2021年以来，能源规划、碳达峰行动方案、新型储能指导意见等多份政策文件中都强调了虚拟电厂的发展，北京、内蒙古、浙江等多地也将虚拟电厂写入其“十四五”能源发展规划。在中国的双碳目标下，发展虚拟电厂对于促进清洁能源消纳，实现电力系统安全运行等方面，具备重要意义。
我们根据中国电力行业结构和电力市场的发展情况，对虚拟电厂这项智能电网技术在中国的发展提出一些不成熟的建议，具体包括1）把虚拟电厂纳入电力投资规划；2）把虚拟电厂纳入电网投资规划；3）确定虚拟电厂参与电力市场的模式和规则；4）确保虚拟电厂得到合理和公平的经济价值补偿。
Securing a clean, efficient and affordable power system is a complex undertaking in the best of times. The current energy crisis, however, has compounded the challenge with a cost-of-living crisis, the need to free Europe from its dependency on Russian fossil gas, and the ever-present spectre of climate change. A seemingly insurmountable task begs all available resources. One of the most powerful — and often undervalued — solutions is household demand-side flexibility.
Empowering and rewarding consumers who are able to shift how and when they use electricity is a vital power system resource. Demand-side flexibility contributes to a reliable and decarbonised power system while reducing costs, a critical outcome for low-income and disadvantaged households.
On 28 September, the Electrification Academy was pleased to welcome Sophie Yule-Bennett to unpack the insight and recommendations from RAP’s 2022 study The joy of flex: Embracing household demand-side flexibility as a power system resource for Europe. She explored:
For many years, the topic of regulation of gas distribution utilities has been far from the limelight and has not received the kind of attention that electric utility regulation attracts. But there are an increasing number of reasons to take a fresh look at gas utility regulation. Most importantly, climate goals call for phasing out greenhouse gas emissions associated with gas production and consumption, which include carbon emissions and methane leaks.
Climate goals aren’t the only reason for concern. Many utilities face looming expenses to maintain and replace aging distribution systems, and the way this is handled will have significant implications for consumers. In addition, new evidence documents the harmful health impacts of indoor air pollution associated with gas appliances.
In a recent paper, Under Pressure: Gas Utility Regulation for a Time of Transition, we analyzed a number of regulatory tools and concepts to help refresh gas utility regulation. In this post, I’ll take a brief look at one of those: the idea of non-pipeline alternatives (NPAs). Several states have already started to discuss NPA frameworks, and all states will have something to gain by taking up this topic.
Recently, my colleague Megan Anderson discussed how regulators and gas utilities can and should improve planning. Regulators play a crucial role in making sure that utilities create meaningful scenarios and conduct comprehensive assessments of options. Considering NPAs can improve longer-term planning and can also help optimize short-term investment decisions that are not captured in planning scenarios.
The NPA concept is related to the “non-wires alternatives” idea that became a hot topic in the power sector from about a decade ago. The main idea is straightforward: instead of expanding or upgrading traditional networks — electricity grids or gas pipeline systems — utilities can and should consider investing in alternatives. For gas utilities, alternatives include energy efficiency, electrification, and other measures on the customer’s premises, which are often lower cost. For example, consider a new housing development that creates potential demand for gas for home heating and cooking. It is often less expensive — especially when considering both direct costs and also the social costs of fossil-fuel emissions — to support electrification measures for the new homes instead of expanding the capacity of the natural gas distribution network.
To make NPAs work, the key is to create a regulatory framework that requires the utility to consider NPAs in a routine, transparent, and evenhanded way when creating planning scenarios and when making incremental decisions about new investments. An NPA framework should provide a level playing field for all options. It should also consider the total societal costs of different options, including costs associated with greenhouse gas emissions and health impacts. The framework should be detailed enough that the utility can use it to guide routine decision-making.
When designing a framework for NPAs, here are some important considerations:
There are a number of states considering NPA frameworks. In 2020, the New York Public Service Commission kicked off a proceeding on gas planning procedures, including a call for establishment of NPA frameworks. In February 2021, the New York commission staff issued a proposal for such a framework, including many of key points discussed above. Colorado’s new package of climate legislation specifically allows the Colorado Public Utilities to require utilities to evaluate NPAs. California’s ongoing gas utility proceeding includes a “long-term gas system planning” track that includes discussion of NPAs. Meanwhile, Oregon and other states have been piloting NPA efforts.
The next year is likely to see further growth of the NPA discussions. States with firm decarbonization goals are likely continue to move ahead with NPA framework development. But states without firm decarbonization goals can also benefit from an NPA framework to help to search out and exploit cost-saving opportunities on a routine basis. In short, it’s time to take a fresh look at gas utility regulation, and NPAs should be near the top of the list.
‘How electric vehicles endanger electricity supply’ rang the alarm in a major German newspaper in 2018. The author warned that the local electricity networks would collapse if people returned from work in the evening and all charged their cars at the same time, a fear that kept many network operators up at night.
The government that, eight years prior, had set the target of 1 million electric vehicles on the road by 2020 had to respond.
The policy makers considered various solutions: Would upgrading the network to accommodate simultaneous charging of millions of electric cars be the best solution? Or could charging be controlled in such a way that households do not all charge at once and, if so, how?
What follows is a cautionary tale, demonstrating the importance of consumer choice and long-term power system efficiency in the transition to clean energy and transport.
Faced with the challenge of integrating EVs without jeopardising power system reliability, the federal energy ministry started work with distribution system operators on a new tariff design.
After a process spanning several years, the ministry presented a new draft regulation: the dispatchable appliances law. It contained two fundamental changes to how networks are run – an approach that network operator associations had promoted as early as 2017.
First, household customers were to decide how much ‘uninterruptible’ and ‘interruptible’ network capacity they required. In other words, customers were expected to inform the network operator how much of their electricity consumption was essential and how much could be curtailed, or paused, during times of peak electricity demand.
Consumers would be forced to choose between unpredictable interruptions or much higher network fees.
The higher the uninterruptible share, the higher a household’s required contribution to electricity network costs. Consumers would be forced to choose between unpredictable interruptions or much higher network fees.
The second major change proposed concerned the ‘interruptible’ share of electricity consumption: Consumers would hand over control of their flexible appliances, such as EV chargers and heat pumps, to the network operators during pre-determined hours of the day.
The network companies would then be allowed to curtail electricity demand as needed to manage the network. Consumers who did not relinquish this control would face much higher network fees.
Grid operators welcomed this proposal, which gave them full control to curtail consumer demand for electricity.
The leading consumer associations, however, swiftly opposed the proposals due to the onus they placed on consumers to declare the interruptible portion of their network capacity, the limitations to consumer choice, and the price increases if customers did not agree to curtailment.
Moreover, if consumers gave up control over their appliances, they would not be able to reap the financial benefits of other flexibility offerings at these times, such as time-of-use energy prices or demand-response programs. These retail energy services could also help balance the national grid and better integrate renewable energy.
Innovative retailers and the car industry sided with the consumer associations. German automakers, having finally embraced the rising demand for electric cars, opposed the new regulation because they felt it would make EVs less attractive. Following an intervention by the German Association of the Automotive Industry, the government withdrew the draft law.
If the law had taken effect, Germany would have created a system that would have effectively limited further innovation.
Network operators would have informed consumers of the set blocks of time when they would have curtailed energy use and, if that did not sufficiently lower the system peak, the network companies would have had the green light to invest in more system infrastructure.
If the law had taken effect, Germany would have created a system that would have effectively limited further innovation.
More effective and less costly so-called non-wires solutions, such as time-of-use tariffs and residential demand response, would have no longer been considered and the network operator would have retained full control. This approach reflects a well-known German saying, “trust is good, control is better.”
From a system perspective, the draft law would have failed to incentivise innovation and efficient use of the existing infrastructure, measures effective at lowering costs. Indeed, the regulation would have led to exactly the opposite result – higher costs for all consumers in the long term.
If the general curtailment measures failed, network operators would simply invest in more infrastructure, leading to higher system costs.
So, without the law proposed by the ministry, will the networks collapse as a result of EVs? Field trials in Germany, which simulated a high share of EV home charging, indicate otherwise. Experience shows that actively engaging with stakeholders, especially consumers, delivers a better outcome with a higher chance of success.
There are many useful examples from other regions, including the UK and EU, that demonstrate the need for transparency when designing and implementing network regulations to manage EV charging. Germany, being the only country in the EU where the ministry sets the calculation methods for network tariffs, can learn from these processes.
In September, a new Federal Parliament will be elected, and with it a new government. Will the new lawmakers learn from the past and from other regions and favour efficient solutions for consumers? In other words, will they trust consumers to make the right choices regarding their energy use or will they stick with ‘trust is good, control is better’?
Treating consumers as partners, not controllable assets, can help the network operator grow into a cost-conscious service provider within an energy transition where the consumer can freely decide about their electricity usage and pay only for the costs directly incurred as a result.
‘Trust, not control’ will hopefully now ring beyond Germany and across Europe.
A version of this article originally appeared in Euractiv.
Not too long ago, electricity consumers across states in India used to suffer long and frequent power outages. Daily or weekly load shedding – pre-defined intervals for planned power supply cut-off – was so prevalent that people used to plan their routine around their distribution company’s (discom’s) load shedding calendar. That changed substantially a couple of years ago when the peak demand deficit reduced to a low of 0.8% from the highs of 16.6% in 2007, largely as a result of private sector investment in power generation infrastructure, (mostly coal-based capacity).
What didn’t fully change is the frequency of planned outages or interruptions that consumers have to face, even after India has been declared a power-surplus nation. So, while supply of electricity came more in line with demand as a result of new capacity installations, the requisite investments in adequate distribution infrastructure fell short. In other words, the reliability of our electric grid is still a problem in the peri-urban and rural areas. And it should be addressed, not only for the benefits a highly reliable grid can have on future economic growth, but also for the opportunity this presents in making way for the energy transition to a cleaner and more equitable system.
This is the first in a series on electric grid reliability in India. Today, we begin by looking at the reasons behind the persistence of poor reliability around the country. In the two articles that will follow in the coming weeks, we will make recommendations for new regulatory approaches to resolve reliability problems, and then analyse the overall impact of improved reliability on India’s climate action planning.
ISO New England, the regional transmission organisation in the eastern United States, defines reliability as “the electricity you need, when you need it.” Ideally, this means that end-use consumption should not be affected by either a lack of generation and procurement in the wholesale and bulk electricity system (generation and transmission) or by disruptions on the local distribution network. Of course this does not mean — from a societal cost-benefit perspective — that massive public spending on achieving 100% reliability via investments in multiple tiers of redundancy is desired.
Policy makers and regulators therefore have determined the minimum requirements for a reliable grid from two distinct, yet related, angles. One is the set of requirements to be met by the generation and transmission utilities and system operators, and the other is that to be met by the distribution utilities, together yielding a desired level of reliability for the end-consumers at a cost they—society as a whole—is willing to pay.
The National Electricity Policy, issued by India’s Ministry of Power in 2005, provides a vision for reliability. It prescribes creating adequate reserve capacity margins and a spinning reserve of at least 5% at the national level to ensure grid security, along with quality and reliability of power supply. It directs state regulators to specify standards for reliability and quality of power supply by distribution utilities. The National Electricity Policy further provides for consumer interest protections and directs state regulators to draw up a roadmap for improvement of a distribution utility’s reliability index (which is to be calculated and monitored for all cities and towns).
The Indian Electricity Grid Code Regulations, 2010, and subsequent amendments establish “rules, guidelines and standards to be followed by various persons and participants in the system to plan, develop, maintain and operate the power system in the most secure, reliable, economic and efficient manner.” These regulations apply to the bulk power supply system.
At the distribution level, discoms are guided by the Standards of Performance regulations, which are notified by state electricity regulatory commissions (SERCs). These regulations define reliability indices – such as the system average interruption frequency index, system average interruption duraction index and customer average interruption duration index – along with more procedural directions for consumer rights and protection, such as time taken by the discom for a new connection, restoration of supply on failure, time to resolve consumer complaints and the like. They also prescribe provisions on compensation to consumers in case the discom fails to meet minimum standards of performance requirements.
Most recently, the Ministry of Power issued the Electricity Right of Power Consumers Rules, 2020, with an aim to ensure a minimum standard of service for the supply of electricity to end consumers. This rule requires state electricity regulatory commissions to develop clear guidelines for discoms to follow for maintaining a 24/7 reliable distribution network. It also directs SERCs to prescribe detailed mechanisms for performance measurement of discoms and suitable compensation for consumers in case of non-performance.
While these directives and regulatory oversight have improved reliability on the bulk power system, the same is not true for the distribution network. What it means is that, although the incidence of regional, large-scale blackouts is rare, the end consumers (especially from rural and peri-urban areas) are nevertheless subject to intermittent and frequent power outages. A 2019 Global Competitiveness Report by the World Bank ranks India at 108th place out of 141 countries on the reliability of electricity supply.
What is not obvious is why, with these directives in place, the discoms do not plan and invest in appropriate measures to improve the reliability of their networks. More so, what inhibits them from deploying cost-competitive and clean distributed energy resources closer to the consumers usage point, which can help them meet their standards of performance?
One may argue that this indifference stems partially from a lack of regulatory will to penalise discoms for non-compliance with the standards. This may derive in part from a lack of public pressure: Given how consumers have internalised a significant share of the reliability costs over the years, expectations that discoms will actually improve reliability across the board for all consumers are low. A third reason, which is probably the most substantial and crucial of all, is the perennial poor financial health of the discoms limits them from making fresh investments that they likely see producing only marginal benefits. Still, they are entitled to earn a regulated return on equity on investment, which reliability-related assets would constitute. But then, with poor balance sheets and tariffs not in line with the cost of service, the inducement of earning returns on capital investments is only good in theory.
In practice, other solutions can fill this missing link. They may include driving investments in more distributed clean energy solutions, such as rooftop PV along with storage on select feeders where reliability is below average. This can be a substitute to a broader and expensive sub-distribution system strengthening. In general, a cost-effective, clean and efficient approach for improving reliability can occur via non-wires alternatives.
Non-wires alternatives are being evaluated by regulators the world over, to solve the local challenges of grid resilience, flexibility and equity. In the Indian context, local non-wires solutions can also help solve the reliability challenge. Such an approach can save ratepayers money and can also lead to a cleaner and more equitable grid, thus reducing emissions from diesel back-up generators and providing an overall impetus to the energy transition pace. These solutions can be implemented at lower costs – cost of distributed clean energy resources have dropped significantly over the last few years while the cost of traditional solutions are increasingly going up – and carry lower risks because the installation and performance of such resources is more stable and reliable than traditional grid-based solutions.
For that to happen, regulators will have to play an active role. That goes beyond setting standards and actually incentivising discoms to explore alternate solutions (which we’ll take up in the next installment in this series). Key takeaways remain: Distribution-level reliability has been poor in India due to lack of investments and the discoms’ lack of innovation in attempting new approaches. This has resulted in customers relying on high-cost and high-emissions solutions, such as self-owned diesel generators and batteries.
This is the first part of a series on reliability. We will update this post with links to the second and third blogs when they are published.
At the Midwest Energy Solutions Conference in Chicago, Dr. Carl Linvill identified a broad range of policy drivers to advance non-wires alternatives for a resilient grid.
Ofgem’s recent framework decision on improving its performance-based regulation scheme, RIIO, indicates that it may be ready to take a much-needed step toward levelling the playing field between supply-side and customer-side resources. However, it is not yet clear what the details will look like. According to Jan Rosenow of the Regulatory Assistance Project, a global group of regulatory experts, Ofgem should put a network regulation scheme in place that will maximize the role of energy efficiency, demand-side resources, and customers. The U.S. provides instructive examples of such an approach.
Gas and electricity network companies hold a monopoly position. Households or businesses cannot choose which network to use. Therefore, regulators set price controls, a ceiling on the amount companies can earn from the charges to use their networks.
These controls offer an opportunity to incentivise network companies to deliver the services consumers value and to advance the clean energy transition at least cost. In other words, price controls direct how and where the revenues collected through network charges are being spent. At more than €60 billion, electricity distribution revenues in Europe are serious money.
The U.K.’s performance-based framework RIIO (Revenue = Incentives + Innovation + Outputs) is one of the most innovative price control mechanisms in the world. In its recent RIIO-2 framework decision, Ofgem, the U.K.’s Office of Gas and Electricity Markets, placed “giving consumers a stronger voice” at the top of its list of methods for developing a reliable, safe, secure network—one that fosters a low-carbon future.
The report shares the results of the agency’s consultation on how to adjust its network price controls program as of 2021 and 2023 for gas and electricity, respectively. In the process, the regulator put the last five years of its program under the microscope.
Like many regulators the world over, Ofgem recognizes the valuable role of consumers as we face exponential change in today’s power sector and strive for decarbonisation. Facing criticism over unexpectedly high network company profits, Ofgem strives to strike a balance between consumer costs and the need to create a “smarter energy system” that keeps pace with critical changes in the energy sector. Customer-side resources and energy efficiency are powerful instruments for meeting these challenges, especially if supported by the right policies.
Stakeholders voiced a broad range of views in the public consultation, particularly on end-use energy efficiency. The Regulatory Assistance Project urged Ofgem to consider a stronger role for network companies in providing solutions that encourage lower energy use by consumers and thus reduce or defer the need for investments in energy networks.
This is important because end-use energy efficiency, such as thermal insulation of gas- and electricity-heated buildings and more energy efficient appliances, brings environmental benefits such as lower carbon emissions and lower emissions from burning fossil fuels and leads to lower costs. Network companies, including system operators, are in a unique position to evaluate the cost-effectiveness of end-use energy efficiency from a network system perspective. They have the data to identify where efficiency savings might replace or delay the need for investments in network infrastructure, thereby saving consumers money.
Con Ed estimated that the effect of its systemwide efficiency programmes reduced capital expenditures by more than $1 billion.
To mention an old example of this approach, in the 1990s, the Holyhead Powersave Project reduced peak demand by 10 percent on Holy Island in Wales through energy efficiency measures including efficient light bulbs, draught proofing, and the installation of energy-efficient electrical appliances. The electricity supplier and distributer for North Wales implemented the project in response to growing demand that would result in the need for a new substation on the island. By deferring the need for the new substation by five years, the project resulted in an avoided investment cost of an estimated 500,000 euros.
Thankfully, the regulator took a serious look at the role network companies can (and should) play in delivering end-use energy efficiency. At a high level, Ofgem committed itself to creating a level playing field for demand-side and supply-side resources. This marks an important step in the right direction.
In its consultation response, the regulator states: “Where energy efficiency, alongside other supply-side options, has the potential to defer or mitigate the need for network investment, then there should be no barriers to network companies pursuing this solution.”
However, it is not clear yet what this will mean specifically for network companies and for RIIO. Ofgem will develop more specific methodologies for RIIO-2 by December 2018 to fill this gap.
Fortunately, there is valuable experience on energy efficiency and network infrastructure from the international realm to provide guidance.
The longest track record of regulators working with network companies to integrate cost‑effective “non-wires” or “non-transmission” alternatives into planning and investment can be found in the United States, although there is a growing track record of network companies piloting similar solutions in the U.K. These alternative solutions include end-use energy efficiency, demand response, and distributed renewable resources.
Consolidated Edison (Con Ed), the electric utility serving New York City and its northern suburbs, leads the pack in this approach. In its ten-year forecast, Con Ed estimated that the effect of its systemwide efficiency programmes reduced capital expenditures by more than $1 billion. Similarly, the New England Independent System Operator has identified more than $400 million in previously planned transmission investments in New Hampshire and Vermont that are now deferred beyond its ten-year planning horizon due to energy efficiency.
In order for network companies to identify and realise the network benefits of energy efficiency and other measures on the customer side of the meter, regulators must put the proper regulatory framework in place. California’s recent introduction of a non-wires alternative requirement provides an instructive example of how such a framework might be structured. The requirement has several key elements:
This is not a new approach. California’s non-wires requirement implements the “efficient reliability standardˮ developed by the Regulatory Assistance Project for the U.S. national regulators’ association nearly twenty years ago—a concept that is still entirely relevant today.
The expected impact of investment in non-network alternatives, including energy efficiency, is difficult to gauge, as it will depend on many factors. Instructive data on the benefits and potential scope can be drawn from discrete projects, including those listed earlier, where the savings resulting from investment in efficiency and other non-wires alternatives have been calculated in comparison to network-only investment.
Following the high-level commitment in the consultation response, Ofgem now needs to follow through on ensuring that energy efficiency and customer-side resources take a leading role. The agency will increasingly need to contend with electrification of the heat and transport sectors, further increases in distributed generation such as solar and wind, and greater uptake of storage and other technologies. Clearly, energy efficiency is one of the key ingredients to manage networks and make a success of the clean energy transition.
A version of this blog originally appeared in Energy Post.
During a panel at the National Governors Association’s annual Governors’ Advisors’ Energy Policy Institute, David Littell presented on the importance of distribution and transmission planning in an era of disruptive technology.
