Warning of future blackouts as politics dominates energy and climate debate

Victoria and NSW have been warned they could follow South Australia in being hit by electricity blackouts in years ahead unless Canberra comes up with a bipartisan national plan to deal with energy and climate change.

Victoria and NSW have been warned they could follow South Australia in being hit by electricity blackouts in years ahead unless Canberra comes up with a bipartisan national plan to deal with energy and climate change.

The Turnbull government leapt on the latest in a string of South Australian blackouts, which hit about 40,000 properties for 45 minutes during extreme heat early Wednesday night, to accuse the state Labor government of relying too heavily on renewable energy.

The attack dominated parliamentary question time, with Treasurer Scott Morrison brandishing a lump of coal – a sign of his party's support for more generation from the high-emissions fossil fuel, which he contrasted with federal Labor's 50 per cent renewable energy target.

Prime Minister Malcolm Turnbull said Labor's ideological approach to renewable energy was turning off the lights in Adelaide. "They have failed to deliver the security of energy that Australians need," he said.

Energy Minister Josh Frydenberg said the state needed to look at every option to stabilise the system, including reopening the 32-year-old Northern coal-fired station that closed last year and is already partly demolished.

But South Australian Energy Minister Tom Koutsantonis blamed the blackout on a "massive, catastrophic failure" of the National Electricity Market. He pointed to the state's gas-fired power plan at Pelican Point, which could have provided the power needed but was not called on to run at full capacity.

"I think what you're seeing at a national level is an ignorance that the problem that's occurring here is coming to a city near you on the eastern seaboard soon," he said.

Energy industry leaders and experts warned the government was incorrect to solely blame the South Australian government for the electricity crisis and called for a national solution.

While South Australia backs clean energy, the overwhelming driver of the state's high percentage of wind energy had been the national renewable energy target, which has bipartisan support. South Australia has many of the best sites for wind generation in the country, and therefore had drawn much of the investment triggered by the national target.

It has happened as nine coal plants have closed in seven years, with no policy to drive what should replace them. Victoria's Hazelwood plant will follow next month, though analysts believe it should not lead to blackouts if the market functions as it should.

Australian Energy Council chief Matthew Warren, representing 21 electricity and gas businesses, reiterated calls for a bipartisan energy and climate plan to guide companies on what they should be investing.

"Politics has turned this into the Punch and Judy show. We're trying to get something that is workable. We have politicians from both sides accusing their opponents of being ideologically driven and political, but then both sides are guilty of that in the next sentence," he said.

Tony Wood, energy program director at the Grattan Institute, said no players in the debate were blameless, but the Turnbull government should be called out for blaming the state government.

"I will criticise crazy state-based renewable energy targets, but this is not the result of a South Australian policy," he said.

Mr Wood said the available gas plant lying dormant when it was needed was either a failure of the rules governing the national electricity grid, or the way the market operator was interpreting them.

Chief scientist Alan Finkel is running an inquiry into the national electricity grid that was commissioned after a statewide South Australian blackout in September. An interim report in December flagged the need for changes.

South Australian Premier Jay Weatherill said, with no national solutions being offered and the market operator unable to guarantee security of supply, the state was considering options to intervene in the national market to ensure supply.

The market operator has warned of more potential problems during hot weather ahead, with the possibility of a blackout in NSW on Friday afternoon.

Accusations flared over why available gas-plant was not in operation when it was known the wind would not be blowing on Wednesday - whether the market operator had failed to direct the it to run, or plant owner Engie had failed to respond to a call for bids to sell power into the grid.

Labor environment spokesman Mark Butler said Mr Frydenberg should stop playing politics with the national energy crisis and make sure the market operator was doing its job.

Mr Frydenberg said South Australia had the power on Wednesday to ask for more generation to be operating. He said he had asked the market operator for an urgent report into what happened.

Australian Industry Group chief Innes Willox called for consideration of energy users of all sizes being offered an incentive to slightly cut back usage at critical times.

"We need both long-term reform for a market that delivers affordable, reliable and clean energy, and urgent shorter term measures to ease the current crunch," he said.

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The story Warning of future blackouts as politics dominates energy and climate debate first appeared on The Sydney Morning Herald.

NextEra will be the new energy supplier for Cape Light Compact

Austin Brandt, power supply planner for Cape Light Compact. — Courtesy of Austin Brandt

In January, Island customers of Cape Light Compact (CLC) got a new energy supplier — NextEra — and all that power is generated by 100 percent renewable sources. Plus, the new rate for residential customers — in place only until the end of July 2017 — is 9.93 cents per kilowatt-hour (kWh), slightly lower than the residential rate from Eversource, the regional electricity distributor, which is 10.318 cents per kWh. According to Austin Brandt, CLC’s power-supply planner, CLC and Eversource both change the prices for residential customers at six-month intervals, and determine their prices by analyzing the futures market. Customers can expect new rates to be announced in early summer. Differences in price are due to locking in at different times and varying blends of energy sources. Individual Eversource customers were switched over from Con Ed Solutions to NextEra through the month of January, as their billing period ended and a new one began.

CLC is a municipal aggregator; its primary purpose is to negotiate a competitive price for electricity for its members. The regional compact was formed in 1997, in the wake of the 1992 federal Energy Policies Act, which among many other changes, forced energy producers to separate themselves from energy distributors. This created room in between for aggregators, made possible in Massachusetts in 1997, by the Massachusetts Restructuring Act.

Since 2005, until this month, CLC bought its power for residential users from Con Ed Solutions, a Valhalla, N.Y.–based company. According to Mr. Brandt, CLC began buying power in in 2014 for its industrial and commercial customers — a distinct minority in the Cape and Islands region — from the Massachusetts affiliate of NextEra Energy Services, based in Juno Beach, Fla. With the residential supply contract up for renewal in 2016, CLC issued a request for proposals (RFP) and received two, one from NextEra and one from Con Ed.

“[CLC executive director] Maggie [Downey] and I discussed how to go green,” Mr. Brandt said, “and then we brought in the board of directors. We asked Con Ed and NextEra to consider this in their proposals.” NextEra was chosen, according to Mr. Brandt, because its price was competitive, its representatives seemed comfortable with the commercial and industrial load, the deal gave better value for the cost, and NextEra brought options for making the supply 100 percent green. In spring 2016, CLC entered into a contract with NextEra.

What is a compact?

CLC is the oldest municipal aggregator in the state, and the only one that pools customers from multiple municipalities into a single purchasing bloc. It includes all 21 towns on the Cape and Martha’s Vineyard, as well as the governments of Barnstable and Dukes counties.

“Barnstable County created Cape Light Compact after the 1997 restructuring act,” Ms. Downey said. “Back then, they had a forward-thinking local government.” The county organized and funded CLC. Energy-efficiency funds that pay for all CLC activities are derived from a systems benefits charge of $0.025 cents/kWh that is added to the bill of all utility customers.

The compact is an example of a community choice aggregator (CCA), which allows for the group purchasing of power. CCAs are established by law in seven states now, with Massachusetts being the first to adopt them. They work in partnership with an existing utility, Eversource in the Cape and Islands, which continues to deliver power, maintain the grid, and do the billing.

In addition to negotiating contracts for the delivery of power, aggregators may also administer energy-efficiency programs, including energy audits for homes. According to Ms. Downey, this free service is available to Martha’s Vineyard customers during one week out of every month. She said there was now an eight-week waiting list.

As an aggregator, CLC is not allowed to develop power generation. In 2008, the passage of the state’s Green Communities Act made it possible for cities and towns to develop their own power generation.

“Green Communities made sale of energy as a transaction more viable economically,” Ms. Downey said, “because of net metering credits. In addition, the price of PVs [photovoltaic cells] plummeted.” The 1997 restructuring act had allowed for the formation of municipal energy cooperatives, and CLC formed the Cape and Vineyard Energy Cooperative (CVEC) in 2007 to be an entity that would develop renewable energy projects.

CLC is still a member of CVEC, Ms. Downey said, but it is no longer funding it. Early in the development of CVEC, CLC employees were doing most of the administrative work. Between 2007 and 2014, CLC gave CVEC help in the form of grants from surplus in the energy-efficiency funds used to run CLC. After 2014, the surplus was depleted, and CVEC must raise all of its own revenue.

Also in 2014, according to Ms. Downey, the political atmosphere at Barnstable County changed. After what she described as “a rocky time with the [county] assembly of delegates,” CLC ended its contract for services with the county. All of the CLC staff are employees of the county; Ms. Downey is the assistant county manager.

“At the county, it came down to the issue of liability for employees who worked for CLC,” the executive director said. “We were told that we’d have to become a county department or move on, so we signed a termination agreement. The contract expired in 2022 anyway; all this did was fast-forward that conversation.”

In response, CLC has been advised by counsel to form a “joint powers entity.” CLC would have employees of its own, but would contract for administrative services with one of its member towns. Its relationship with Barnstable County will end in June or before.

CLC’s relationship with the state is not extensive. According to an email response from Katie Gronendyke of the Executive Office of Environmental Affairs, “municipal aggregators, like Cape Light Compact, are statutorily allowed (although not required) to develop demand-side management programs (now referred to as energy efficiency). Those plans must be submitted to the DPU [Department of Public Utilities] to certify that the plan is consistent with the state energy conservation goals developed pursuant to statute.

“Currently, Cape Light Compact is the only municipal aggregator with a ‘certified’ energy efficiency plan. Their last three-year energy efficiency plan, for the 2016 through 2018 term, was reviewed and approved by the DPU in D.P.U. 15-166.

“The filings made by the Cape Light Compact recently have pertained to their energy efficiency plans, goals, and spending. The DPU reviews these filings consistent with applicable law and statute.”

100 percent green supply

Although CLC signed a contract with NextEra in spring 2016, it had not yet decided to go 100 percent renewably sourced. Mr. Brandt and Ms. Downey put this matter before CLC’s directors, who discussed it between late summer and the fall. By November they had decided to “go green.”

“If we hadn’t gone this route,” Mr. Brandt said, “the difference would have been a tenth of a cent per kWh. The difference is small because [divisions of] NextEra own a regional power grid [in Florida] and a variety of resources — both renewable and nonrenewable.”

A division of CLC’s new supplier, called NextEra Energy Resources, develops, builds, and owns power plants, according to NextEra director of communications Steven Stengel. “We meet the energy needs of our customers through procuring power for them,” Mr. Stengel said in a phone interview. “We are the largest generator of wind and solar power in the world.”

When NextEra produces power via wind turbines and solar panels and feeds it into the national grid, it purchases a renewable energy credit (REC) for each megawatt (MW) of power generated. “[The RECs] represent the good environmental attributes of the energy produced, attributes like a lack of greenhouse gases produced,” Mr. Brandt said. “It has been agreed that they are the appropriate way to make claims about where your energy comes from.”

Any producer of alternative energy, large or small, can earn RECS. “If you have a small PV array on your home,” Mr. Brandt said, “it produces solar RECS. You can contract with a broker, who will sell them for you. That’s income for you, but then you can’t claim to be using renewable energy, only producing it.”

At a larger scale, Massachusetts state law requires energy suppliers to retire a certain number of RECs per year. This is the basis of the market for RECs; it creates a reliable demand for them.

Mr. Brandt explained the appeal of NextEra to CLC. “They own big REC-producing resources,” he said. “They have both production and demand under one company.”

According to Mr. Stengel, NextEra owns 19,000 MW of electricity production in 29 states; 80 percent of that is generated through wind and solar energy. They have been producing solar power since 1989. The next largest portion of their production, 14.5 percent, is derived from nuclear power. Mr. Stengel said NextEra thinks of itself as a wholesale provider; their customers are aggregators, utilities, municipalities, and cooperatives.

Unlike Con Ed Solutions, NextEra was able to promise CLC that it could reliably supply renewably sourced power to all its customers. “NextEra is purchasing RECS or assigning RECs they own, and retiring them in sufficient quantities, that it covers CLC usage,” Mr. Brandt said. This allows CLC to make the claim that 100 percent of the power used by their customers has a green source.

NextEra is producing power and purchasing RECs in other states where the energy supply exceeds the demand for it. The lower demand causes them to be cheaper; CLC’s retirement of these out-of-state RECs keeps the price per kWh down for its customers.


EIA updates bioenergy, wood heating forecasts

The U.S. Energy Information Administration has released the February edition of its Short-Term Energy Outlook, predicting the non-hydro renewables share of U.S. electricity generation will be 9 percent in 2017 and 10 percent in 2018.

Wood biomass is expected to be used to generate 110,000 MWh per day of electricity this year, increasing to 111,000 MWh per day next year. Waste biomass is expected to be used to generate 60,000 MWh per day of electricity this year, with that level maintained into 2018.

The electric power sector is expected to consume 0.216 quadrillion Btu (quad) of wood biomass in 2017, increasing to 0.223 quad in 2018. The sector is also expected to consume 0.283 quad of waste biomass this year, increasing to 0.287 next year.

The industrial sector is expected to consume 1.235 quad of wood biomass in 2017, falling to 1.23 quad in 2018. In addition, the sector is expected to consume 0.192 quad of waste biomass in both 2017 and 2018.

The commercial sector is expected to consume 0.073 quad of wood biomass this year, maintaining that level of consumption through next year. The consumption of waste biomass is also expected to be at 0.049 quad in both 2017 and 2018.

The residential sector is expected to consume 0.394 quad of wood biomass this year, increasing to 0.413 quad next year.

On a combined basis, all sectors are expected to consume 1.919 quad of wood biomass in 2017, increasing to 1.94 quad in 2018. Consumption of waste biomass is also expected to increase, from 0.524 quad this year to 0.528 quad next year.

According to the EIA, 2.48 million households are expected to use wood as a primary heating fuel during the 2016-’17 winter, up 1.3 percent when compared to the previous winter. This includes 536,000 households in the Northeast, down .09 percent; 612,000 households in the Midwest, up 1.7 percent; 601,000 households in the South, up 3.4 percent; and 731,000 households in the West, up 1 percent.

Experts Identify 8 Areas of Electricity Innovation to Watch in 2017

We have a lot to look forward to in the electricity sector this year. While many of us take a moment to reflect on the accomplishments of 2016, there are just as many of us who are thinking about the challenges ahead.

For the past five years, Rocky Mountain Institute has been convening and supporting the Electricity Innovation Lab (eLab), a unique network of leaders and change agents from across the electricity industry representing a cross-section of the key stakeholders who are shaping the transformation of our electricity system. With utilities, regulators, distributed energy resource companies, energy consumers, advocates, and academic experts collaborating together, eLab really is a laboratory: a place to test new ideas and to explore new solutions.

We surveyed those eLab members about their most exciting opportunities -- and their critical challenges -- in 2017. Eight key issues emerged.

1. Distributed energy resource (DER) valuation and rate design

Things are starting to get interesting in this space. Nevada just reinstated net metering, Arizona and California are moving to time-of-use rates, and New York is moving closer to a “value of DERs” tariff. And we still have 46 states to go! As of last count, 15 states were formally examining or resolved to examine the value of distributed generation.

Two underlying dynamics are spurring new attention on DER valuation. First is the accelerating adoption of new DERs. Electric vehicles (EVs), batteries, grid-interactive water heaters, and many other smart appliances are expanding the definition of “distributed energy resource” beyond just rooftop solar. As a result, policymakers are taking a more holistic, and generally technology-agnostic, approach to DER valuation. In the year ahead, we can expect more attention on smart home rates and electric vehicle rates, in particular.

The second thing that is changing the conversation, almost literally, is that all parties are dramatically increasing their understanding and recognition of the costs and benefits of DERs. With new resources, such as the recently published manual on DER rate design and compensation from the National Association of Regulated Utility Commissioners (NARUC), in 2017 we’re going to see forward motion on parties being able to deliberately segregate the way they calculate the value of DERs from the way they pay for them (e.g., net metering).

2. Electric vehicles as a grid asset

While electric vehicles still represent a small fraction of vehicles on the road today, research has shown that it takes relatively few EVs on one distribution feeder to have a significant effect on the overall performance of the grid. As a result, stakeholders are looking for tools and programs to leverage EVs as a grid asset rather than a liability.

At the same time, with the recently released long-range Chevrolet Bolt, the soon-to-be-released Tesla Model 3, and many more automakers debuting EVs with larger batteries and longer ranges, 2017 is going to be the year we see automakers, charging network operators, and others get serious about expanding DC fast charging and charging networks more broadly.

While these two dynamics may seem complementary on the surface, some serious complications still need resolution. To employ EVs as a grid asset, utilities require predictable charging patterns. This suggests charging at lower voltages for longer periods of time -- Level 2 charging. Automakers and charging network operators seek convenience for EV drivers, which means charging at higher voltages whenever and wherever it’s most convenient -- DC fast charging. How to best manage the impacts of charging on the grid, while creating a system that supports the broader adoption of electric vehicles, requires finding and creating solutions that work for both groups.

3. Alternative capital planning

As DER costs have declined to the record-low prices we see in the market today, utilities and regulators are exploring ways to use DERs to displace traditional infrastructure investments at a lower total system cost. Often referred to as a non-wires alternative (NWA), this concept is gaining momentum with the California Public Utilities Commission’s decision directing investor-owned utilities in California to conduct at least one and up to four pilots using DERs to displace or defer traditional grid investments.

While innovators are moving swiftly to make portfolios of DERs plug-and-play for utilities and grid operators, there are still many questions about how to plan for this, how to contract and pay for these portfolios, and then how to operate and maintain them. These portfolios often require a mix of different DER technologies in order to provide the full suite of services that utilities and grid operators seek. We are beginning to see new alliances between DER providers in order to make these projects happen, and we anticipate efforts to co-create tools and solutions to address the planning, financing, and operational issues that non-wires alternatives present.

4. Utility business models in vertically integrated states

Using portfolios of DERs to replace traditional grid infrastructure presents a fundamental challenge to the traditional cost-of-service regulation model for vertically integrated utilities -- particularly when the distributed resource alternatives are deployed by third parties and not by utilities, creating a direct conflict for the traditional utility revenue model. In states like Minnesota and Hawaii, regulators and other stakeholders are exploring changes to the traditional utility business model that can resolve this conflict.

Options range from performance-based regulation -- where the utility’s business model of investing in the grid remains much the same, but the metrics by which it is assessed and rewarded changes -- to creating entirely new revenue opportunities for utilities. The alternative revenue models that have been suggested are broad and varied, and include the utility acting as a service provider to deliver energy-efficiency upgrades and other services to customers, the utility operating as a finance provider for alternative grid investments (e.g., DERs), and the utility serving as a market platform for DERs, also described as the distribution system operator.

5. Distribution system operations and markets

As vertically integrated utility markets are looking for cost-competitive mechanisms to invest in economic DER technologies, deregulated markets face an equally complex challenge in incorporating DERs into multiparty transactions. Transforming the grid into a system that is cleaner, smarter, and more flexible means capturing and creating value from resources at the distribution edge. While it will take more than clean DERs for our system to reach the 80 percent or 100 percent renewable energy targets that an increasing number of cities, states and companies now aim for, building a system that can accommodate this level of renewable energy means seamlessly integrating the capabilities of DERs with utility-scale resources and wholesale markets.

Markets at the distribution-system level, often referred to as distribution system operators (DSOs), as opposed to the independent system operators (ISOs) that operate the wholesale markets, are increasingly being viewed as a necessary part of the grid of the future. While consensus about the need for DSOs is growing, many outstanding questions still need to be answered about who manages the DSO, where its boundaries should lie, and what kind of market transactions (e.g., real-time prices or day-ahead bidding, etc.) it should use to manage participating distributed energy devices. New York has already begun this scoping process through the Reforming the Energy Vision (REV) proceeding, and in 2017 we’ll see other states, ISOs and individual utilities begin their own explorations into and possibly demonstration projects for DSOs.

6. DER control schemes: Coordination or chaos?

As we look to create distribution-level markets, we encounter many questions about the control required between devices, system operators, and market operators. While a bevy of working groups such as the Smart Grid Interoperability Panel and the GridWise Alliance have been working to bring standards and protocols to the DER controls realm, growing interest in DSOs and momentum to use DERs as alternatives to traditional capital investments are injecting new urgency into this topic.

Engineers and economists agree that control is necessary to manage the impact of DERs on the grid. They also agree that a certain amount of control and coordination is necessary to manage DERs in a market. But uncertainty exists about when and where the need for control arises for both system operations and market operations. Do these functions require separate devices, or can they be accomplished through the right combination of software and hardware? When these questions are layered with questions about what should be market-driven coordination, as opposed to an autonomous device response, or with a customer’s decision about how to use the device and when, things really start to get interesting.

7. Customer engagement

While it’s easy to get excited about all this discussion about DSOs and non-wires alternatives, the stark reality is that customer participation in most traditional utility demand-side management (DSM) programs still remains in the single digits. Adoption of rooftop solar and EVs also remains in the single digits in most parts of the country. If we’re going to see DERs truly realize their potential to operate as a grid resource that utilities, system operators, and regulators plan for and rely on, then 2017 needs to be the year that we kick our customer engagement into high gear.

The next generation of customer engagement can start by thinking about “customers” and not “ratepayers,” experience as well as energy use, and value versus costs. We’re seeing new models emerge that leverage customer segmentation and consumer marketing analytics to drive DER adoption based on real customer needs; that increase customer trust by providing clear, easy-to-understand quote comparisons; and that cut through bureaucratic red tape to deliver a seamless customer experience.

8. DERs for low- and moderate-income customers

When thinking about the role customers can and will play in the grid of the future, it’s important that we remember our low- and moderate-income customers, those who often face the greatest risks with the fewest resources to adapt to a changing energy landscape. For years, regulators have ensured that energy costs do not become an undue financial burden to low- and moderate-income customers by providing special credits, subsidies, or rates to these customers, as well as by ensuring that utility investments are fair, justifiable and reasonable.

In 2017, with the decrease in the costs of DERs coupled with smartphone-enabled engagement pathways (including pay-by-phone, electronic billing, and prepay), utilities, regulators and others are revisiting whether they can serve these customers better with DERs than with subsidies. Doing so would simultaneously reduce costs while also improving customer metrics, including a declining energy footprint.

These eight opportunities and challenges are center stage for RMI and eLab network members.


Leia Guccione is a principal with RMI's electricity and industrial practices, where she specializes in microgrids, campus energy systems, industrial ecosystems, distributed generation and storage, and renewable energy procurement strategies. This piece was originally published at Rocky Mountain Institute's Outlet and was reprinted with permission.

UK ranked 24th out of 28 EU member states for renewable energy

The UK has one of the lowest rates of renewable energy consumption in Europe, according to new figures.

The European Union has a target of 20 per cent of energy use coming from carbon-free sources by 2020.

However there is a vast difference between the best and worst performing states.

Sweden has the highest rate with more than 54 per cent of its energy coming from renewable sources in 2015, following by Finland on just under 40 per cent and Latvia on 39 per cent.

The UK’s figure is just 8.2 per cent, putting it in 24th place out of 28 and not far ahead of last-placed Luxemburg on 5 per cent.

However the European Commission said the EU as a whole remained “well on track” to meet it 2020 target, with an average figure of 16.4 per cent in 2015.

Miguel Arias Cañete, Climate Action and Energy Commissioner, said: “Despite the current geopolitical uncertainties, Europe is forging ahead with the clean energy transition.

“There is no alternative. And the facts speak for themselves: renewable energy is now cost-competitive and sometimes cheaper than fossil fuels, employs over one million people in Europe, attracts more investments than many other sectors, and has reduced our fossil fuels imports bill by €16bn (£13.7bn).

“Now, efforts will need to be sustained as Europe works with its partners to lead the global race to a more sustainable, competitive economy.”

The figures include electricity consumption, but also the energy used for heating and transport.

More than 20 per cent of the UK's electricity now comes from renewable energy, but the country has struggled to make an impact on the greenhouse gases produced by cars and other vehicles and also to heat people's homes.

The figure for the UK's renewable energy use in 2015 means that the UK is slightly ahead of schedule if it is to meet its share of the overall EU target of 20 per cent, set at 15 per cent because of its low starting point.

But there are concerns that progress is beginning to stall.

Dr Nina Skorupska, chief executive of the Renewable Energy Association, said: "We have been saying for some time that the UK is unlikely to meet its 2020 renewable energy target overall given the current policy framework.

"While we are likely to meet and even overshoot on power, much more progress needs to be made on transport and heat.

“In heat, the Government’s recent reform of the Renewable Heat Incentive has stilted the growth of much of the biomass sector, which was the technology that was previously deploying the majority of the heat under the scheme.

“The Department for Transport should accelerate the introduction of ... renewables in the fuel mix, increasing the cap on crops in the production of sustainable biofuels.

“While the European Commission report indicates that we met our interim target in 2013/2014, the Government has introduced over a dozen negative policy changes that have significantly slowed renewable deployment since that point."

"The UK is moving to 15 per cent renewable energy from a low base and, as the report points out, along with the Netherlands, France, and Luxembourg we have the biggest gap to meet our target."

The Department for Business, Energy and Industrial Strategy said: "We are currently progressing in line with the trajectory set out in the Renewable Energy Directive, having met the Directive’s interim targets."

Here is a list of each EU country showing its renewable energy share in 2015:

Sweden 54.1%

Finland 39.5%

Latvia 39.2%

Austria 33.6%

Denmark 30.6%

Estonia 27.9%

Portugal 27.8%

Croatia 27.5%

Romania 24.7%

Lithuania 24.3%

Slovenia 21.8%

Bulgaria 18.4%

Italy 17.1%

EU average: 16,4%

Spain 15.6%

Greece 15.5%

France 14.5%

Germany 14.5%

Czech 13.6%

Slovakia 11.9%

20, Poland 11.8%

Hungary 9.4%

Cyprus 9.1%

Ireland 9%

UK 8.2%

Belgium 7,.3%

Netherlands 6%

Malta 5.3%

Luxemburg 5%

5 European EV Fast-Charging Networks Partner For Open Fast Charging Alliance

February 8th, 2017 by

Five large electric vehicle fast-charging station networks in Europe have partnered to create a new integrated alliance, allowing users to easily use the stations of any of the 5 networks while traveling, according to a new press release from the collaboration.

The networks of these 5 companies certainly don’t cover the whole of Europe, but this partnership seems as though it will represent a good improvement over the previous situation for electric vehicle (EV) owners in the countries in question.

So, what are the 5 EV charging networks in question (the founders of the Open Fast Charging Alliance)?

Not a bad starting group. Though, hopefully the partnership will be expanded to include more networks within the near future.

“Together, the alliance members own and operate more than 500 fast chargers in 6 countries. They operate their networks according to high standards. This includes providing 24/7 customer service, and ensuring maximum network uptime. The alliance is open to other networks adhering to these standards,” a press release on the matter stated.

“The alliance will focus on bilateral roaming agreements between these high quality networks by implementing open standards such as OCPI. The first implementations are planned within the year.”

We reported previously that a number of major auto manufacturers in Europe are cooperating on the development of a large EV superfast-charging network there. It’s not completely clear at this point whether the manufacturers will be actually developing the network, or if partnerships with existing networks like the five above will be the path taken. It’ll be interesting to see if the Open Fast Charging Alliance gets co-opted by that initiative, or if it remains independent.


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About the Author

's background is predominantly in geopolitics and history, but he has an obsessive interest in pretty much everything. After an early life spent in the Imperial Free City of Dortmund, James followed the river Ruhr to Cofbuokheim, where he attended the University of Astnide. And where he also briefly considered entering the coal mining business. He currently writes for a living, on a broad variety of subjects, ranging from science, to politics, to military history, to renewable energy. You can follow his work on Google+.

Infratil upbeat about US renewable energy

Wednesday 08 February 2017 11:44 AM

Infratil upbeat about US renewable energy despite Trump uncertainty

By Rebecca Howard

Feb. 8 (BusinessDesk) - Infrastructure investor Infratil is still upbeat about its investment in US renewable energy development company Longroad Energy Holdings, despite President Donald Trump's election promises to boost coal.

While Infratil said the company's progress has been overshadowed by the potential impact of Trump's promises, "the president's comments about each of coal, gas and renewables are inconsistent, making outcomes hard to anticipate."

In a market update to the New Zealand stock exchange, it noted that while there is no way of knowing how federal and state policies, the rising cost of coal mining, the falling cost of gas, and improving renewable plant economics will play out, there are also political, societal and commercial factors which make it extremely unlikely that the US will suddenly stop building renewable generation.

"There will be headwinds, but the ship is unlikely to sink," it said.

The current US situation is "hardly ideal" for Longroad's plans to develop, but Infratil said its business model is suited to dealing with uncertainty.

Infratil and the New Zealand Superannuation Fund teamed up with a local management team to invest in Longroad in October last year. At the time it said the investment gives the Kiwi team exposure to one of the largest and fastest-growing renewable markets in the world, with an experienced US management team who were previously involved in First Wind, which Infratil said was one of the most successful independent renewable energy development teams in the US over the past decade.

It said today that shareholders have jointly agreed to provide initial funding of US$100 million and Infratil's share is NZ$65 million. Since October, Longroad has announced the purchase of a portfolio of early stage solar development projects across several states, as well as the purchase of wind turbines which will be deployed as developments become available.

Infratil shares last traded up 0.4 percent at $2.875.



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New Coal Build Most Expensive Energy Option For Australia, According To BNEF


Published on February 7th, 2017 | by Joshua S Hill

February 7th, 2017 by

A report published last week by Bloomberg New Energy Finance showed that new ultra-supercritical coal would be the most expensive form of new energy supply in Australia, well above the Levelized Cost of Energy for other sources such as wind, solar, and natural gas.

Reports earlier this month revealed that Australian Prime Minister Malcolm Turnbull had moved to fund and support the development of ‘ultra-supercritical coal-fired power stations’ (new-coal) — a type of coal-fired power plant which is said to run at a much higher efficiency than traditional coal-fired power plants. However, Australia’s division of Bloomberg New Energy Finance (BNEF) published a new report to coincide with the reports, which shows that any move to build new coal of any level of efficiency is the least economically viable option available.

Specifically, Bloomberg reports that the Levelized Cost of Energy (LCoE) of new ultra-supercritical coal-fired power in Australia sits at AUD$134-$203/MWh. This ranks well above the current LCoE for new build wind(AUD$61-$118/MWh), solar (AUD$78-$140/MWh), and combined-cycle gas (AUD$74-$90/MWh).

2017 levelized cost of energy for new build technologies in Australia (AUD/MWh)

As a result, new build coal would only serve to increase electricity prices across the country, whereas a combination of wind, solar, and natural gas would only serve to drop electricity prices for all Australians.

“New coal is made particularly expensive due to the substantial carbon, reputation, trading and construction risks the technology presents to an investor,” said Leonard Quong, a Senior Associate with Bloomberg New Energy Finance in Sydney. “But even if the government were to completely de-risk coal by paying for the whole plant and guaranteeing an exemption from any future liabilities, the lowest LCOE that could be achieved is AUD 94/MWh, which is still well above wind, solar or gas.”

The authors of the report conclude that the LCoE “of new coal is high due to the substantial carbon, reputation, trading and construction risks the technology presents.” Even if the Government were to totally “de-risk coal by assuming all these risks,” the lowest the technologies’ LCoE would reach is AUD$94/MWh.

Unsurprisingly, the report also concludes that this “new coal” is far from being ‘clean.’ Already, Australia’s existing coal fleet is 0.85-1.52tCO2-e/MWh sent-out. Unfortunately, “new coal,” though less emissions intensive — with a typical emissions intensity of around 0.76tCO2e-MWh sent-out — is nevertheless double the intensity of a combined cycle gas turbine generator — between 0.37-0.46tCO2-e/MWh — and renewable energy — which is ostensibly 0.

Further, BNEF predicts that the role of inflexible, fossil-fuel based generators will decrease in the future. “The fundamental control paradigm of grids is changing from baseload-and-peak to forecast-and-balance,” Quong explains. As such, more flexible generating sources will be required, such as natural gas and wind.

“Whilst we estimate that 19.1 GW of coal capacity could reach the end of its technical life by 2040, a combination of gas and renewables is the lowest-cost option to replace this generation and maintain secure energy supply in Australia,” Quong added.

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Legislators take closer look at wind farm

By Steve Herring
Published in News on February 6, 2017 9:57 AM

State House Majority Leader John Bell of Goldsboro is among a group of 11 state legislators who have asked Homeland Security Secretary Gen. John Kelly to take another look at a soon-to-be-completed wind farm in northeastern North Carolina.

That request includes shutting the facility down should it be proven to interfere with a nearby military radar installation.

"If the Department of Defense and the military installations say this is not a threat to military training or military operations or national security, then I wish them luck and hope they move forward," Bell said.

Unlike an earlier wind farm that Bell led successful efforts to stop, the one in northeastern North Carolina poses no threat to Seymour Johnson Air Force Base or the Dare County Bombing Range base jets use for training.

There could be an issue if the new facility was to expand in certain directions, and that is a reason to keep an eye on it, he said.

Also, Bell said there is still concern about cracking the door to such facilities locating in the state.

"That is why Sen. Harry Brown and I have continued to work on the permitting process with the wind facilities to ensure it does not interfere with our military operations," he said. The 11 lawmakers, including Sen. Louis Pate of Mount Olive, who signed the letter to Kelly argue that a government-funded study concluded the facility would "seriously degrade" the radar's operational performance.

The preferred option is to shut the facility down, and the company compensated for its investment, but not for any lost future profit, lawmakers said in their letter to Kelly.

The second option is make changes to the Department of Defense agreement that allowed the project to proceed in the first place.

That option would require the developer to shut down when a 5 percent degradation of the radar signal is experienced.

"We have a new administration in Washington, and from what I understand there were a number of residents and folks up in the area who (were) concerned about the impact it would have on the radar system," Bell said. "All we did in that letter was to ask him to strongly consider looking at that one.

"One, if it would interfere with the radar system, which would be our national security, to look at shutting that wind facility down. The other option said to temporarily put a halt until we are 100 percent that it could not interfere with the radar."

Bell said he had heard off and on for a while about the project, which was approved by the Department of Defense.

"I give this example, it is one thing to talk with a farmer, but the Department of Agriculture doesn't represent every farmer," Bell said. "They don't understand the views of every single farmer. That is the same with the military and the DOD. The DOD, a lot of that is bureaucracy, and they march to a political tune.

"If there is something interfering with a military installation, Seymour Johnson, Cherry Point or even the radar system, then you actually need to have these conversations with the wing commanders and representatives there because they can give you a better boots-on-the-ground feel of exactly is going on."

That is how concerns started several years ago as to how that earlier wind facility could impact the mission of Seymour Johnson Air Force Base and the Dare County Bombing Range, he said.

"It wasn't because DOD notified Seymour Johnson," he said. "(Fourth Fighter Wing Commander) Col. (Jeannie) Leavitt spoke up and said, 'Hey, this could be detrimental to Seymour Johnson.' That is how the first wind farm was actually blocked.

"My concern is that an active military installation or an active radar system, I just want to make sure that our national security is put first and foremost. Until there is a positive 'yes, it interferes,' or 'no, it does not interfere,' I think that needs to be weighed out first before they flip the switch on the farm."

Bell said he would have no problem with the facility as long as it doesn't interfere with national security, military training or radar.

However, Bell said he continues to have problems with the tax structure and how the facility came about even though company is in compliance with how the law is written.

"I would like to go back and change the 80 percent property tax abatement and those types of things, which are why these projects are able to exist to begin with," Bell said. "I would like to go back and change some of those policies. But as of right now, those facilities are compliant with the law. I just want to make sure they are not interfering with any of our military operations."

Comments from some suggest that the letter is the result of legislators trying to protect the coal and fuel industry. That is unfounded, Bell said.

"I would say that is 100 percent false," he said. "Part of the issue we have with people's power bills actually creeping up is because the renewable energy such as wind or solar cannot actually stand on their own.

"They are subsidized. I believe they receive about an 80 percent property tax kickback. That is one way they are able to do it. So they are subsidized through the taxpayers. Then on top of that, on the wind farm side, it could put our second-largest economic impact, which is the military, at risk."

Also, power companies such as Duke are required to purchase the energy.

Bell said he is not against renewable energy.

"I just don't believe it should be subsidized by the taxpayers of North Carolina," he said. "One of the other issues that was brought up to me, which I guess I had thought about it, but really didn't think about when I visited the wind facility there in the Perquimans area, is the effect that it had on the surrounding property owners.

"They were upset because they feel like their property values are declining because there was a wind farm right next door to them. You had cost associated with running the amount of equipment and the utility and infrastructure they had to have in place to provide power to those wind turbines."

The local community does not benefit from the energy produced at the plant, he said. It is sold to another entity, Bell said.

"Of course, the community gets the benefit because it is their largest tax base," he said. "But it is also subsidized by 80 percent. So there is a lot of concern there about quality-of-life issues. There is a lot of concern from residents there about noise and the lights.

"They felt like that infringed on their property rights. It is more than just the military. There were a lot of people there who had a lot of concern from the local community."

Bell said people had asked him why he visited the facility last week if he was against wind farms.

"I said I am against the wind farm because if you put them in the wrong location it can interfere with the military," he said. "I am against the subsidizing from the taxpayers. But if I don't understand both sides of the issue, I'm really not as informed as I should be. I try to hear all sides.

"That is the reason I went and saw it. Frankly, from an architecture perspective it is very impressive. They are huge. The operation there is very impressive and unique. But I tend to like our F-15s a little more."

Bell said officials of the company building the facility assured him they do not want to interfere with the state's military missions.

They are willing to work with the state to protect the military, he said.

Bell said he attended several meetings this past week on the original House bill he helped sponsor on permitting the wind farms.

The state Military Affairs Committee was not in place when that bill became law.

"What I am trying to work on now is have our state Military Affairs Committee, which every major military facility is represented on that committee, to have the first crack at looking at proposed project to see if it impacts the military or not," Bell said.

"That way the wind companies before they make an investment, they know if it is going to be an uphill battle or if they are going to have smooth sailing. I just don't think it is fair for them or any other company to invest funds, time and energy and then get to the 11th hour like this project and realize there could be a problem that could jeopardize the project. They need to know that right up front before they spend the first dollar."

Yesterday’s Retail Tariff and a Transforming Grid

Yesterday’s retail tariff is prohibiting the optimal dispatch of co-generation resources as our grid is transforming with high levels of solar generation and potential over generation issues.

An Unintended Consequence of Policy

California has some of the most ambitious energy efficiency and renewable energy goals in the world. Investments in renewable energy and other clean energy technologies have been substantial, and California has established itself as a true leader in the fight against climate change. A clear example is the investment in solar energy. California currently has more than 8 GW of grid-connected solar and more than 5 GW of rooftop photovoltaic solar. California’s continued leadership in renewable energy has yielded climate change benefits but also created some challenges, including the potential for significant over generation—that is, more generation than can be integrated reliably into the grid.

The state has been exploring several solutions to over generation, including energy storage, facilitating exports through more integrated markets with the rest of the West, and flexible loads that can be increased in over generation conditions. While storage is a potential game-changer, the technology is still immature, and it is unclear that it can be deployed cost-effectively in the volumes necessary to really address over generation. Integrating markets across the West has raised many vexing market design, jurisdictional, and political issues. Flexible loads, on the other hand, provide a potentially low-cost and easily implementable solution to over generation.

A Potential Solution: Co-generation

One type of potentially flexible load that is often overlooked is load associated with California’s large fleet of co-generation plants. Co-generation plants generally use natural gas–fired generation to produce both power and steam for an industrial host, such as a large factory. Most host loads are subject to standby tariffs—when their electrical loads are not served by on-site co-generation facilities, they pay a retail rate of approximately $100/MWh. This rate generally exceeds prevailing wholesale prices by a wide margin. The structure of standby tariffs encourages host loads to rely on on-site generation even when it is significantly more expensive than power from the wholesale market, for example under over generation conditions.

An example is Calpine’s Los Medanos Energy Center (LMEC) in Pittsburg, Calif. The power plant provides power and steam to both the Dow Chemical Co. (Dow) and USS-POSCO Industries (UPI). The electric load of both entities combined rarely exceeds 90 MW, which is smaller than the minimum load at which LMEC can operate (190 MW). Consequently, operating LMEC entails not only serving the Dow and UPI loads but also exporting at least 100 MW to the grid.

The Tariff Problem

Given the standby tariff, even if the wholesale price is zero, and accounting for the cost of liquidating any excess generation beyond what is needed to serve their loads into the market, it is generally less expensive for Dow and UPI to rely on generation from LMEC, rather than meeting their needs from the wholesale market. Consequently, LMEC generally sends power to the grid, regardless of wholesale prices and over generation conditions.

If standby tariffs were modified to better reflect wholesale prices and market conditions, co-generation facilities such as LMEC would be encouraged to decrease generation and effectively increase load under over generation conditions. In the case of LMEC, not only might it stop sending excess power to the grid, but it could also draw from the grid to meet host loads, resulting in a swing of 190 MW and allowing excess solar generation that might otherwise be curtailed or exported to other states to be used to support California manufacturing and jobs. This large flexible load is available with essentially no additional capital investment.

More rational rate design could open additional opportunities for co-generation units to address over generation conditions above and beyond replacing the generation from co-generation facilities with wholesale market purchases when wholesale prices are low. For example, when LMEC is not operating, steam for Dow and UPI is provided from gas-fired auxiliary boilers. These auxiliary boilers could be replaced with electrical auxiliary boilers that could consume significant amounts of grid power under over generation conditions. Presumably, similar opportunities exist at other co-generation facilities meeting substantial steam requirements.

Just as the grid needs a balance of resources to meet demand throughout the day, the over generation problem will be solved in many ways. But leveraging existing infrastructure and making some basic rate changes could make a real impact in the over generation problem—not in a few years, but today. ■

Ashley Bernstein is director of origination and development at Calpine Corp.