California is paving the way to distributed renewables and overcoming federal obstruction following approval of a law mandating that by 2020 all new residential homes must integrate solar systems appropriately sized to displace the home’s annual electricity consumption. This is expected to deliver an additional 200MW of distributed solar a year, and while storage wasn’t mandated in the legislation it was included as an efficiency compliance credit, providing builders with an attractive, cost-effective option to fully electrify homes.
While California policies appear to be driving clean energy growth, the UK’s may have stalled it. According to the Environmental Audit Committee’s Green Finance report, policy decisions from 2015 onward have dented investor confidence in clean energy, resulting in a collapse in investment and presenting a threat to the UK’s ability to meet its fourth and fifth carbon budgets. The EAC have called on ministers to “urgently plug this policy gap” and create a plan for securing the needed investment in clean technology. The report also calls for a steadily rising carbon price to disincentivise fossil based generation.
On a more positive note, a new report finds that gas will not be needed to replace the coal power plants being phased out in the UK by 2025. Almost all the renewables growth required to meet demand currently being met by coal is either contracted or under construction. And capacity is expected to be replaced through Capacity Market contracts for interconnectors, battery storage projects, demand side response and, predominantly, small peaking gas plants. Ultimately, the report argues, large gas plants will be too costly and unsuitable in a renewable future, where the main challenge will be around meeting demands during time periods of low renewable generation.
And the UK’s National Grid, in partnership with Environmental Defense Fund (EDF) and WWF, have launched an online tool forecasting electricity generation across the UK, by region, 48 hours in advance. It hopes to help users plan consumption to coincide with green power production, which could go someway to manage peak demands through information driven demand response mechanisms.
In the US the Arizona Public Service has issued a request for proposals for 400-800MW of capacity to meet summer peaks, but has limited demand side resources and renewable energy combined with storage to 100MW each. The RfP looks to violate the state’s pause on gas investments, and has left some stunned at APS’s apparent disregard for current regulation. In addition, the RfP limits the diversity of possibilities to deliver the most cost effective solutions.
A push for new gas plants is especially problematic when considered alongside research from the Oxford Martin Programme on Integrating Renewable Energy, which suggests that investing in fossil based plants may lack long term cost effectiveness. The research shows that many existing plants may need to be retired early, and according to Alexander Pfeiffer, lead author of the paper, “existing power plant stock, if operated until the end of its useful life, would emit around 300 gigatons of CO2, which exceeds the 240 gigatons we can afford if we are to meet our climate goals.” The authors urge companies to re-evaluate investment in further fossil based generation, saying that government policies should be strengthened to avoid further lock in.
Decarbonising heat is becoming increasingly important to consider alongside when considering how electricity systems will need to evolve in a renewable future, especially as one potential route involves electrification, which could add additional strain onto already stressed systems. But according to a new report published by the Institution of Mechanical Engineers, greater deployment of power to gas systems could help overcome a key barrier to renewables and accelerate the UK’s decarbonisation,. At times of excess renewable generation these systems could use clean power to create hydrogen through an electrolysis process. The hydrogen could then be used to heat homes, power transport solutions, or injected into the gas grid. The report calls upon the government and industry to collaborate to support investment in the technology and bring about demonstration projects. It recommends that the government create an industrial forum of representatives from the nuclear, renewables and gas sectors, that they promote the use of up to 20% hydrogen in the country’s gas distribution network by 2023, and that a comprehensive study comparing power-to-gas with lithium ion batteries is commissioned.
The Heat, Incumbency and Transformations (HIT) team have released the final working paper exploring the shift toward low carbon heating form the perspective of incumbency. While incumbents can exert both positive and negative impact on decarbonisation progress, little research to date has explored this issue. In their final paper, the HIT team explored policy implications for decarbonising heat. They found that there was very little evidence of the large incumbents (bar the UK gas distribution networks and heating appliance manufacturers) engaging in the idea of decarbonising heat, perhaps linked to short investment horizons. But those who were engaged were mainly exploring ideas (through lobbying and innovation) to decarbonise the gas grid using hydrogen. While this does present advantages over electrification or development of district heat networks, there are still major uncertainties around technical aspects, cost, and energy sourcing. Such a strong focus on the gas grid may also mean that other decarbonisation strategies may not get the attention they deserve. Consequently the team make 10 policy recommendations, which among other things calls for “significant support for the rapid deployment of known low carbon heat technologies” including “heat pumps, heat networks, energy efficiency.” The team also call for “greater demonstration and research into the potential decarbonisation of the gas grid to see how (and if) the gas system may fit into a low carbon future.” But, heat decarbonisation policy must acknowledge vested interests, work with incumbents to diversify, and encourage new entrants and ideas.
While studies exploring power-to-gas and other new ideas in heat decarbonisation might help other technologies get a foot into the storage market, lithium-ion battery systems are making sure to secure their hold. Tesla’s 100MW / 129MWh battery in South Australis’s grid has taken on 55% of the state’s Frequency Control Ancillary Services (FCAS), resulting in 90% reductions to grid service costs and improvements in the grid’s reliability. Although this reduces the business case for other large scale batteries, SIMEC ZEN Energy is moving ahead with development of another battery less than 100 miles from Tesla’s, and Tesla are working to develop a virtual power plant by fitting 50,000 houses with rooftop solar systems and Tesla’s Powerwall 2 batteries.
The new app for Tesla’s Powerwall 2 customers will allow them to implement time based controls under four charging strategies: backup-only, self-power (maximising self consumption from rooftop solar system), balanced time-based (using stored solar when electricity is expensive and after the sun goes down) and cost saving time-based (stores low-cost energy to power home when electricity is expensive).
And the company are also working on a virtual power plant to balance the grid in Europe. Tesla have partnered with Restore to offer balancing services to European transmission system operators.
Microgrids and peer-to-peer
Shell have recently acquired a majority share in GI Energy, a microgrid company. Alongside other energy giants such as Enel, Total, Engie and Centrica, this marks major investments in grid edge technologies.
EnSync Energy Systems have signed a 20 year power purchase agreement for a solar plus storage project in Hawaii, enabling residents at a housing complex to share power via EnSync’s True Peer-to-Peer DC-Link technology. Carports are being fitted with solar systems, which will either power the associated residential unit, charge a battery, or export excess energy to units with higher demand, to common areas, or to the grid. This adds up to a more predictable and manageable load than solar alone, adding to the stability of the grid and providing value to the local community.
Centrica have teamed up with the University of Exeter, National Grid and local distribution network operator Western Power Distribution to trial a Local Energy Market in Cornwall. They are hoping to engage 100 homes and 100 businesses in their blockchain based peer-to-peer trading platform to see how flexible demand, generation and storage assets might help relieve grid congestion. Participating homes and businesses will be given batteries, monitoring equipment, solar panels and smart meters for blockchain-based trading, and will be able to buy and sell energy directly. Ultimately the trial hopes to see whether and how blockchain technology can deliver value to the wider energy system.
And regulators in Chicago have approved plans to build a utility scale micro-grid on the South Side of Chicago, connecting with an existing microgrid on the campus of the Illinois Institute of Technology (IIT). The project aims to explore how to maximise the value of interaction between two microgrids to improve overall system resilience and reliability, creating the US’s most advanced clustered urban microgrid development to date.
As electricity networks move from one-way flows of electricity and toward a distributed platform incorporating peer-to-peer energy trading, blockchain software could help them manage an increasing number of transactions. According to David Martin, co-founder of Power Ledger, the technology could help manage increasingly complex payments. For example, a household with solar panels could be selling excess energy to their next door neighbour. In this context, Martin argues “It is only using a small subsection of the network. There is no reason in the world I should be charged transmission charges, system charges, and all of the distribution charges if I’m sending electricity 20 meters over my back fence.” This raises questions around the true financial benefits to customers, which new research at Northwestern University looks to address. But it also raises bigger questions around network charging. Allowing PV owners and their local community reduced network charges has the potential to offload higher charges onto those communities without generation assets, potentially leading to inequality and energy poverty issues. And it raises questions around the future of network charging models.
Electric vehicles and the grid
Electric vehicles certainly hold a large amount of attention in the UK’s transition to a low carbon future. Managing peak demand and matching it to available generation will be key to help balance the power network and minimise costs to EV users, and many studies have shown the opportunities that vehicle to grid (V2G) technology offers. Smart charging points can charge cars when there is surplus power in the system, feeding back energy at times of peak demand. And if coupled with machine learning technology to profile drivers’ patterns of behaviour, cars should always have sufficient power for users’ needs. While V2G presents clear benefits to the grid, it’s not so clear how users might respond, and this is something that the V2GB consortium (with partners including National Grid, Western Power Distribution, Nissan, Moixa, and Cenex) is investigating. Their study draws on extensive industry knowledge, expertise and data to develop driver-centred business models to support rapid growth of V2G technology. And although the study is just getting going, prior research suggests that with V2G technology, EVs could represent 40% of new car sales by 2030.
Such rapid growth of EVs often drives concerns over the impact that they might have on the grid – for example, not being able to boil the kettle for a cup of tea while charging an EV, or seeing a whole street shorting out if just six EVs are charging. National Grid’s worst case scenario identified that the increase in EVs could lead to a 30GW increase in peak demand by 2045. And while mainstream press created hype with headlines like “UK could need 20 more nuclear power stations if electric cars take over our roads and cause ‘massive strain’ on power network”, Graham Cooper, EV lead for the National Grid’s future scenario, explains that new technology for smart charging could see the peak drop considerably to 4-5GW. According to Tom Callow, Chargemaster’s director of strategy, “having either tariff led or physical infrastructure for forcing charging or not at certain times, we probably only need at peak probably 5GW. That’s a regular gas-fired power station and a bit” and far more manageable for the UK’s power infrastructure. In addition, with an anticipated 50% of workplaces with car parks expected to have charging infrastructure in the next 5 years (making workplace charging the biggest growth sector) the peak could be reduced even more by spreading charging out more evenly over a 24 hour period.