity Market Reform (EMR). While this is welcome news for the market, it needs to be seen in context, i.e., just another small step in what appears to be an almost pedestrian transition under the U.K.’s EMR.
Pots of Cash
Notwithstanding, within days of this EC approval, a draft budget for October’s first CfD allocation round was released proposing £205 million (US$340 million) of support split between two categories; “established” technologies such as onshore wind and solar PV awarded contracts for project delivery beginning 2015-16 will receive £50 million (US$83 million) annually, while “less-established” technologies such as offshore wind, wave and tidal energy will be allocated £155 million (US$257 million) for projects beginning 2016-17. The draft budget also reinforced a decision in May to not allocate any subsidy support for coal to biomass conversion plants.
While the final budget won’t be announced until late September, it has already attracted criticism. While recognizing the need to hold back budget for future years, there’s also a sense that the allocation is overly cautious and falls short of what is required to drive down the cost of renewables in the long run. The U.K.’s Solar Trade Association (STA) has described the draft allocation as “absurd,” as even applying the whole “established” budget of £50 million (US$83 million) to solar PV would support only 1 GW of capacity, a considerable reduction given the market’s current growth potential.
The £155 million (US$257 million) allocation for “less established” technologies would also barely cover one small offshore wind project. These budgetary constraints are likely to further exasperate the stalling investment in new U.K. projects driven by the EMR stalemate. Some cynics may think this is a deliberate intension of the policy-makers.
Value for Money
The industry’s disappointment is likely to be all the more bitter after the UK National Audit Office (NAO) concluded that the Government has overpaid CfD subsidies to the five offshore wind and three biomass projects awarded early Final Investment Decisions in April. The NAO is “not convinced” that the decision to award £16.6 billion (US$28 billion) of contracts — equivalent to around 58 percent of the U.K.’s total available funding for renewables between 2015 and 2020 — is worth the risk to taxpayers, and claims that it may have undermined future bidding rounds by expediting contracts without ensuring sufficient price competition.
The threat of yet further policy upheaval also looms large as the Government considers offering CfD support to foreign renewables projects to aid the achievement of the UK’s 2020 target. While it has reassured the sector this will not occur before 2018, acknowledging that the challenges and complexities of such a change will require most aspects of the EMR policy design to be reviewed, even the prospect of further changes could be too much for an already fragile market fatigued by ongoing policy tinkering.
Nowhere has this been felt more recently than in the solar sector. Four of the UK’s largest solar companies have launched a legal challenge in response to the Government’s surprise announcement in May of its intension to withdraw Renewables Obligation (RO) support for solar projects above 5 MW two years earlier than planned, forcing them to compete for CfDs with other mature technologies. The challenge came just weeks after a coalition of more than 150 businesses petitioned the Government to give solar extra time and policy stability to compete with conventional fuels and avoid putting the U.K.’s current position in the booming global solar market at risk.
The U.K. has now become only the sixth nation to surpass the 5 GW installed capacity mark for solar PV, according to NPD Solarbuzz. Around 1.5 GW of new capacity has already been installed in the first half of 2014, more than the whole of 2013 and putting the U.K. on track to become the world’s fourth-largest market for new solar deployment this year. Martifer Solar, a Portuguese clean energy developer, plans to develop 100 MW of new capacity in the U.K. by early 2015, and a joint venture between China’s Znshine Solar and U.K.-based MAP Environmental has agreed a US$680 million deal to develop a 400-MW solar portfolio.
Large to Small
The Government’s unexpected solar intervention therefore comes despite record levels of public popularity and industry appetite. The rationale offered is the need to shift development toward commercial and domestic rooftops amid concerns that large-scale installations threaten to monopolize the RO budget, claims the STA say are ill-founded given solar currently accounts for just 5 percent of total RO expenditure.
Few in the sector are disputing the importance of the small- to mid-scale solar projects but point out that such projects still lack clear policy and incentive drivers to unlock their value.
Choppy Waters Ahead
The U.K. offshore sector is also continuing to experience mixed fortunes, with a mismatch between the potential 37-GW project pipeline and the Government’s target for 10 GW to 20 GW by 2020. The proposed CfD budget could reduce this ambition further, while the announcement in early August that Centrica and DONG Energy are abandoning the 4.2-GW Celtic Array in the Irish Sea is another blow to the sector. The developers have cited challenging seabed conditions that make the project economically unviable with current technology, though some are speculating that policy backsliding may also be a factor.
Project Pipeline Pickup
Projects are still flowing, however. Statoil and Statkraft are to proceed with the £1.5 billion (US$2.5 billion) Dudgeon wind farm after receiving CfD approval in April for the 402-MW project, and E.ON has received the green light for its proposed 700-MW Rampion wind farm with an estimated price tag of £2.0 billion (US$3.3 billion). JV partners ScottishPower Renewables and Vattenfall Wind Power have also recently received planning consent for the 1.2GW East Anglia One project, part of a wider 7.2-GW development granted under Round 3 of the Crown Estate’s offshore licensing program.
GIB Takes Offshore Private
But perhaps the biggest boost for the sector in recent months has been the unveiling of plans by the Green Investment Bank (GIB) to launch a £1.0 billion (US$1.7 billion) offshore wind fund to help utilities refinance operational wind farms and start new developments. It will be the first private capital under the control of the bank following receipt of EC state aid approval in May 2014 to promote and manage funds and other co-investment structures. The GIB will contribute up to 20 percent of the capital and is now seeking a suitable group of strategic long-term co-investors to participate in this “innovative capital-raising exercise.”
Lead image: United Kingdom map via Shutterstock
This has become a matter of key urgency for the Russian Far East, a vast area of 6.2 million square kilometers, which makes over one-third of the Russia’s total area with the population of a mere 6.2 million. With plans to ramp up capacity to 4 MW, the facility will become the largest solar installation behind the Arctic Circle.
Out of four bidders, Xelios Strategije proposed the lowest price for the construction with RUB 156.7 million (US $2.9 million). The project is slated to launch in the first half of 2015.
“When interconnected with the grid, the 1-?W facility, coupled with a local diesel-fired combined head and power (CHP) system, will complete in Sakha the creation of a single energy complex able to fully satisfy the demand for power and heat and, importantly, cut down the generation costs at local diesel-fired power plants and better manage the use of expensive diesel,” said Alekseij Kaplun, deputy director general of Energiceskije sistemy Vostoka.
Upon completion, Energiceskije sistemy Vostoka will be able to save over 54,000 tons of diesel fuel worth US $43.4 million every year, said Kaplun. The Batagaij settlement is one of the first localities already able to use the program’s benefits.
“For Batagaij Verxojansk, a settlement of nearly 4,000 people and with its own kindergartens, hospitals and educational establishments, securing an uninterrupted energy supply is extremely important. Besides, the new facility will allow for the accumulation of power capacity reserves, which subsequently will increase the reliability of power supply to the Batagaij power hub during fall and winter, when it experiences maximum load,” stressed Kaplun.
The plant is part of Vostoka’s strategy to install a set of autonomous hybrid power systems in Sakha, which use is applauded due to the region’s limited access to the conventional energy network that results in a gap between supply and demand.
Russia is committed to boost its solar and wind capacity from 250 MW currently to 6 GW by 2020. Russia’s current electric power generation capacity is estimated at more than 220 GW.
Currently, Vostoka is operating seven solar facilities in the region. But the holding eyes developing more than 170 renewable energy facilities with a total capacity of 120 MW by 2020.
The solar-diesel hybrid installations are thought to reduce the cost of local electricity output by 40 percent and, consequently cut down the regional and federal governments’ energy subsidies.
Despite these cost reductions, Russian federal authorities in Moscow have been wary and weary of the renewable energy costs in the region, where the temperature can dip under -50 degrees Celcius in the winter.
“Solar development in the remote and isolated regions of our country cannot be seen as a single solution, especially in the light of the mind-blowing cost at $3 per kWh. In general, I don’t like to see when the hype about green energy compromises conventional energy sources,” Ivan Dmitrij Graciov, chairman of Russian Duma (Parliament) Energy Committee, told Renewable Energy World.
While the Russian Far Eastern region boasts high solar insulation — around 800 kW per square meter per year — high renewable energy costs along with the local content production requirements are impeding more rapid expansion of the renewables in the region.
“In addition to the money already pumped into the region’s energy system, an extra US $13.3 billion is needed to maintain and boost the investment environment and attract for that new investments to the problematic sector today. To secure the flow of investments, legislative investment-“friendly” amendments are necessary first,” insisted Kaplun.
According to him, the industry needs regulation, but it has to be reasonable. The Far East needs long-term tariff regulation so that payback in investment — and generation — can be achieved, explained Kaplun.
“If conventional energy needs 20 years for seeing payback in investmnent, for renewable energy, it would be enough 10-15 years. Securing that kind of tariff would create clear conditions for potential investors, and company would be able to independently attract third-parties in investments,” said Kaplun. “Now, special tariff policies for renewable energy are regulated by direct agreements with regional administrations, but they do not provide sufficient assurance to those who are willing to invest in these projects.”
Kaplun also urged to exercise caution on the local content requirement.
“We understand the situation, but the fact is that the hardware requirements are different everywhere, depending on the region, whether we speak of Yakutia, Kamchatka, Sakhalin or others. For example, in the village of Batagai, where we will put solar panels, the annual fluctuation in temperature is up to 100 degrees. Which manufacturer can guarantee an industrial-scale operation of its equipment in such conditions? Therefore, the equipment is made especially for us,” said Kaplun.
And, as a new NRDC fact sheet published today illustrates, the electric grid can handle much higher levels of zero-carbon wind and solar power, far more than what’s necessary to achieve the relatively modest carbon emission reductions in the U.S. Environmental Protection Agency’s plan to limit pollution from existing power plants. But first, a little background on how our nation’s electric system works.
The nation’s high-power transmission system is made up of three largely separate grids: one on either side of the Continental Divide (roughly) and the third in Texas. The two largest grids are further subdivided into regions managed by different regional and local utility grid operators.
Source: MJ Bradley Associates using Ventyx Velocity
Grid operators are the air traffic controllers of the power system, managing the flow of electrons from power plants to customers across thousands of miles of transmission lines. They operate the grid under extremely detailed procedures and standards.
Planning for the Next 5 Minutes and the Next 10 Years
To ensure a reliable transmission system, grid operators think in several time frames. In the immediate seconds to hours, they run the grid according to a detailed set of economic and electrical engineering rules embedded in sophisticated computer programs. These programs dispatch power plants with the lowest operating costs first, subject to important constraints to preserve the grid’s stability and avoid blackouts.
Grid operators also plan years into the future to ensure reliability. In the same way that one would not set out to drive across the desert on a half-tank of gas, they want to ensure enough power exists and can be delivered to meet consumer demand years ahead. To do so, they identify factors that could either increase or decrease the need for more power and power lines, and then plan accordingly.
Wind and Solar Power Hit the Big Leagues
There is more renewable energy flowing through the power grid than ever before. At times, wind has supplied more than 60 percent of the total demand on some utility systems, without reliability problems. And solar power now routinely contributes 10 to 15 percent of midday electricity demand in California, which has more solar panel installations than anywhere in the country.
Source: American Wind Energy Association independent analysis based on real time data publicly available by ISOs and utilities
Accurate Forecasts and Advanced Technologies Matter
Due to more precise weather forecasts and sophisticated technologies, grid operators increasingly can predict—and control—wind and solar generation levels. Accurate predictions of wind speed and solar conditions help grid operators efficiently schedule renewable energy into the system. Using advanced and often-automatic control systems, grid operators can both increase and decrease the power output into the grid, which helps to stabilize the grid’s electrical frequency and maintain reliability.
Wind and Solar Need Less Backup Power than Coal, Gas and Nuclear
Every power plant on the grid needs “backup” power in case something happens to prevent it from generating as much electricity as planned. PJM, in charge of most of the grid from New Jersey to Illinois, currently holds 3,350 MW of expensive, fast-acting contingency reserves 24/7 to ensure that it can keep the lights on in case a large fossil or nuclear power plant unexpectedly breaks down. In contrast, MISO – the grid operator for the middle part of the country with the most wind power in the nation – needs almost no additional fast-acting power reserves to back up its 10,000-plus MW of wind power on the system.
Why is so little backup power needed for wind and solar? In contrast to the large, abrupt, and often unpredictable changes in electricity output from coal and nuclear power plants, wind output changes tend to be gradual and predictable, especially when wind turbines are spread over larger areas. The fact that a wind farm is a collection of many smaller turbines also helps, since the failure of one has little impact on the farm’s total output.
Our Grid Is Successfully Integrating Clean Energy Now and Will Continue
The power grid has always adapted to changing state and national energy trends and needs, thanks to regular operations and planning frameworks. Forty years ago grid operators learned to accommodate the sudden losses of generation that can come from integrating very large nuclear power plants into the system.
Now, as utility-scale wind and solar power rapidly expand, grid operators are successfully integrating these new resources into the grid while retiring many outdated, costly, and polluting coal plants. And they’re doing it without most Americans even noticing. Maybe that’s the best proof that wind and solar power are not just ready for the big leagues, they’re already there.
This article was originally pubished on NRDC and was republished with permission.
San Francisco —
Duke Energy and other utilities in South Carolina are preparing a plan for developing distributed solar in the state on the heels of a net metering agreement announced last week. The utility plan will be delivered to the state public utilities commission in February, and after a few months of expected PUC deliberation, Duke will begin implementation “immediately,” according to Ryan Mosier, a spokesperson for the utility.
«The state has been very methodical and intentional in embracing solar – so much so, South Carolina may now be the model other states will want to follow.” — S.C. Gov. Nikki Haley
The net metering agreement provides that Duke and other utilities in the state will both charge and pay solar customers for energy at the same rate — currently about 10 cents per kilowatt-hour — over the next decade or longer. The agreement — developed by a consortium of utilities, co-ops and environmental, consumer and industrial groups — is based on a law signed by Gov. Nikki Haley in June, known as “A Balanced Path for Distributed Energy in South Carolina.”
Among provisions of the law apart from a mandate to reach a net metering agreement is a plan to foster solar adoption by educational and non-profit organizations in the state. Duke has already has contributed $2 million to Palmetto Clean Energy (PaCE), “a nonprofit organization that promotes the development of renewable energy resources.” Duke notes that “Through PaCE, we fund a pilot program that provides matching grants to K-12 schools and not-for-profit educational institutions interested in installing rooftop solar systems.”
The law also enables Duke Energy Carolinas and Duke Energy Progress in South Carolina to add up to three percent of the utilities’ peak demand, or about 150 MW of solar in the state. And the law provides for the PUC to establish a program for residential and commercial customers to lease solar facilities from non-utilities and utilities.
Mosier said, “The agreement is pretty unique and was crafted by groups in South Carolina for South Carolina.” At the time of his signing of the law, Gov. Haley said, “the state has been very methodical and intentional in embracing solar — so much so, South Carolina may now be the model other states will want to follow.”
Duke currently has only about 200 residential solar customers in South Carolina, but the utility’s two units rank fifth and tenth in the nation in terms of installed MW assets per customer (see table). Duke Energy Renewables, part of Duke Energy’s Commercial Businesses, began building and operating photovoltaic solar projects for commercial business customers in 2009. The company and now owns about 150 MW of generating capacity at 21 solar farms in various states. Duke Energy has invested more than $3 billion since 2007 to develop its U.S. commercial wind and solar power businesses.
There is big news to report from the front lines of our current campaign to protect wind in 2015. And though there’s bad news and good news — it all points to how critical your voice is going to continue to be in our fight for clean, homegrown energy.
As you may know, a few weeks ago, when Congress began negotiating the terms of a bill that could make a huge difference in bringing affordable wind power to American families in 2015, we launched a nationwide campaign to support it.
However, we weren’t the only ones reaching out to Congress. Anti-wind organizations have been fired up beyond any opposition we’ve seen before. They’ve been spending millions of dollars and writing messages to legislators urging them to leave wind policy out of this bill.
Late last week — we started to see the impact of our opponents’ attacks, and our own efforts to defend wind. By a vote of 378 to 46, the House voted to pass H.R. 5771, a bill that proposed to extend multiple tax incentives through the end of this year, including two common-sense energy policies – the production tax credit and investment tax credit.
Last night — by a vote of 76 to 16, the Senate passed the same bill. The President is expected to sign it into law shortly.
The bad news: This extension falls short of what we were pushing for. We wanted to see a two-year extension, which would make a huge difference in providing more clean and affordable energy to Americans than ever before.
The good news: The voices of wind advocates in our Power of Wind network were heard, and helped preserve common-sense wind policies through this year. At a time when our opponents were fighting to eliminate wind policy, we powered through and gained at least an extension through this year of the wind policies vital for clean energy growth.
We’ve proven that we can counter the well-funded voices of the anti-wind movement. However, we have our work cut out for us. In January, we will need your help to:
If you haven’t already, please sign up at PowerofWind.com to communicate with your elected representatives (we make it easy!), and join thousands of others in becoming part of the reason common-sense wind policy can carry on.
Lead image: Wind turbine via Shutterstock
This is an excerpt from EERE Network News, a weekly electronic newsletter.
Maps can help you plan a road trip, explore new places, or even find buried treasure. But there’s another kind of map that can help chart the path to a more sustainable future and unlock the potential for wind energy development. The Energy Department’s National Renewable Energy Laboratory (NREL), together with the Energy Department’s Wind Program and AWS Truepower, has released maps that illustrate the potential for wind energy development using new wind turbine technologies.
Wind industry professionals use wind resource maps in the early stages of wind farm project planning to understand the potential for wind development in a particular region and to see where more in-depth site evaluation might be justified for various types of turbines.
The Energy Department previously released maps that gauge average wind speeds at 80 and 100 meters (262 and 328 feet) above the ground. The new maps released by NREL recently build on these wind speed data to identify areas throughout the country that have an average wind energy capacity factor greater than 35%. (Wind energy capacity factor is a measure of power plant productivity that indicates how much electricity a wind farm actually produces relative to the maximum it could potentially produce at continuous full-power operation over a specific time period.) For the complete story, see the EERE Blog.
“This is the first time that the industry is able to articulate such a complex deal in Africa,” Araluce said by phone. “This will ease future projects and I’m sure it’s the first of many to come in Africa.” He declined to disclose the value of the order.
The project, to be built about 1,200 kilometers (746 miles) from the port city of Mombasa, would generate enough power to meet about 15 percent of the nation’s electricity demand. While about 420 kilometers of transmission lines will have to be built to connect it to the grid, the plant will save East Africa’s biggest economy about 150 million euros ($186 million) in fuel imports each year, Vestas said.
“Eastern and southern Africa are key markets for Vestas, and the Lake Turkana project will establish Kenya among the continent’s wind-energy leaders,” Christoph Vogel, president of Vestas Central Europe, said in the statement.
The combination of desert and lake climate results in strong and steady winds, with an average speed of 11.3 meters per second, Araluce said. Vestas is confident it can announce more deals in Africa in the next two years, he said.
Sub-Saharan Africa may this year add about 1.8 gigawatts of renewable-energy capacity, excluding large hydroelectric power plants, Bloomberg New Energy Finance said in August. Investment in countries including South Africa, Kenya and Ethiopia is estimated at $5.9 billion, and may reach $7.7 billion in 2016. Lake Turkana had been delayed by about three years because of difficulties in securing financing.
Copyright 2014 Bloomberg
Lead image: Wind turbines via Shutterstock
Electricity customers in the U.S. got good news last week.
A new report from Accenture highlighted a potential revenue loss for U.S. utilities of $48 billion per year by 2025 due to distributed solar and energy efficiency. But where does that money go? If we pursue a democratic energy system as outlined in ILSR’s new report (also released last week), it goes right into the pockets of utility customers.
Read on for an explanation of how we can achieve energy democracy out of the turmoil of today’s electricity system.
A System Under Stress
Why are U.S. electric utilities facing huge revenue losses? Because their business model, built around a 20th century centralized command-and-control electric utility, is increasingly outdated in an age when we can produce power on rooftops from ubiquitous sunshine and manage energy individually on ubiquitous smartphones.
See the following timeline released in ILSR’s new report to understand the changes being wrought.
There have been three waves of change crashing over the electric utility system in the past 50 years: Shock Competition, Deregulation, and Transition. The third wave, powered by distributed renewable energy and stagnant energy demand and aided by state regulation, isn’t going to recede.
Already, the Wall Street Journal notes that the era of growing electricity sales is likely over.
Not only is demand falling, but competition from renewable energy sources is growing. In the past few years, that competition isn’t just from other large power producers, but from utility customers themselves (see the growth of «small solar» in particular (and red), representing residential and commercial installations 1 megawatt and smaller).
Utilities haven’t given up in the face of this threat. In fact, they’re often actively fighting it while they continue to invest in the infrastructure for last century’s grid (read more in ILSR’s report).
These battles are the origin of «Utility 2.0,» a business model discussion inside and outside of utilities that would allow electric companies to accommodate flat energy demand and rising customer energy production. It’s good policy, focused on shifting the principles of the electricity system to a low-carbon, flexible, and efficient one as well as shifting utility incentives to achieve these outcomes.
But Utility 2.0 will prove inadequate if it remains indifferent to the flow of energy dollars out of communities (the $48 billion question).
Already, 500,000 U.S. homes sport solar energy and it gets more affordable every year. Rooftop solar, smartphones, and widespread energy storage will give utility customers unprecedented opportunity to control their energy usage, and to capture their share of the nation’s energy dollars. A 2.0 utility business model that doesn’t accommodate this opportunity for local, equitable access to energy production and management will leave many U.S. electricity consumers deeply unsatisfied.
That’s the central point of Utility 3.0, or as we call it, energy democracy. It adds two other principles – local control and equitable access – to the low-carbon, flexible, and efficient grid of the future to make the Five Pillars of Energy Democracy. The following graphic illustrates the principles of the ideal 21st century electricity system and how the policies of the electricity system contribute to achieving those desired outcomes.
How do we get to energy democracy from where we are now? In Vermont, the state has already identified and adopted many of the key strategies and policies, from robust net metering to integrated distribution and transmission planning. They have an independent energy efficiency utility, and a feed-in tariff to encourage broader distributed renewable energy development. In New York, the state is Reforming the Energy Vision, and considering how to make an open and transparent marketplace that puts utility customers on an even footing with utilities in providing key energy services. The following graphic illustrates this concept.
Neither state has unleashed a system with real «energy democracy» yet, but they’re pursuing the right principles and structure and policy that will lead in that direction.
Will utilities survive this crashing wave of energy democracy? It depends on your definition of survive. Will they continue to profit from retaining control over the generation and transaction of power on the electricity system? Perhaps not. Could they profit from designing and deploying the infrastructure and software to make a democracy energy distribution system? Certainly. They just need a little vision.
And we’ve got one to share.
This article originally posted at ilsr.org. For timely updates, follow John Farrell on Twitter or get the Democratic Energy weekly update.
Photo credit: Jonathan Potts
Indeed, benefitting from its mountainous landscape and position between three seas, Turkey has a significant hydropower capacity, estimated at some 433 TWh a year in total, of which some 140 TWh a year is thought economically viable. To put this in context, according to Turkish Electricity Transmission Corporation figures electricity demand is expected to reach around 420 TWh annually by 2020.
At an average elevation of 1,100 meters above sea level, with the Euphrates and Tigris River basins sitting at around 1,300 meters, there is ample head available for development in a number of regions, including the area around the Black Sea, the Mediterranean, and Eastern Anatolia.
Given that the geography provides considerable opportunity for hydropower development, it was only following measures to privatize the national electricity system, which began in 2003, that the exploitation of this huge resource began to accelerate. Today, though some 60 percent of the country’s hydropower potential remains undeveloped, Turkey has more than 500 hydropower plants operating with a combined capacity of more than 15 GW. Further the country has more than 15 GW of hydropower capacity currently under construction.
Turkish Energy Policy Landscape
Despite the considerable development of Turkey’s abundant hydropower and other renewable resources, the country’s energy mix is still dominated by fossil fuels. Currently, gas supplies around a third of the country’s total primary energy demand, while coal and oil products provide 27 percent and 29 percent, respectively. Much of the country’s oil and gas comes by way of imports from Iran and Russia. Hydropower, wind, and other renewables produce around 17 percent of Turkey’s electricity supply.
However, in a bid to bring down the share of natural gas to less than 30 percent of total energy supply, the government has introduced policies aimed at diversifying the energy supply by supporting domestic sources in particular. As part of this policy, renewables, including hydropower, have been the beneficiaries of feed-in tariffs to encourage their development. In the case of hydropower projects beginning operations before the end of 2015, the feed-in tariff is US $0.073/kWh (€0.056/kWh) with an additional “local-content” bonus of US $0.01-0.023/kWh (€0.007-0.018/kWh) which is payable for 10 years. The local content bonus is available for five years.
Other reforms centered on the liberalized electricity market, accelerated private investment in Turkey’s energy sector and by 2012, independent power producers were supplying some 26 TWh of energy annually. In addition, the government established a target to deliver 30 percent of its primary energy demand from renewables by 2023.
In other examples of supportive policy measures, the Energy Market Regulatory Agency (EMRA) has instituted a license fee exemption for renewable energy investors and the Turkish Electricity Trading Company, TETAS, can provide buying guarantees to renewable energy, further supporting inward investment.
Didier Mallieu, Vice President of Hydropower and Renewable Energy at engineering consultancy firm Poyry, explained that Turkish companies spearheaded the post-liberalization development drive. He said that there is significant engineering capability in Turkey and that those engineering firms teamed up with mainly Western European companies to jointly develop and finance hydropower projects. “Many players in the European market, many European utilities, were interested in acquiring projects or assets in Turkey two, three, four years ago,” he said.
However, he added that given the scale of this development — he estimated that around 70 GW of new power generating capacity was under construction in Turkey — “we see a little bit of slowdown for the moment in new projects and some are being put on hold.”
This is partly a result of a more challenging finance market, he explained, adding that the classic buyers or developers of those assets, the European utilities, are experiencing difficulties themselves. Mallieu also noted that the easiest projects have been developed already. “What remains is a bit more difficult to develop and probably requires a higher market price to be economical, this could be why we see a slowdown of the Turkish market for new hydropower plant.”
Mallieu said that the slowdown is “typical of the transition to deregulated electricity market, where investors’ most important risk is the building of overcapacity. Therefore, investors might have the tendency to postpone investments until they are certain that the capacity additions are in line with demand growth.”
Further, he said that, “such a phenomenon is partly mitigated in Turkey by the cancellation of power plant licenses which are now not going forward. The high volatility between various electricity generation scenarios might represent risks, but for sure also potential opportunities, maybe huge opportunities.”
Mallieu highlighted other factors that are influencing new Turkish hydropower development. For example, along with setting ambitious renewable energy targets the government is also looking to develop other low-carbon resources, such as nuclear, with plans for nuclear power to supply some 5 percent of the country’s electricity supply, some 5 GW.
Within the renewables sector, hydropower is also competing for investment with technologies such as wind and solar, which inevitably require far less up-front capital investment and typically have a far shorter development and ROI period too.
In August 2013, Minneapolis (MN) was in the news for considering a take-over of its energy utilities. Today, they’re back in the news for supporting a first-in-the-nation clean energy partnership with those same utilities and a pioneering effort to bring more local input into the city’s energy future. It’s been a whirlwind week.
On Monday, the city council earned a Climate Champion designation from the White House. Last night they proved the designation was well placed by funding their half of a novel city-utility partnership that was sealed in early October. The vote to provide $150,000 for the partnership is a crucial step achieving a better energy future.
The partnership has its roots in the city’s desire to find equitable, local solutions to climate change.
Over the past several years, Minneapolis has developed a comprehensive sustainability plan, including these ambitious targets: generating 10 percent of energy from local renewable energy sources, cutting energy use by 17 percent and reducing greenhouse gas emissions 30 percent by 2025. But there’s a big fly in the sustainability ointment. Two-thirds of the emissions from city residents and businesses come from energy sold by Xcel and CenterPoint.
In other words, the city’s sustainability success hinges on its ability to influence the use of its two largest energy sources: electricity and gas.
Since the law gives the city virtually no influence over its energy utilities, another tactic was necessary. You can read (or watch) more about the history here, but the summary can be boiled down to these five steps:
But what can this partnership accomplish?
It all depends on the workplan, and the grassroots team at Minneapolis Energy Options has delivered. (Disclosure: I serve on the board of Community Power / Minneapolis Energy Options).
Outlined in their draft proposal (to be discussed and improved by the city-utility partnership board) are nine ambitious yet achievable strategies for the next two years. The strategies will involve new city ordinances and utility program changes, and an unprecedented level of coordination between the partners, energy program delivery entities, and the residents and businesses of the city. It will mean one of the biggest coordinated grassroots efforts to mobilize the city to seize control of its energy future, individually and collectively.
What’s the best part of this plan? It’s all about local action. No state law or regulation made this partnership, just grassroots organizing. So why isn’t your city doing the same thing?
The Big 9 Two-Year Strategies from Minneapolis Energy Options
1. Residential Energy Efficiency
2. Rental Energy Efficiency
3. LED Streetlights
4. Affordable Community Solar
5. On-Bill Financing
6. Buying Rural Renewable Energy
7. Commercial Building Energy Challenge
8. Incentives for Green New Buildings
9. Residential Energy Bench-marking
1. Stream-line Residential Energy Efficiency Program for Buildings with 1-4 Units
Build off of the existing Home Energy Squad program, the Sustainable Resources Center low-income weatherization program, a pending CenterPoint Energy pilot project, and existing community energy projects to create a single, coordinated residential energy efficiency program that includes: