Key issues at stake as EU electricity market reform nears finishing line

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A quick side-by-side of the positions in Parliament and Council

Reform of the European electricity market design should enter the final stages ahead of next year’s elections. Will the racers be able to cross the finish line in time? This largely depends on how far removed the positions of team Parliament, Council, and Commission are from each other.

Although political motivations are, as usual, a big factor in the fate of the file, we will not speculate about them here.

The triple whammy of scarce Russian fossil pipeline gas, low hydropower reservoirs in a summer drought, and defect-crippled French nuclear plants pushed energy prices in 2022 to uncharted territory, causing many to call for rethinking the design of European energy markets.

The European Commission eventually presented proposals in March 2023 to improve the electricity market’s functioning. These are not revolutionary but build on the 2019 ‘clean energy package’ to better protect vulnerable consumers, support non-fossil flexible resources and stabilise prices over the long term.

The clock is ticking. Ideally, negotiations between the three institutions start in September, allowing them to finish before the end of 2023. Some parliamentarians are trying to disrupt the next step of plenary adoption as a last-ditch effort to weaken the compromise, but it seems unlikely this will have a substantive impact.

Regardless, the Belgian presidency begins in January, and they effectively only have a few months before attention turns to the European and Belgian national elections.

Tracking the different positions

There are many minor and major differences between the Parliament and Council positions.

For starters, the Parliament made specific additions to the Commission’s stance on grid operator governance in support of demand-side flexibility and increased transparency. They mention locational price signals and propose a detailed framework to assess the need for flexibility in the Member States.

All of this should support the transition to a clean energy system. Parliament is also very expansive about energy sharing, adding lots of detail. This should enable owners of solar installations to distribute production among other consumers.

The Council doesn’t go into the same level of detail on grid governance, flexibility and energy sharing, but the differences don’t seem insurmountable. Parliament also suggests important additional consumer protection clauses, including a ban on disconnections.

The Council has reportedly settled on most of the issues in their position. They tend to be more cautious than Parliament, asking the Commission to analyse positive new elements like regional hubs and long-term transmission rights.

The Commission proposes to give transmission system operators the option to procure peak-shaving services directly in the market to limit the need for fossil-gas peaker plants — similar to a product National Grid offers in the UK. The Council would strictly limit this option to times when there is a price crisis to prevent such a product from interfering with the existing regular market and keep the power system in balance.

A much more controversial aspect of the reform is the Commission’s proposal to reinforce long-term contracts between private actors (defined as PPAs – power purchase agreements) or with a public entity (defined as CfD – contracts for difference).

The Commission proposes that if investments in clean energy need support, the go-to tools are ‘double-sided’ contracts for difference. Double-sided, because they have a floor, below which the public pays the project for the difference, but also a ceiling, above which the project owners have to pay the public entity back. This is considered the most cost-effective support mechanism, lowering financing costs and acting as a buffer against windfall profits.

The Council has not finalised its position on long-term contracts yet. Parliament, for its part, is lukewarm on double-sided contracts for difference as best practice for investment support. It also created a very broad — and therefore probably not very useful — list of how the costs and revenues involved with CfDs can be distributed among different consumer classes.

For instance, more focus would probably be advisable to support low-income households and those at risk of energy poverty. Distributing costs and revenue to businesses risks distorting intra-European competition. It may also shield industry from the price signals that should incentivise them to change their energy and production processes.

We understand that the design and the distribution of costs and revenues of CfDs is also what the Council is still debating. As usual, a lot of energy is being spent on treating nuclear energy in this file. More focus on smart CfDs and vulnerable consumers would be most aligned with the original intention of the reform proposals.

The biggest gap between the Council’s position and that of Parliament, along with the original Commission proposal, is on capacity mechanisms. The standing regulation considers these temporary patches to resolve security of supply concerns. They come with a risk of over-procurement, especially from large fossil power plants. This may lead to higher costs to consumers than necessary and risk locking in polluting fossil fuel power plants.

The Council seems intent on making capacity mechanisms permanent. They are even considering a derogation for coal and lignite plants to allow them to receive capacity subsidies beyond the current deadline of 2025. Considering the time and effort that went into the 2019 clean energy package capacity mechanism discussion, there is a real risk that re-opening this discussion under tight time constraints could derail the whole file.

The sprint to the finish

There is still room to finalise the new legislation before the 2024 elections — by refocusing the long-term contract sections, accepting safeguards to diminish the risk of peak shaving services distorting markets, and moving deliberations on capacity mechanisms to another file altogether.

The electricity market reform is meant to achieve better consumer protection, more and cheaper renewables and a financial return for people making the flexibility in their heat pump or electric vehicle available to the grid.

The finish line may seem elusive, but it’s close.


A version of this article originally appeared on Euractiv.

Decompression: Policy and regulatory options to manage the gas grid in a decarbonising UK

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For countries with significant proportions of gas in their heating mixes that are looking to decarbonise and reduce exposure to gas imports, there is a major question around how to deal with existing gas distribution infrastructure in an equitable way which supports consumers. Yet this question has received only limited policy focus.

This briefing considers this problem for the United Kingdom, a country which has a well-developed gas distribution network with high coverage (85% of homes) which is both privatized, fully unbundled and split into regions — and which is looking to remove direct fossil fuel use in heating by 2050 at the latest.

The UK energy regulator, Ofgem, is imminently due to embark on a price control process to regulate the gas networks from 2026 onwards and the UK government is also expected to make a decision on the potential of a role for hydrogen in heating in 2026. We hope this briefing can support policy makers and regulators working on these processes.

If decarbonisation of heating by 2050 is successful, there is a high likelihood of stranded UK gas network assets. There will also be some costs associated with the physical disconnection of buildings and decommissioning of the gas grid. Ultimately, consumers bear the responsibility for and risks of these issues. The briefing proposes three options for the British government to manage better these issues on behalf of consumers:

  1. Business-as-usual wind-down with accelerated depreciation and the potential for a decommissioning fund.
  2. Evolutionary regulation to encourage gas networks into clean heating.
  3. Nationalisation with planned wind-down.

In addition to the above, we would encourage greater consideration of the issues of decommissioning, continued capital investment and the role for local area energy planning in gas network decision making. While regulation, governance and ownership vary between countries, many of the technical and regulatory challenges in countries with major gas distribution infrastructure will be similar to the UK.

Policy and regulatory tools to assist achievement of India’s low-carbon energy goals

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India is on an ambitious path

India has embarked on aggressive plans to reform its electricity sector in keeping with its nationally determined contributions (NDC) submitted to the U.N. Framework Convention on Climate Change (UNFCCC) and with its current and future energy needs. The importance accorded by the Government of India to electricity sector plans and targets reflects the place of electricity within the Indian growth story and its role in all major economic sectors.

Several reforms to meet these nationally determined contributions are underway, including a series of proposed amendments to the Electricity Act, a recent revision of the National Electricity Policy, modifications to wholesale power markets such as an expansion of security-constrained economic dispatch (SCED), enhanced renewable portfolio obligations for states, and expansion of the transmission grid to absorb more renewables. New instruments periodically drive further reforms, such as the 10-year Indian Electricity Grid Code (IEGC) and the Report of the Group on the Development of Electricity Market in India.

Power sector decision-makers are tasked with meeting national ambitions

India has many ways to meet its national goals. Decision-makers already face important choices and will have to grapple with more in the years ahead, including such questions as:

  • How can the transition to competitive wholesale markets be achieved most efficiently and equitably?
  • How will resource adequacy be secured?
  • What can be done to improve the financial health of the distribution companies while maintaining affordable service for Indian homes and businesses?

India has robust and rigorous frameworks that capture such choices, in the form of legislative processes (Parliament approvals) and the subordinate legislative processes (rules, regulations and guidelines from the Ministry of Power [MoP], the Central Electricity Authority [CEA], the Central Electricity Regulatory Commission [CERC] and state electricity regulatory commissions). Regulatory processes are principally informed by local market conditions, as is apt. Even so, examples from other jurisdictions that have undertaken similar efforts and insights from other parts of the world where similar electricity reforms have been underway could be useful touchstones for decision-makers as they implement key changes in India.

RAP’s regulatory toolkit: A compendium of practical solutions

To that end, the Regulatory Assistance Project is launching a “living toolkit” as a reference source for electricity sector policymakers, regulators and other power industry actors in India. This toolkit is a web-based repository of policy briefs, best practices and recommendations, to be updated with new content as further topics of interest or fresh priorities emerge. This page is envisioned as a knowledge hub, to be ever expanding as the needs of India’s government, industry and civil society dictate. Where relevant, we also expect this toolkit to identify and document best practices in India, i.e., those demonstrated in the Indian power sector, as a helpful resource to other global practitioners.

The toolkit’s contents draw on our own experience in India and elsewhere in the world, to identify options that might be adaptable to India’s unique circumstances and, when feasible, the contexts of individual states. The practical solutions outlined will not be prescriptive; RAP, working across North America, Europe, China and India, understands that what works in one place might not in another. This is why we have chosen to call this resource a toolkit: The best tool for a job depends on many factors, and those applying the tools are best placed to make the final choice from an array of suitable options. Some may find certain tools more effective than others.

Which “tools” are in the toolkit?

RAP will populate this page with practical and succinct documents in which we will describe and interpret international experience on a range of topics identified through conversations with Indian public sector stakeholders. The full documents are available for download by clicking on their title.

  • Resource adequacy[click to read more]: In the fall of 2022, the CEA issued Draft Guidelines for Resource Adequacy Planning. Putting in place sensible, enforceable resource adequacy requirements is, as the CEA notes, a necessary element of a power system in which “demand is reliably met in future, in all time horizons.” Of particular import, observes the CEA, is that the share of variable renewable energy sources in the system is growing significantly and, consequently, “a fresh look at the manner in which distribution licensees contract for power” is needed. In this component of the toolkit, we look at resource adequacy planning in the eastern United States and draw insights that we think might have particular applicability in India.
  • Distributed energy resources (DERs) [click to read more]: The most recent Draft National Electricity Policy, 2021, issued by the Ministry of Power on 15 May, 2023, acknowledges the benefits of DERs and specifies requirements for the Forum of Regulators to implement a framework for DER aggregation in the country. Further, the newly issued Indian Electricity Grid Code references the utilisation of demand response and distributed generation resources in the context of demand estimation and resource adequacy. Deploying DERs at scale provides an opportunity to improve electric system efficiency, reduce consumer costs and reduce emissions. Drawing upon examples from the United States, this brief describes the benefits of DERs; the role of DER aggregators and private market players who can bring in capital and technical expertise; and the steps that regulators can take to facilitate DERs — including modifying distribution company business models, issuing business rules for DER aggregators and educating customers.
  • Energy efficiency [click to read more]: Over the past two decades, the Indian power sector has seen two legislated acts of Parliament — the Energy Conservation Act (2001) and the Electricity Act (2003) — paving the way for enhanced energy efficiency in end-use sectors. Complementing the two pieces of legislation, a slew of subordinate legislation in the form of notified regulations by state electricity regulatory commissions — primarily the Demand-side Management Regulations — inform and direct distribution licensees to identify end-use energy efficiency and load shifting opportunities as system resources. In this component of the toolkit, we identify robust legislative and regulatory support measures the end-use efficiency sector has received in India and ways to maximise the potential of implementation opportunities at the end-use level. U.S. insights on on-bill financing and energy efficiency costs are also included.

As additional topics linked to decarbonisation take centre stage in India’s electricity regulatory landscape, RAP will produce and share helpful examples from other jurisdictions worldwide that will be responsive to the concerns that are front and centre for India’s central and state decision-makers.

If you would like RAP to keep you abreast of new briefs added to the toolkit, would like to share suggestions and requests on major topics that the toolkit should cover, or have feedback on any of the publications already included in the toolkit, please contact us at [email protected].

From the Ground Up: Rural Electric Co-ops Can Lead on Decarbonization

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With the Biden-Harris administration’s recent announcement of $11 billion for rural energy providers to electrify and decarbonize, rural electric cooperatives now have the boost they need to apply their nimble capabilities and lead the energy transition.

Although energy demand from any one cooperative may be small, the impact that cooperatives have across the United States adds up. There are 832 distribution cooperatives and 63 generation and transmission cooperatives serving 42 million people across more than half of the country’s landmass.

Map of United States showing service areas of rural electric cooperatives

Rural cooperatives have made good progress reducing their dependence on fossil fuels in recent years, but significant untapped opportunity remains for cooperatives to shift their systems to create cleaner, lower-cost and more reliable systems for their members.

Kit Carson Electric Cooperative in Taos, New Mexico, provides an example of this energy shift: Taos is a small town of less than 7,000 people in a very rural area and state — New Mexico is the fifth largest state in area, but has only 2.1 million residents and is ranked 46th in population density. Instead of seeing its small size as a barrier, Taos’s rural electric cooperative embraced the opportunity to act quickly and nimbly to transition its electric system, increase reliability and resiliency, and lower bills. By building numerous solar arrays across its large service territory, and partnering with a power provider that sought clean energy sources while also allowing Kit Carson to continue to build out its own resources, the cooperative met its goal in 2022 of meeting 100 percent of its daytime electric demand with solar energy. At the same time, the cooperative led the transition to fiber optic broadband internet for town’s residents, thus opening up new opportunities for consumers, businesses, and the cooperative energy transition.

With the funding provided by the administration through the Empowering Rural America (New ERA) Program and the Powering Affordable Clean Energy (PACE) Program, rural cooperatives have the chance to do even more. As outlined in a guide for rural cooperatives that RAP wrote in partnership with Climate Cabinet and Pace Energy and Climate Center, cooperatives can use energy efficiency and demand response programs to ensure that homes are weatherized to improve indoor comfort and reduce bills. In turn, programs to use distributed energy resources can allow the cooperative to integrate more renewable resources to increase the flexibility and resiliency of the system. Gas prices will remain volatile. By contrast, electrification of heating and cooking can provide bill stability for consumers and add flexibility to the system as these resources can charge during times of high renewable energy production and lost system costs, and provide energy during periods of limited renewable supply and high system costs. Smart rate design — which will give customers price signals that are aligned with the cooperative’s costs to provide energy — can facilitate the use of these resources for the cooperative and reduce bills for consumers. Development of these programs and additional renewable resources can add job opportunities to local cooperative communities.

The administration’s grant of funds must happen quickly; the U.S. Department of Agriculture wants to commit the entire $11 billion in 2023. But the solutions are already at hand and numerous entities are offering support for cooperatives to apply for funds, including the Beneficial Electrification League, the National Rural Electric Cooperative Association (NRECA), and the Rural Power Coalition. Given the ability of cooperatives to operate nimbly and quickly, the opportunity is ripe for them to demonstrate how energy systems can become more efficient, equitable and effective.

Navigating the Workforce Bottleneck

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The workforce is the driving engine of the economy. This adage is equally true even when the engine is efficient and electric. Clean energy jobs in the fields of energy efficiency and electrification are increasing. While the U.S. workforce grew overall by 2.8% between 2020 and 2021, clean energy jobs grew 4% during the same period. However, employers are having Building Modernization Legislative Toolkit difficulty filling these jobs because declining interest in skilled trade jobs over the past decades means there are few new workers in the fields of energy efficiency and electrification. Employers expect this picture to only get worse. In 2016, the U.S. Department of Labor estimated that as many as 500,000 energy industry workers would retire within five to 10 years.

Some states recognize this looming bottleneck and are taking action to advance comprehensive legislation on climate and energy policy, while simultaneously advancing workforce goals. Electrification and improving energy efficiency in buildings to reduce energy use save consumers money and advance climate goals. These upgrades and changes to buildings require a skilled workforce. The case for job growth in the energy efficiency and electrification sectors is bright due to projected exponential growth in clean energy jobs to meet demand. Many states have existing workforce development programs and are updating or changing the focus of these programs to educate the workforce in the clean energy sector. Only a handful of states, however, including Minnesota, Maine, New York, Massachusetts, Maryland and Illinois, have enacted legislation to launch or expand workforce development programs that provide the skills necessary for a successful and diverse building modernization workforce.

Successful state legislation to advance workforce development programs that prepare workers and businesses to meet the growing demand for energy efficiency, electrification and clean energy building upgrades can:

  • Ensure a just energy transition by increasing access to the education and training necessary for energy efficiency and building decarbonization jobs among underrepresented populations and businesses through equity-focused program outreach and curricula.
  • Develop training opportunities that enable those with nontraditional educational paths to gain the skills needed to successfully participate in the workforce.
  • Create programs to reach middle and high school students that allow students to get on-the-job experience in a trade at a younger age.
  • Remove barriers in existing workforce development programs, such as requirements for certain educational attainment, and barriers to individuals who have a criminal conviction or some connection to the justice system.
  • Provide skills-based networking and transition programs for workers and communities impacted by power plant closures. Workers affected by power plant closures may possess training and certifications not easily reflected in a job market focused on traditional degrees. State programs that focus on skills-based hiring and enabling nontraditional educational paths will be more readily able to connect displaced workers with quality jobs.
  • Enable more earn-as-you-learn programs through registered apprenticeships that provide participants with on-the-job learning while they earn a paycheck.

As more states enact laws to support the energy efficiency and building electrification workforce, they can use the legislative examples in the Building Modernization Legislative Toolkit to launch task forces and plans, create clean energy jobs networks and use state and ratepayer funds to create workforce development programs. States with robust energy efficiency and building electrification workforce development programs will be well positioned to pursue over $30 million in funds from the Infrastructure Investment and Jobs Act for training and education needs, including activities that address current workforce gaps. States can leverage these funds for purposes such as pre-apprenticeships, apprenticeships and career opportunities for on-the-job training and vocational school support. The infrastructure legislation also includes millions of dollars for energy efficiency programs, which will require a qualified workforce to deliver.

Prudent Gas System Planning Can Minimize Risk

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According to the American Gas Association, from 2018 to 2020, natural gas utilities added an average of 753,619 customers and 20,724 miles of pipeline each year. This equates to adding more than one customer per minute and more than 2.4 miles of pipe per hour over that timeframe.

Building Modernization Legislative Toolkit At the same time, however, consumers are showing increased interest in alternatives to gas, such as electric heat pumps. New state and local building codes are limiting emissions from new appliances or otherwise restricting or discouraging gas equipment installations, and states are putting in place decarbonization policies that require limitations on future emissions from gas distribution utilities. These trends collectively hint at a future of a declining customer base for gas utilities, and that in turn is driving customer, advocate and policymaker concerns about stranded assets. The risk is that those customers least able to afford alternatives to gas would be forced to shoulder more of the cost to run the gas system.

From the perspective of public regulatory commissions, investments being made by gas utilities today are expected to serve customer energy needs reliably and equitably throughout the useful life of those investments. However, in many cases, current regulatory processes and tools used to evaluate gas utility investment decisions are not designed to adequately reflect these countervailing uncertainties and risks.

The planning and regulatory processes for gas are not directly coordinated with electric system planning processes, and as a result they are unable to quantify a range of potential long-term risks and benefits for customers. Specifically, regulators are lacking insights that can be gained from transparent tools that can model major uncertainties in long-term planning assumptions. These uncertainties include the degree and speed of decline in customer demand, as well as the cost and availability of alternative gas resources that are less emissions-intense than fossil gas.

Many important questions facing our energy systems can be explored within updated gas utility planning, with decision support tools and consideration of complementary regulatory tools (such as revised line extension policies and accelerated depreciation) to mitigate increasing costs to customers.

What States Are Doing

At least 10 states have recently engaged in a regulatory proceeding exploring some aspect of the gas utility system transition: California, Colorado, Connecticut, Hawaii, Massachusetts, Minnesota, New York, Nevada, Oregon and Washington. Bills addressing some aspect of gas planning or line extensions have been introduced in Nevada, Vermont, Rhode Island, Maryland, Oregon and Massachusetts. Although the specific driver behind each state’s proceedings varies, the underlying consistent theme is one of exploration of uncertainties and minimization of risks to customers.

For example, Washington passed legislation in 2021 requiring that the Washington Utilities and Transportation Commission open an investigation to evaluate pathways for electric and gas utilities to achieve their share of greenhouse gas emissions reductions. An independent third party is to conduct the study, to which stakeholders will supply data and other input. Since two of the three investor-owned gas utilities operating in the state are gas only, this process could yield best practices for coordinating the sharing of customer and planning data between gas and electric utilities. The legislature also funded the study to be managed through the public utility commission (PUC), so no additional ratepayer funds need to be collected by utilities to enable the study. Although not complete yet, the study development process is well underway.

Another example of gas planning evolution comes from Colorado, where legislators passed S.B. 21-2646, a bill that requires gas utilities to file Clean Heat Plans pursuant to PUC regulations. These plans much achieve a 4% reduction in greenhouse gas emissions from 2015 levels by 2025 and a 22% reduction by 2030, using a mix of supply-side resources, including energy efficiency, beneficial electrification, recovered methane and green hydrogen. The PUC issued a decision in December 2022, and the first utility plans will be filed in 2023.

Other gas-planning developments have focused on line extensions. Another 2021 Washington bill, H.B. 1084, precludes cross-subsidization of line extensions for residential and commercial customers. It requires new customers to cover the full cost of the new line extension rather than allowing the cost (or part of the cost) of new service to be allocated among all gas customers. This reallocation of costs has the effect of more appropriately reflecting system cost to new users. Note it does not apply to new customers on an existing gas line but only to new line extensions for a new development or service area.

An Accelerating Trend

Washington and Colorado are not alone, as states, utility commissions and utilities grapple with new scenarios that don’t fit into old processes. According to a McKinsey article, “gas utilities could face a range of scenarios, including high rates of electrification with significantly declining gas consumption, or more moderated electrification with transitions to biogas, carbon capture, or hydrogen. As gas utilities consider different decarbonization pathways, they will need to plan for different business trajectories amid the uncertainty.” Consequently, business-as-usual planning is no longer serving the gas sector well. States and commissions across the country are recognizing the need to review and update their planning approaches.

Leadership from policymakers, particularly at the legislative level, can provide needed guidance and authority to utility commissions, helping to dismantle the silos of gas and electricity planning and allowing for fuel-neutral planning in the public interest.

Practical Power Sector Reforms To Boost Reliability, Reduce Risk and Accelerate Carbon Peaking

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In 2020, the Chinese government announced its twin intent to peak carbon emissions before 2030 and achieve carbon neutrality before 2060. Since establishing these landmark objectives, often referred to as the “dual carbon targets,” China has set in place a 1+N policy framework and issued high-level directives regarding the power sector. These directives focus on “speeding up the development of the new electric power system” and “optimizing clean energy generation.” 

In 2022, RAP released an initial version of this paper, presenting recommendations for power sector reforms to support and complement the 1+N directives. The recommendations are founded on our global team’s analysis of the feasibility of various measures in the power sector in other parts of the world and on our understanding of Chinese policies and institutions, including decades of discussion and collaboration with government authorities and partners. Our recommendations offer practical ways to follow these principles and build on China’s world-leading renewable energy investment — while containing costs and accelerating progress toward the dual carbon targets. 

This updated version addresses recent policy statements which imply a perceived trade-off between 1) an optimized new electric power system based on clean energy and 2) other goals such as power sector reliability and energy security. The experience of other countries — and of various pilot reforms in China — suggests, in contrast, that power sector reforms, such as those recommended, can enhance energy security and power sector reliability while also advancing China’s efforts towards the dual carbon targets.