Map for Elevating Decarbonization in Energy Regulation

Turks & Caicos

A proposed multisector public utility regulatory framework streamlines oversight of essential services in the Turks and Caicos Islands

Context — Problem/Issue

The energy sector in the Turks and Caicos Islands is highly dependent on fossil fuels, with very high energy costs and price volatility; renewables (solar) account for only 3% of installed capacity. Nonetheless, the sector is undergoing significant transformation, aiming for a sustainable and clean energy future, with the recent introduction of the Renewable Energy and Resource Planning Bill 2023, which targets a 33% share of energy from renewable sources by 2040, through the development of solar, wind and ocean energy technologies. The bill also encourages private sector investment through incentives and financial mechanisms and considers as key priorities environmental conservation and energy resilience, with efforts to mitigate environmental impacts and enhance the infrastructure’s resilience to natural disasters. The policy framework aims to streamline the permitting process for renewable energy projects and includes a competitive tendering process for project selection; it also introduces integrated resource plans and a net-billing program to allow excess electricity generated by buildings and businesses to be sold back to the grid.

Currently, the functions of the energy regulator, the Energy and Utilities Department (EUD), are comprised in the Electricity Ordinance and include inspection and testing of power plants, dispute resolution and any others assigned by the government. Under this mandate, the EUD is currently reviewing an application from FortisTCI (the main energy utility in the country) for a proposed 6% increase in electricity rates, set to take effect (if approved) on April 1, 2024. The last rate increase application was granted in 2020.

The new Renewable Energy and Resource Planning Bill will grant the EUD with specific mandates to implement the energy transition. The EUD will be in charge of overseeing the regulation and safe operation of renewable energy systems including the safe design and operation of renewable energy systems, ensuring that companies comply with licensing requirements, and establishing standards for timely connections to the grid. Furthermore, the EUD will oversee the Net-Billing Program and the implementation of the competitive tendering process, ensuring renewable energy projects are selected based on the most cost-effective bids, aiming to enhance energy affordability, reduce reliance on fossil fuels, and ensure a diverse and secure energy supply.

Among the efforts to reform and enhance the regulatory framework, a new policy is currently being discussed to implement a Multisector Public Utility Regulatory framework for critical services like telecommunications, electricity, water and sewerage, emphasizing innovation, environmental sustainability and high-quality service delivery. The proposed unified regulatory oversight will be under a newly established Commission, streamlining and enhancing efficiency and consumer focus. The EUD will lead the consultation phase

to refine the policy with input from service providers, consumer groups and industry experts.

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Argentina

Transforming Argentina's energy sector: a shift towards renewables and regulatory evolution (Argentina)

Argentina, despite being home to some of the world’s largest reserves of shale gas and oil,  has been pivoting toward renewable energy, targeting a 20% renewable share in the power mix by 2025 and aiming for 30% by 2030. In 2022, renewables, particularly hydro and wind, made up almost 30% of power generation and 35% of installed capacity. This transition is further bolstered by Argentina’s abundant solar and wind resources and its position as a leading lithium producer, critical for the energy transition. Policy, legal and regulatory reforms are underway focusing on market opening, subsidy reduction and fostering renewable energy, marking a new era of energy policy post-December 2023’s governmental change.

Context — Problem/Issue

Argentina’s energy sector is primarily fueled by natural gas and oil, comprising 50% and 38% of the country’s total primary energy mix respectively in 2022. The nation is also recognized for its significant reserves of shale gas and shale oil, ranking as the world’s second and fourth largest respectively. Argentina aims to reach carbon neutrality by 2050 and has set an unconditional target of not exceeding 349 MtCO₂e in 2030. Despite its fossil fuel resources, Argentina is making strides toward renewable energy, aiming for renewables to reach 20% of the power mix by 2025, according to the Renewable Energy Law of 2015, and 30% by 2030, according to Plan Nacional de Transición Energética a 2030 (National Energy Transition Plan 2030), a goal that’s spurred the deployment of utility-scale renewable projects. In 2022, renewables accounted for almost 30% of Argentina’s power generation mix (mainly hydro and wind) and 35% of installed capacity. Argentina’s focus on renewable energy is also motivated by its potential in solar and wind resources, alongside its status as the fourth largest lithium producer, crucial for battery storage systems and the energy transition. Additionally, the draft of the Hydrogen Promotion Law, currently under analysis, is expected to boost the decarbonization process and Argentina’s role as a global energy supplier. The government’s efforts are supported by initiatives like executing several auctions for renewable energy projects since 2016, which have added more than 6,300 MW of installed renewable energy capacity.

Argentina has multiple regulatory entities overseeing different aspects of its energy sector, including the national regulator for the electricity market (National Electricity Regulatory Entity — Ente Nacional Regulador de la Electricidad, ENRE) who oversees electricity generation and transmission, as well as various provinces that have their own regulatory bodies for local energy distribution and regulation. The Argentinian Association of Regulatory Entities for Electricity (ADERE), integrated by ENRE and most regulators of the country’s provinces, aims to exchange experiences, foster capacity building and training, promote international cooperation and exchanges focused on energy diversification and the expansion of renewable energy sources.

Previous legislation and political tendencies in Argentina resulted in limitations of fuel marketing, outdated compensation mechanisms for electric transportation expansions, high subsidies in the electricity sector, and certain special benefits for distributed renewable energy, which caused a stagnation of the energy sector and several limitations within the role of energy regulators. Furthermore, gas remains as the main energy driver, with high penetration within the sector and elevated subsidies that have dicentivized faster development of other technologies. All of this is expected to change considerably after the new government took power in December 2023, with a presidential decree that repeals several energy laws and regulations, with the goal to restructure the energy sector and thereby reduce subsidies, push distributed energy and renewables, and open the market to competition to foster private investment. Some regulatory changes are already taking place; in February 2024, the ENRE issued some guidelines for the analysis and implementations of smart meters and distribution tariff adjustments, requested the development of the power grid, and approved new renewable energy installed capacity. Several regulatory changes are yet to come and new regulators’ roles will be adapted to the new policy.

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Azerbaijan

Azerbaijan's energy sector transformation and regulatory evolution (Azerbaijan)

Azerbaijan, a prominent crude oil and natural gas producer and exporter, is navigating a significant shift toward a more sustainable and diversified energy portfolio under the guidance of the Ministry of Energy and the Azerbaijan Energy Regulatory Agency (AERA). Ambitious plans aim to escalate renewable energy’s share to 30% by 2030, supported by the Law on the Use of Renewable Energy Resources in Electricity Production and a strategic focus on reducing the carbon footprint. AERA’s efforts to promote efficiency, transparency and sustainable development include facilitating privatization in non-strategic areas, enhancing the electricity system’s efficiency, and preparing for the electric power sector’s deregulation and market liberalization by 2028. With recent legislation paving the way for a centralized electricity market and the unbundling of electricity services, AERA’s functions and international collaborations are set to expand, underpinning Azerbaijan’s role fostering energy security, sector efficiency and environmental sustainability.

Context — Problem/Issue

Azerbaijan is a major crude oil and natural gas producer and exporter in the regional energy market. It’s energy sector, under the governance of the Ministry of Energy and the Azerbaijan Energy Regulatory Agency (AERA), is transitioning toward a more sustainable and diversified energy portfolio, emphasizing the development of renewable resources and energy efficiency. Despite its rich oil and gas heritage, the country has seen a significant increase in electricity generation (mostly by natural gas) which grew by over 50% since 2010. Renewable power generation capacity represented 16.5% in 2022 and 7% in electricity production (mainly hydro), with plans underway to further harness this potential through pilot projects and international cooperation and an aim to raise the share of renewable capacity to 30% by 2030. Nonetheless, the first solar panel was just installed in May 2023, in the country’s first major solar power plant. Azerbaijan aims to achieve a 40% reduction in emissions by 2050, compared to 1990 levels. The country is exploring its substantial renewable energy potential, including solar, wind, hydro, biomass and geothermal sources, supported by energy policy that emphasizes green energy and combating climate change. Recent legislative changes, such as the Law on the Use of Renewable Energy Resources in Electricity Production, follow this strategy to reduce the carbon footprint and ensure energy security while maintaining Azerbaijan’s role as a key energy player in the region.

AERA was established in 2017 to regulate and oversee the electricity, gas and heat supply sectors, aiming to ensure efficiency, transparency and sustainable development to ensure a diversified national production portfolio. AERA’s functions include tariff proposals, supervising market participants, participation in policy-making and implementation, certain licensing and permits, promotion of energy efficiency and conservation, offering regulatory incentives to encourage the uptake of energy-saving technologies and practices, maintaining energy supply reliability and safety, and fostering the integration of renewables into the grid, for which it has already issued several statutes.

One of AERA’s efforts to attract investment into the energy sector, aiming to diversify the national production and enhance the efficiency of the electricity system, includes the implementation of the initiative for the privatization of non-strategic production facilities, as outlined in national privatization programs. Five out of eight small hydropower plants open for privatization have successfully been transferred to private ownership and four of these privatized plants are currently being reconstructed and operated with private investments.

A major energy sector restructuring is currently being implemented in Azerbaijan, with the Law on Electric Power, published in May 2023, that aims to reform the electric power sector by gradually deregulating it and establishing a centralized electricity market, separating electricity generation, transmission, distribution and supply into independent entities to avoid monopolistic control over the sector. The law introduces a phased reform plan, with the separation of generation and the creation of a market operator by July 1, 2025, and the complete unbundling of distribution from transmission and supply, along with the full market deregulation by July 1, 2028. Initial measures to establish a regulatory framework and start the deregulation process will take effect on January 1, 2024.

AERA is in charge of developing the applicable regulatory framework to ensure a competitive liberal electricity market through the phased transition. AERA has been drafting and coordinating with relevant state bodies on projects for installation, safety and technical operation rules of electric devices, in addition to the approval of electricity network rules, among others.

In addition, AERA has been actively gathering regulatory international experience toward energy transition, network development and efficient investment planning. AERA’s international cooperation includes seminars, participation in regional training programs and bilateral cooperation meetings, covering potential regulatory frameworks for EV charging stations, R&D and innovation in energy distribution, reliability and stability of supply networks, tariff mechanisms for renewables and regulation mechanisms for electricity storage, among others. In February 2024, AERA signed a memorandum of understanding with the Georgian National Energy and Water Supply Regulatory Commission (GNERC), aiming to bolster cooperation in energy regulation and foster the development of bilateral relations through the exchange of regulatory experiences, sharing legislative developments, and organizing training on renewable energy and energy efficiency regulation. This collaboration builds on the existing partnership between AERA and GNERC within the Energy Regulators Regional Association (ERRA).

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Bahamas

URCA facilitating renewable integration (The Bahamas)

The Bahamas, a tourism-driven economy, faces unique energy challenges, primarily relying on imported oil for 99% of its energy needs. The nation aims to dramatically shift its energy landscape by 2030, targeting a 30% reduction in greenhouse gas emissions and ensuring at least 30% renewable energy in its mix. The Utilities Regulation and Competition Authority (URCA) is tasked with updating the regulatory framework to promote renewable energy integration, improve power quality and reliability, and foster stakeholder collaboration. Initiatives include frameworks for renewable energy system installation, quality standards, grid connectivity and the encouragement of private renewable energy generation.

Context — Problem/Issue

The energy sector in the Bahamas is marked by its high dependency on imported oil, with 99% of energy needs met through oil products. By 2022, renewables only accounted for 1% of installed capacity (mainly solar). The Bahamas electricity system is distributed across 16 isolated island grids. The Bahamas plans to cut its greenhouse gas emissions by 30%, achieve a minimum of 30% renewable energy in its energy mix, and ensure that electric and hybrid vehicles constitute 35% and 15% of new vehicle acquisitions, respectively, all by  2030; and aims to achieve carbon neutrality by 2050. The country’s energy transition contemplates financial incentives for household solar, a transition to solar energy on less populated islands, and the retrofit of government buildings with renewable energy systems, supported by international funding.

The Utilities Regulation and Competition Authority (URCA) regulates both the energy and electronic communications sectors in The Bahamas, overseeing electricity generation, transmission and distribution. Guided by the 2015 Electricity Act and national energy policies advocating for dynamic governance fostering consultation, participation and public-private partnerships, URCA is in charge of promoting the effective integration of renewable energy into the energy mix, revising and updating the existing regulatory framework, and fomenting stakeholder and public collaboration. Initiatives include the establishment of a new framework to improve reporting requirements for power outages, the establishment of power quality and reliability standards, the integration of battery energy storage systems in the energy sector, revision of competition guidelines, along with the potential development of integrated plans to address cross-sectoral (electricity-communications) implications and dependencies, as outlined in URCA’s 2024 annual plan (issued for consultation in December 2023). This annual plan focuses on (i) identifying and addressing efficiency gaps in major electricity suppliers, (ii) the importance of supporting the diversification of the electricity generation mix and (iii) the strengthening of the transmission and distribution network to ensure a more resilient and sustainable energy future. URCA has also been analysing the implications of their somewhat vague mandate to oversee fuel charges, aiming to obtain further clarity on the elements and externalities that should be considered on the determination of such costs.

URCA has undertaken several initiatives to support the development of customer-owned renewable generation. It has issued regulatory frameworks for Small Scale Renewable Generation (SSRG) and Renewable Energy Self Generation (RESG) to encourage owners to meet their energy demands and export surplus energy to the grid. In its final decision, URCA focuses on the cost-effectiveness of various policy options for renewable energy self-generation projects. It includes detailed analysis and responses to stakeholder comments, sets out URCA’s stance on policy design options, compensation rates and the integration of renewable energy sources, and examines several policy scenarios, comparing their cost-effectiveness from the perspectives of the regulator, utility, participants and ratepayers. Key considerations include the impact of these policies on investment returns and utility rates, and the balance between incentivizing renewable energy investment and ensuring fair rates for ratepayers, with a particular focus on methods like Net-Billing and Buy-All/Sell-All arrangements and their implications for renewable energy adoption and cost recovery. These efforts have caused a significant uptick in renewable adoption, with a 22% increase in system installations and a 26% rise in capacity since 2021, mainly due to solar photovoltaic systems. In addition, to facilitate installation and use of private renewable energy systems by larger users such as large hotels, URCA has modified the licencing requirements to allow large users to operate self-generation.

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Michigan 4

Strategic approach to evaluate decarbonization criteria for the Low Carbon Energy Infrastructure Enhancement and Development (EIED) Grant (Michigan)

The Michigan Public Service Commission is tasked with managing a grant program aimed at fostering low-carbon energy infrastructure development to support initiatives such as natural gas, combined heat and power, renewable natural gas facilities, and electrification projects, with a significant focus on reducing carbon and other GHG emissions. The evaluation of potential projects involves a comprehensive assessment of emissions savings across different energy sources for an average customer, backed by detailed calculations and assumptions, alongside an analysis of the expected health impacts on communities from these low carbon energy facilities. Despite the absence of specific carbon pricing mechanisms, the regulator recommended the use of an existing model for life cycle emission reduction calculations.

Context — Problem/Issue

The Michigan Public Service Commission (MPSC) manages the Low Carbon Energy Infrastructure Enhancement and Development (EIED) Grant, a grant program aimed at fostering low-carbon energy infrastructure development. The assessment process for potential projects includes a detailed evaluation of emission reductions from various energy sources for the average customer, supported by precise calculations and assumptions, and considers the anticipated health benefits for communities from low-carbon energy facilities. Despite lacking specific carbon pricing frameworks, the regulator advises employing a recognized model for calculating life cycle emission reductions.

The MPSC is required by Public Acts 53 and 166 of 2022 to establish a grant program aimed at enhancing and developing low-carbon energy infrastructure, the Low Carbon Energy Infrastructure Enhancement and Development (EIED) Grant. This program is designed for businesses, nonprofit organizations and local government entities (unit of government or Tribal government) to support activities such as planning, developing, designing, acquiring or constructing facilities for low-carbon energy. The legislative grant term for this program is set to conclude on September 30, 2027. The types of projects that could be funded include, but are not limited to, natural gas facilities, combined heat and power facilities, renewable natural gas facilities and electrification initiatives.

The MPSC is in charge of evaluating and issuing an award recommendation of the potential projects to receive the grant. For this, in September 2022, the MPSC published a Request for Proposals (RFP) on its website. Subsequently, the received proposals were made publicly available on the grant’s webpage, with a final submission deadline by March 14, 2023. This setup facilitated a 45-day period for public comment, followed by an additional 15 days allocated for applicants to make any necessary adjustments to their proposals.

One of the purposes of the grants is to support the reduction of carbon emissions and any other greenhouse gas (GHG) emissions reductions resulting from the project. Among the criteria to be evaluated, the MPSC had to consider:

1. A comprehensive analysis of different scopes of emissions, as categorized by the Environmental Protection Agency, comparing the emissions associated with the proposed energy supply against those from the current energy sources used by prospective customers and other available alternative energy options. This comparison encompasses:
   a. The estimated emissions savings for an average customer across various energy supply alternatives.
   b. Supporting information for the emissions calculations, detailing the models used and the assumptions made in these calculations.
2. An analysis of the anticipated community health impacts related to the proposed low-carbon energy facility.

Despite not having clear carbon pricing mechanisms to evaluate emissions savings and health impacts, the MPSC included in the cost benefit test analysis requirements (described in Attachment 3 of the RFP) a recommendation for the calculation of carbon emissions reductions, by employing a life cycle analysis using the Greenhouse Gases, Regulated Emissions, and Energy Use in Technologies (GREET) model, which was created by the Argonne National Laboratory.

Following a thorough evaluation, the MPSC approved $50M in low-carbon energy infrastructure grants for 15 projects, including grid-scale energy storage, community solar, electric vehicle infrastructure, renewable natural gas and expansion of natural gas to areas now reliant on propane (Case No. U-21293).

Who first approached the problem?

Legislation mandates the regulator to develop program guidelines and implement an application process for the grant and must first prioritize and approve grants that do all of the following: (a) are supported by a cost-benefit analysis; (b) facilitate the largest number of end-use customers achieving access to low-carbon energy facilities at the lowest total cost; (c) reduce customer energy cost burdens; and (d) support the reduction of emissions.

Potential Solution

The regulator designed and issued the request for proposals to evaluate potential projects for the award of the grant, including a recommendation to evaluate decarbonization criteria, despite not having clear carbon pricing mechanisms.

Economic and Financial Mechanisms:

Despite the absence of specific carbon pricing mechanisms, the regulator recommended the use of an existing model for life cycle emission reduction calculations for the evaluation of projects for the Low Carbon Energy Infrastructure Enhancement and Development (EIED) Grant.

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Grenada 2

Self-generator pilot program to foster renewable energy (Grenada)

The Grenada’s Public Utilities Regulatory Commission (PURC) launched a Self-Generator Program designed to foster renewable energy adoption by allowing individuals to generate their own electricity for personal use and sell excess power back to the grid. Initially granting a 15-year renewable permit, this program supports the shift from net-billing to net-metering, which benefits consumers by allowing them to utilize their green energy first before selling any surplus. It aims to install up to 1 Megawatt of renewable capacity, with specific generation limits based on residential and non-residential status. The process involves a clear application procedure, highlighting the benefits of decreased electricity bills, increased self-reliance and contribution to reducing Grenada’s carbon footprint.

Context — Problem/Issue

Climate risks in Grenada, like many small island states, are particularly acute due to its geographic and economic vulnerabilities. These risks include sea-level rise, increased intensity of tropical storms and changes in precipitation patterns. Climate change poses a significant threat to Grenada’s critical sectors, including tourism and marine-based industries, impacting the entire spectrum of the nation’s economic activities.

With an electricity sector historically reliant on imported diesel fuel, the shift towards renewable sources like solar and wind is not only a decarbonization effort but also a strategy to enhance energy security and reduce price volatility. The government of Grenada has pledged to cut its greenhouse gas emissions by 30% by 2025 from its 2010 levels, with a goal of achieving 10% (approximately 27MW) of this reduction by incorporating renewable energy into the power generation mix. Nonetheless, by 2023, renewable energy in Grenada only accounted for 5% of net generation (2.8 MW), despite having good renewable energy source potential.

The Public Utilities Regulatory Commission (PURC), serving as the electricity sector’s independent regulatory body, is tasked with promoting and ensuring the sustainable adoption and use of renewable energy sources and aims to reduce the country’s reliance on fossil fuels. It was established by the PURC Act No. 20 of 2016 and launched in July 2019. It sets and reviews tariffs for public utilities, handles consumer complaints, and oversees the procurement for generation, transmission and distribution systems, with a focus on facilitating renewable energy. Additionally, the PURC makes recommendations to the Minister on licensing for renewable energy production, emphasizing the government’s intention to significantly adopt renewable energy​.

The Electricity Supply Act of 2016, (Amendment in 2017), aims to ensure a regular, efficient, coordinated and economical supply of electricity in Grenada. It establishes a framework to accelerate the development of electricity from renewable energy sources, detailing the roles and responsibilities of the Minister and the PURC in regulating the sector. It covers the promotion of renewable energy, the integration of independent power producers and self-generators, and the competitive procurement of generation capacity. It emphasizes sustainable and efficient electricity generation and use, aiming to reduce reliance on imported fossil fuels and lower electricity costs. Additionally, the Electricity Act covers licensing requirements and specifically states (Section 14) that the issuance of licenses shall be prioritized to entities that generate electricity from renewable energy sources or to those whose electricity production significantly lowers consumer costs, reduces Grenada’s carbon footprint and lessens its reliance on imported fossil fuels.

Self Generator Pilot Program

The Electricity Supply Act (Sections 4(h), 13.3 & 25) mandates the PURC to regulate self-generation in Grenada and to determine the criteria for participation. It also establishes guidelines for self-generators to operate their systems and connect to the grid, enabling them to sell any surplus electricity to the Network Licensee (GRENLEC, the vertically integrated electricity monopoly, publicly traded on the Eastern Caribbean Securities Exchange, regulated by the PURC).

In 2021, the PURC launched a 12 month Self Generator Pilot Program (still in force), an initiative that permits individuals and businesses to produce their own electricity using renewable sources, mainly for self-use, while also allowing them to sell any surplus energy back to the grid. Permits are initially issued for a 15-year period, with the option for renewal. The program aims to achieve the installation of up to 1 MW of electrical capacity sourced from renewable energies, mainly solar photovoltaic. It contemplates a transition from net-billing, where customers sold all generated electricity at a low price, to net-metering, allowing customers to use their generated “green energy” first and sell any excess.

To benefit from the program, applicants need, among other technical requirements, a two-register meter configuration. GRENLEC is in charge of the installation and maintenance of the meters. Additionally, an interconnection agreement will be required between GRENLEC and the self-generator, who will be in charge of the maintenance of the generating facility.

Self-generators are granted non-discriminatory access to the grid managed by GRENLEC. It retains, however, the right to disconnect a customer’s generation unit from the electricity network due to safety concerns, contract violations or debts to GRENLEC.

This program contemplates generation limits per type of permit holders:

• Residential: can generate 1.2 times their current average annual kWh consumption
• Non-Residential: limited to generating 0.6 times their current average annual kWh consumption

The intended benefits of the program include decreased electricity bills, payment for surplus energy sold to the grid, increased self-reliance with storage and contribution to reducing Grenada’s carbon footprint.

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Michigan 3

Responsibly sourced gas program limited by lack of decarbonization objective (Michigan)

The lack of an explicit decarbonization objective or carbon price meant it was not possible for the Michigan regulator, Michigan Public Service Commission (MPSC), to support to support incurring extra expenses for potential environmental advantages for responsibly sourced gas program.

Context — Problem/Issue

The legislation (Public Act 304 of 1982) does not justify additional costs attributed to potential environmental benefits; hence the regulator, Michigan Public Service Commission (MPSC) is hindered to approve the request to recover premium costs for responsibly sourced gas, without clear justification of users’ benefits.

Case U-21064

In December 2021, pursuant to Public Act 304 of 1982, a gas utility, DTE Gas Company, requested the MPSC for approval of a gas cost recovery plan and authorization of gas cost recovery factors for the 12-month period April 2022-March 2023, which was later amended in May 2022 with revised supporting testimony and exhibits.

The company claimed that it was involved in industry groups and collaboratives to focus on the reduction of methane emissions and included in its gas cost recovery plan premiums above the base cost of gas purchases for responsibly sourced gas (RSG) as part of its net-zero commitment on gas supply strategy, as well as additional costs of certification and auditing that would be required for it to purchase such RSG. DTE Gas Company aimed to recover an underlying commodity cost and the cost of a third-party certification, a  premium of $36,808 on a gas cost of $7.8 million for RSG.

On July 2023, an Administrative Law Judge issued a Proposal for Decision by which it contested the company’s purchase of responsibly sourced gas at a premium above the base cost of gas, among other things. It included a warning to DTE Gas indicating that the $36,808 premium paid for RSG may not be recoverable in future cost reconciliation cases, stating that the company had not made a compelling and convincing case that purchasing RSG was in the best interest of customers or that it would make a significant difference in reducing greenhouse gas emissions. The basis for this position is rooted in the interpretation of Act 304, since it does not consider environmental attributes when evaluating whether costs are reasonable and prudent regarding gas supply choices. Consequently, Act 304 does not justify additional costs attributed to potential environmental benefits in evaluating the reasonableness and prudence of such expenditures. Furthermore, since the RSG requires a premium for certification yet does not offer increased reliability over non-RSG certified gas, it should not be considered a reasonable or prudent supply option under the current language of Act 304. Act 304 also mandates utilities to undertake all necessary legal and regulatory measures to reduce the cost of purchased gas. Given that RSG performs identically to gas acquired without the ‘responsibly sourced’ label, it fails to satisfy the criteria for being deemed reasonable and prudent.

In August 2023, DTE Gas Company requested the MPSC to reject the judge’s recommendation for a warning regarding the rejection of approval of the premium amount of $36,808 paid for responsibly sourced gas (RSG).

Finally, in October 2023, the MPSC ordered the issuance of a warning to DTE Gas Company that the premium of $36,808 paid for responsibly sourced gas may not be recoverable in future reconciliation cases without first providing evidence of how responsibly sourced gas delivers a benefit to customers. For this decision, the MPSC considered that it was not clear, from the testimonies received during hearings, how RSG would lower the composition of methane in the gas.

Who first approached the problem?

A gas utility applied to recover premium costs for responsibly sourced gas, claiming the reduction of methane emissions but failed to prove the final benefits to consumers. The regulator did not have any decarbonization authority to factor in any environmental considerations, but in its decision, it set out the path on how future utilities could better frame their arguments, following a previous case (Case No. U-20940).

Potential Solution

The MPSC acknowledged the potential benefits of RSG but concurred with the Administrative Law Judge and the Attorney General, that a Section 7 warning regarding the RSG premium payment was necessary. It stated that its decision was not an outright dismissal of RSG’s value but reflects the current lack of record support for its procurement, leaving room for DTE Gas Company to seek expense recovery in future rate cases or provide further justification during cost reconciliation. The MPSC’s stance is not a blanket statement against RSG procurement’s prudence. Instead, DTE Gas may still pursue expense recovery in future filings, provided it can present more substantial evidence of RSG’s benefits to customers, akin to the Commission’s expectations in a previous order (Case No. U-20940) concerning the recovery of research and development costs aimed at reducing carbon intensity. In that case, the Commission expected DTE Gas to demonstrate a clear link between costs and benefits to customers, a standard that applies to RSG premium recovery efforts. The absence of sufficient evidence in the current case regarding how RSG benefits DTE Gas’s customers, such as potential cost savings from reduced supply chain emissions, does not preclude the possibility of such benefits being recognized and supported in future submissions.

Policy Development and Implementation

Positive changes toward the implementation of decarbonization in the regulator’s decision-making are coming into force. In 2022 Michigan issued the MI Healthy Climate Plan that recommends to enhance the MPSC approach to include an environmental justice and health impact analysis within the Integrated Resource Planning (IRP) process, ensuring a comprehensive evaluation of community impacts stemming from utility investment choices. The 2023 Clean Energy Legislation marks a significant shift, granting the MPSC the unprecedented ability to factor in climate, affordability and environmental justice considerations into utility integrated resource plans. It also requires the MPSC to perform an environmental justice analysis for the location of any new or upgraded natural gas facilities. Similarly, it requires the utilities to conduct analogous assessments for the retirement of fossil fuel peaker plants, ensuring that community impacts are considered alongside economic factors.

To meet the goals of the MI Healthy Climate Plan, a package of bills was passed in 2023 that, among others, centers environmental justice and equity in clean energy programs. The MPSC now has the authority to incorporate considerations of climate, environmental justice (EJ) and non-discrimination into their evaluations of long-term utility plans. This expansion broadens their capabilities to ensure that the implementation of clean energy laws is done equitably. The recent legislation enhances public involvement, particularly emphasizing the participation of residential ratepayers, EJ communities and those experiencing significant energy burdens in the decision-making process. The laws further mandate the MPSC to perform environmental justice reviews for all new or improved natural gas facilities and for the decommissioning of fossil fuel plants. These laws also extend the responsibilities of the Department of Environment, Great Lakes, and Energy (EGLE) to offer advisory opinions on long-term utility plans, now requiring assessments of the plans’ potential environmental impacts, their alignment with the state’s climate objectives, and their effects on environmental justice and public health.

Economic and Financial Mechanisms:

The regulator issued a warning that a premium the company paid for third-party certified responsibly sourced gas may not be recoverable in future reconciliation cases without clearly demonstrating benefits to customers, as previously suggested in another case.

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British Columbia

BCUC's role in steering British Columbia towards a sustainable energy landscape (British Columbia)

The British Columbia Utilities Commission (BCUC) of British Columbia, Canada has taken significant strides toward fostering clean energy within the province, mandating collaborative strategic planning among major energy utilities. In a notable initiative from 2022, BCUC launched a process to explore the long-term implications of evolving energy scenarios on BC’s electric and gas sectors to align with greenhouse gas reduction targets, especially in emerging sectors like hydrogen and carbon capture. BCUC has also addressed the marketing of biomethane by proposing a shift to new pricing strategies to stimulate renewable natural gas demand and ensure financial viability. BCUC’s commitment to environmental objectives, however, has also led to scrutiny over proposals lacking clear low-carbon transition plans, as seen in the rejection of an expansion request for a district heating system which lacked just such a clear plan for transitioning to a low-carbon alternative.

Context — Problem/Issue

British Columbia’s energy sector relies significantly on renewable sources, with hydroelectric power leading in electricity generation. It has set goals to reduce its greenhouse gas emissions from 2007 levels by 16% by 2025, 40% by 2030, 60% by 2040, and 80% by 2050, for which the province is exploring emerging renewables like wind, solar, biomass and geothermal energy. Furthermore, British Columbia is presently engaged in consultations for a “climate-aligned energy framework,” expected to serve as the initial step toward developing a comprehensive energy strategy. Additionally, British Columbia’s significant natural gas reserves, especially in the Northeast, play a crucial role in meeting local demand and positioning the province as a potential leader in the liquified natural gas export market, taking advantage of its strategic Pacific coast location to target Asian markets.

The British Columbia Utilities Commission (BCUC) serves as the independent regulator for the province’s energy sector covering utilities, common carrier pipeline operations and rates, and the reliability of the electricity transmission grid; it is tasked with ensuring safe, reliable and equitable energy services at reasonable rates.

BCUC Pushing for joint strategic planning from energy utilities

BCUC has been proactively taking initiatives toward clean energy. In 2022, BCUC issued a process to explore energy scenarios and the resulting interdependent long-term implications on the province’s primary electric and gas utilities. It requested that BC Hydro (a public monopoly electric utility) and FortisBC Energy Inc. (FEI) (the largest distributor of natural gas) exchange and submit data for load forecast results based on each other’s scenarios from their resource plans, along with detailed commentary on the potential effects on supply resources, rate changes and greenhouse gas emissions associated with each scenario, with a goal to develop a consistent planning approach across fuels. Part of the information provided to BCUC included a summary of assumptions regarding hydrogen supply volumes; both utilities’ scenarios confirm an anticipated increase in electricity demand from hydrogen production, the assumptions for modelling the increased electricity demand are due to customers transitioning from gas to electricity. This resulted in the recent BCUC’s approval in March 2024 of BC Hydro’s updated integrated resource plan, for the next 20 years, that addresses increasing electricity demand through energy efficiency programs and energy purchases from independent producers, prioritizing greenhouse gas emissions reduction, maintaining low electricity rates, minimizing environmental impacts, supporting Indigenous reconciliation and boosting the economy. For this, BCUC agreed that BC Hydro would need to acquire about 3,000 GWh of clean electricity from new facilities by 2029 and an additional 700 GWh from existing facilities before 2029, increasing its energy resources by over 5%. The decision regarding FEI’s long term gas resource plan approval is still pending.

Fostering renewable natural gas with premium incentives for cost recovery

FEI requested the BCUC to be able to market biomethane as a premium gas product, given that it is more expensive than conventional natural gas. FEI charges a biomethane rate, intended to fully recover its supply and program costs, to those customers who purchase it on a voluntary basis. FEI suggested switching from the cost-based Biomethane Energy Recovery Charge (BERC) rate to two new rates: a Short-Term and a Long-Term BERC Rates, intended to increase renewable natural gas (RNG) demand, raise revenues and lessen the financial burden on non-bypass ratepayers. FEI’s strategy was to sell most or all of the available RNG supply at a lower price, rather than selling a smaller volume at a higher price. The BCUC approved in 2016 the short term rate for biomethane based on a premium above conventional gas cost, along with the long term rate that comprised a discount to the short term one to reflect potential benefits to FEI (including long-term revenue certainty, predictable load and reduced marketing efforts). By 2021, FEI reported that the BERC rate successfully led to higher sales volumes and increased revenues but, after concerns over the risk of a significant discrepancy arising between the short-term and long-term rates established in long-term contracts threatening the chance to maximize revenues, the BCUC instructed FEI to update the long-term rates as needed.

BCUC’s Scrutiny of District Heating Proposals Amid Carbon Reduction Goals

In 2015, the BCUC reviewed a proposal by Creative Energy (a private district heating company) for the expansion of a district heating system to Northeast False Creek and Chinatown in Vancouver. The issue was that district heating system relied on natural gas as the heating fuel, meaning that the project would not lead to meaningful greenhouse gas emissions reductions. The BCUC  turned down the Chinatown extension due to continued reliance of the district heating system on fossil fuels and the absence of a definitive plan for transitioning to a low-carbon alternative.

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France 4

Gas Infrastructure considered crucial to achieve decarbonization by 2050 (France)

The French Energy Regulator (Commission de Régulation de l’Énergie, CRE) is pivotal in transitioning France toward a sustainable gas infrastructure, as the country is aiming for carbon neutrality by 2050. It enforces the Energy Code to support biogas injection, manages the adaptation of networks for renewable gas and explores future scenarios for gas infrastructure, concluding that most of the existing gas infrastructure will be needed until 2050. With its approval of 21 zoning projects in February 2024, the CRE establishes a framework for integrating renewable gases, ensuring the network’s evolution aligns with France’s energy sovereignty and climate goals.

Context — Problem/Issue

France’s gas infrastructure is a critical component of its energy system, playing a significant role in the country’s energy supply, heating and industrial processes. The infrastructure includes a comprehensive network of pipelines for transportation, storage facilities to manage supply and demand fluctuations and LNG (Liquefied Natural Gas) terminals for imports. French gas demand, heavily influenced by weather due to its primary use in heating, exhibits significant variability, with daily consumption potentially quadrupling from August to February. As France moves towards its 2050 carbon neutrality goal, the gas infrastructure is undergoing significant transformations to accommodate the shift from fossil-based natural gas to renewable gases, such as biogas and hydrogen (France 2).

France’s Energy Code considers the right to inject into the gas networks for biogas producers. The reinforcement of natural gas transportation and distribution networks required to facilitate biogas injection is included in the Decree No. 2019-665 of June 28, 2019, specifying the technical, operational and regulatory measures to be implemented by the French Energy Regulatory Commission (Commission de Régulation de l’Énergie, CRE) to ensure that the gas networks can safely and efficiently handle the biogas injection.

The CRE published, in April 2023, a report on the future of gas infrastructures within the framework of achieving carbon neutrality by 2050, aiming to shed light on the impact of various gas production and consumption scenarios for 2030 and 2050 on gas infrastructures. CRE explored three scenarios, with gas consumption volumes projected between 165 and 320 TWh by 2050. These scenarios emphasize a balanced national production and consumption of green gas, eliminating the use of fossil gas by 2050 while ensuring France’s energy sovereignty. The CRE envisions a future with reduced carbon emissions, in which gas infrastructures like transmission and distribution networks will play a crucial role. These elements are considered essential to achieving a successful energy transition and securing France’s energy independence by mid-century.

The report highlights two main effects on gas infrastructure: the adaptation of networks to accommodate distributed green gas production and the changing needs for gas distribution to consumers. CRE presents nine key findings to guide future considerations on the role of gas in France’s energy mix and strategies for infrastructure development, including the necessity of substantial investments in network adaptation, the continued importance of the current transport network despite reduced consumption and the potential for optimizing the gas distribution network with a focus on green gas production. Additionally, the report discusses the interplay between different energy networks, the ongoing necessity of large methane terminals for supply security and the potential role of hydrogen in the energy mix without overestimating its impact on current gas infrastructure. CRE plans to continue its work to assess the economic consequences of different infrastructure configurations for operators and consumers and to adjust the regulatory framework accordingly to reflect the potential dynamics explored in its report.

Furthermore, in February 2024, the CRE issued its approval of connection zones for integrating renewable or low-carbon gases into gas networks. This decision establishes a legal and operational framework for biogas producers, defining how zones are determined and how local stakeholders are involved. The CRE validated 21 zoning projects, aiming to streamline the injection of renewable gases and ensure that technical and economic considerations are addressed for investment and connection efforts.

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Australia and Western Aus

Australian energy regulators pushing the extension of gas regulations to embrace hydrogen and renewable gases (Australia & Western Aus)

While hydrogen as an energy carrier is still at the nascent stage, some regulators have been advising governments on how to address the implications of regulating the development of hydrogen infrastructure. In Australia, taking into account advice from the Australian Energy Market Commission (AEMC), Australian Energy Regulator (AER) and the Western Australia Economic Regulation Authority, Australian energy ministers agreed to extend the national natural gas regulatory framework to include hydrogen and renewable gases. Supporting legislation at the state level is now being passed.

Context — Problem/Issue

Australia is navigating a significant transition in its energy system from a centralized, fossil fuel-based system to one which is decentralized, renewable energy-based and aiming for net-zero emissions by 2050. Hydrogen is expected to play a big role in this transition that will need adaptations in both electricity and gas transmission and distribution networks, a process overseen by the Australian Energy Regulator (AER). In 2019, the government of Australia was one of the first countries to launch a National Hydrogen Strategy (reviewed in 2023 by public consultation) that outlines its vision to build a clean, innovative, safe and competitive hydrogen industry, designed to position Australia as a major global player in hydrogen production and export by 2030. It emphasizes leveraging the country’s abundant renewable energy resources to produce green hydrogen and its available pipeline, the longest in the world. It recognizes hydrogen’s significant role in achieving net-zero targets through its application in industry, transport and energy sectors.

The regulatory framework for hydrogen in Australia is evolving quickly, with significant steps being taken to ensure that low-carbon hydrogen plays a key role in the country’s energy transition and export potential. In January 2021, the Government of Western Australia issued the Western Australian Renewable Hydrogen Strategy outlining its intent to become a key player in the renewable hydrogen industry, focusing on leveraging the state’s strong renewable energy resources, existing infrastructure and proximity to Asian markets. It aims to develop the industry through export, remote applications, blending hydrogen into natural gas networks and transport. The strategy includes government support measures such as funding, resourcing, regulatory reforms and establishing partnerships to facilitate industry growth and transition toward a low-carbon future. The Western Australia Economic Regulation Authority (ERAWA) has been involved in assessing the implications of hydrogen development in the region, which is significant given its potential as a hydrogen production hub.

In August 2021, Australian Energy Ministers decided that the national gas legal and regulatory framework needed to be updated to include hydrogen and renewable gases, a task assigned to the Australian Energy Market Commission (AEMC), in charge of providing comprehensive advice to the government regarding potential legal changes required.

In November 2021, the Australian Energy Regulator (AER) published a paper that discussed potential gas pipelines regulatory changes. Its preliminary view favored accelerated depreciation to equitably distribute costs between current and future gas customers, adjusting for forecast changes in demand to allow flexibility and equitable price impacts and aiming to support investment decisions and consumer protection.

In October 2022, Energy Ministers agreed to modifications to the national natural gas legal and regulatory framework to encompass hydrogen and renewable gases, and issued a policy paper outlining the final reforms and several case studies regarding their application across different types of renewable gas projects. A month later, in November 2022, AEMC issued a report analyzing the potential of extending the regulatory frameworks to hydrogen and renewable gases. Key rule changes included: (i) enabling access to pipelines to facilitate efficient connections and investments in the pipeline infrastructure for renewable gas suppliers, including the enhancement of market transparency and providing clarity on the regulatory treatment of pipelines transitioning to transport renewable gases; (ii) supporting competition, including improvements to the ring fencing framework to enhance transparency and consistency; (iii) extending market transparency mechanisms to include other covered gases and blend processing facilities in transparency mechanisms, facilitating informed and efficient decision-making and promoting efficient operation of markets for covered gases; (iv) streamlining operational arrangements for the short term trading market to accommodate the injection of renewable gases, reduce regulatory burdens and simplify arrangements for new and existing participants, supporting efficient infrastructure use; (v) adapting the Victorian Declared Wholesale Gas Market, recommending new registration categories for blending facilities and other changes to support the decarbonization of the Victorian gas market and the efficient use of pipelines; (vi) allowing new services and commodities in retail gas markets, with the expansion of retail market participant categories to include facilities, like blending facilities, to encourage the delivery of new services or commodities, supporting emission reduction efforts; (vii) informing consumers about gas type changes by requiring distributors to notify customers of any change in gas type and publish relevant information on their websites, enhancing transparency and consumer confidence; and (viii) retaining regulatory sandbox rules and extending them to renewable gases, for enabling trial projects and providing a consistent framework for testing innovative ideas in the gas market. These changes are designed to ensure efficient market operation, encourage innovation, maintain consumer protections and support the energy market’s decarbonization.

In September 2023 the Statutes Amendment (National Energy Laws) (Other Gases) Bill 2023 was presented to the South Australian parliament and was approved in November 2023. The subsequent legal and regulatory changes are expected to be implemented by the end of 2023 or early 2024.

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Italy 2

ARERA balancing energy investments and sustainability with ROSS and TOTEX approach (Italy)

In response to the transition in energy systems and the need for significant investment in updating transmission and distribution networks, Italy’s Regulatory Authority for Energy, Networks and Environment (Autorità di Regolazione per Energia Reti e Ambiente, ARERA)  has shifted from a regulated asset based (RAB) approach, which potentially led to overinvestment and a CAPEX bias, toward a more balanced regulatory framework known as “regulation based on expenditure and service objectives” (ROSS). ROSS aims to align expenditure and output targets to foster a more efficient allocation of resources, addressing both operational (OPEX) and capital (CAPEX) expenditures. The approach is executed in two phases: initially establishing a cross-sector ‘ROSS-base’ framework and subsequently adopting a ‘forward-looking’ method for refining cost and quality targets. ARERA’s integration of TOTEX-based regulation is designed to ensure a sustainable, cost-effective and secure energy future by promoting realistic planning, performance incentives and innovative solutions across electricity and gas sectors.

Context — Problem/Issue

Italy’s Regulatory Authority for Energy, Networks and Environment (Autorità di Regolazione per Energia Reti e Ambiente, ARERA) oversees the electricity, natural gas, water services, district heating and waste management sectors, guided by national and EU policies. Its role includes providing advisory and reporting services to Parliament and the government and is committed to fostering competition and efficiency across public utilities, establishing clear, fair tariff systems, and balancing service providers’ financial goals with societal, environmental and efficient resource use objectives. ARERA engages in comprehensive stakeholder consultations to inform its decisions and is funded by contributions from the revenues of the entities it regulates.

The ongoing transition in energy systems requires significant investment to recondition both transmission and distribution networks while also balancing cost-effectiveness and environmental sustainability. Italy had implemented a regulated asset based (RAB) approach to provide incentives for infrastructure development that may lead to overinvestment or investments not sufficiently aligned with system utility. This caused a CAPEX bias issue (the preference for capital-intensive solutions even when operational alternatives might offer system-wide cost savings) in the energy sector. To address this bias, in 2021, ARERA introduced a new approach for setting electricity and gas infrastructure services’ revenues with Decision 271/2021/R/com, which incorporated expenditure and output targets through a “regulation based on expenditure and service objectives” (regolazione per obiettivi di spesa e di servizio – ROSS) approach. This aimed to balance operational (OPEX) and capital (CAPEX) expenditures by fostering TOTEX efficiency incentives, determining capitalisation rates, and monitoring returns on the regulatory asset base against set benchmarks. This would unfold in two phases: the first one to establish a cross-sector ‘ROSS-base’ framework to streamline regulatory proceedings and the second a ‘forward-looking’ method to refine cost and quality targets. TOTEX-based regulation has seen successful implementations in other jurisdictions like the UK and Portugal. By integrating TOTEX-based regulation ARERA seeks to promote a more balanced and efficient allocation of resources that encompass realistic planning, performance incentives and innovative solutions across electricity and gas sectors. ARERA has also given specific consideration to gas storage and distribution, ensuring a sustainable, cost-effective and secure energy future, by leveraging integrated planning and regulatory mechanisms to support Italy’s energy transition.

Furthermore, ARERA has issued guidelines to determine historical costs within the ROSS approach (held to consultation), regulation criteria to implement the transition toward a ROSS methodology and, in November 2023, issued the application criteria of the ROSS-base regulation for electrical transmission, distribution and measurement and gas transport services.

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New Mexico 2

Regulator pushing for increased system flexibility through encouraging integration into regional electricity markets (New Mexico)

New Mexico’s energy landscape is undergoing a significant transformation from a traditional reliance on coal to a sustainable future powered predominantly by renewable energy sources, in line with the state’s ambitious renewable energy goals set by the Energy Transition Act of 2019. The New Mexico Public Regulation Commission (NMPRC) is pivotal in overseeing this transition, focusing on integrating renewable energy sources efficiently, enhancing grid reliability and promoting economic benefits through cost savings. This might involve active participation in regional markets, which facilitate broader energy distribution and lower costs. The NMPRC’s efforts include developing regulatory frameworks, participating in stakeholder discussions and exploring the feasibility of joining or forming Regional Transmission Organizations (RTOs) or Independent System Operators (ISOs) to improve grid reliability, optimize economic dispatch and support emissions reduction goals.

Context — Problem/Issue

New Mexico’s energy landscape is in a pivotal transition, moving from its longstanding reliance on coal toward a greener, more sustainable future. Renewable energy is currently emerging as the predominant source of electricity in New Mexico; mainly wind, which in 2022 surpassed, for the first time, coal power generation. This shift aligns with New Mexico’s ambitious goals under the Energy Transition Act of 2019, which aims for 50% renewable energy by 2030 and 100% carbon-free electricity by 2045 for investor-owned utilities, extending to 2050 for cooperatives. The New Mexico Public Regulation Commission (NMPRC) is in charge of overseeing this transition.

The State of New Mexico, through utilities regulated by the NMPRC, has already shown interest in participating in regional markets, like the Western Energy Imbalance Market (EIM) that is a real-time wholesale electricity market designed to more efficiently dispatch power generation across the West, helping to integrate renewable energy over a broader region and potentially lowering costs. This is particularly important for states like New Mexico, which are rich in solar and wind resources that can be harnessed not only for local consumption but also to supply power to neighboring states.

The NMPRC has been actively developing regulatory efforts and participating in discussions with different stakeholders, including agencies, electric utilities, energy producers and academic experts. NMPRC has also been involved in regulatory efforts related to the implementation of a regional electricity market, with a particular focus on integrating more renewable energy, improving grid reliability and facilitating decarbonization. The goal is to enhance regional electricity coordination and consider the establishment of a New Mexico Regional Transmission Operator (RTO) Task Force to ensure active participation in regional discussions, influencing studies and models to benefit the state, and making consensus recommendations on further research needs or actions, such as legislation for the state’s energy strategy.

Furthermore, the NMPRC is taking steps to establish guidelines for utilities considering joining regional transmission organizations (RTOs) or similar entities that support the sharing of electricity across various utilities. This initiative is focused on improving grid reliability by allowing utilities facing shortages to purchase power from those with surpluses, often on a day-ahead basis. The NMPRC aims to collect insights from investor-owned utilities to shape rules and set expectations for involvement in these regional energy networks, encompassing day-ahead markets, comprehensive RTOs and Independent System Operators (ISOs) that cover smaller areas than RTOs. The effort encourages participation from both investor-owned utilities and other parties like rural electric cooperatives. This move is part of a wider push toward regional energy cooperation, highlighted by participation in the California ISO Western Energy Imbalance Market by utilities such as the Public Service Company of New Mexico (PNM) and El Paso Electric Company (EPE), and ongoing talks about forming an RTO for the western United States. In January 2024, the NMPRC, as part of an ongoing inquiry (Case No. 23-00268-UT), held a workshop to further evaluate the feasibility and potential benefits of PNM and EPE participating in a regional day-ahead market or joining a Regional Transmission Organization (RTO)/Independent System Operator (ISO).This initiative aligns with the State-Led Market Study, supported by the U.S. Department of Energy, indicating the need for centrally optimized day-ahead unit commitment and real-time dispatch within such markets.

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United Kingdom 2

Ofgem fostering innovation and shaping the energy regulatory environment through regulatory sandboxes (United Kingdom)

The UK’s regulatory sandbox initiative represents a proactive approach by Ofgem to support the energy sector’s transition toward a more innovative, efficient and sustainable future by providing a space for controlled experimentation. It plays a crucial role in shaping the regulatory environment to better align with the fast-paced evolution of technology and consumer demands in the energy market. Projects accepted into Ofgem’s regulatory sandbox initiative have varied widely, including trials of peer-to-peer energy trading platforms, blockchain-based energy transaction systems, smart grid technologies and demand-side response models; they demonstrate the scope of innovation in the sector.

Context — Problem/Issue

Regulatory sandboxes are innovative frameworks to allow both established companies and start-ups to test new business models, products and services in a real-world environment without immediately incurring all the usual regulatory consequences. In the UK’s energy sector, regulatory sandboxes are primarily facilitated by the the Office of Gas and Electricity Markets (Ofgem), the UK’s energy regulator. The regulatory sandbox approach fosters collaboration between innovators, regulators and other stakeholders in the energy sector. By sharing learnings from sandbox projects, Ofgem aims to inform future regulatory policy and support the scaling of successful innovations across the market. It encourages an iterative learning process, where feedback from sandbox trials can lead to adjustments in regulatory approaches to better accommodate emerging technologies and consumer needs.

In 2016, Ofgem launched the Innovation Link program, as a supportive platform for energy sector innovators, offering regulatory guidance and assistance, on a case by case basis, aiming to facilitate the development and deployment of new energy products, services and business models, addressing the need for regulatory adaptation in the face of evolving market conditions. The Innovation Link program has covered various cases encompassing a broad range of areas, such as smart electricity grids, integrated approaches or sector coupling, energy storage, flexibility services for grid stability, electric vehicles and behind-the-meter solutions, among others. The program includes the Energy Regulation Sandbox (ERS) initiative (still operational), allowing participants to temporarily trial and implement innovative products and services in a live environment without immediately facing all the usual regulatory constraints. Despite the ERS not facilitating permanent regulatory changes, it does enable participants, post-trial, to propose modifications to the code or influence Ofgem to amend regulations. Since 2021, the ERS initiative has granted five sandboxes, covering P2P electricity services, electric vehicles, microgrids and flexibility services. Furthermore, to foster engagement and enhance the effectiveness of its programs, Ofgem has published guidelines and initiated public consultation processes.

Ofgem’s regulatory sandbox mechanism has evolved over time, continuously refining its approach based on feedback, addressing the dynamic changes and innovations within the energy sector. In October 2023, to expand the provisions from the ERS, Ofgem proposed the Future Regulation Sandbox (FRS) initiative, aiming to keep regulatory frameworks updated and conducive to achieving a net zero energy system cost-effectively. The FRS is designed as a policy tool to test potential amendments to the energy rulebook in a controlled setting, drawing inspiration from similar strategies by regulators worldwide to foster innovation and inform regulatory adjustments. Ofgem is actively seeking input from stakeholders to refine the FRS proposal, emphasizing its potential to unlock innovation, and is querying the industry on applicable topics and effective execution methods to ensure the sandbox maximizes market benefits.

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Canada

Charting the path to net-zero: CER's role in shaping Canada's energy transition (Canada)

Canada’s energy regulatory framework embodies a complex interplay of federal, provincial and territorial jurisdictions. Focused on ensuring the safe and environmentally responsible development, transportation and trade of energy, the Canada Energy Regulator (CER), regulates the lifecycle of energy projects from inception to abandonment, emphasizing safety, efficiency and environmental stewardship. Its recent publication, Canada’s Energy Future 2023, outlines potential pathways to achieving net-zero emissions, highlighting the shift toward clean energy sources and the essential roles of electricity, hydrogen, bioenergy and carbon capture technologies. With about 73,000 km of energy infrastructure under its watch, CER’s responsibilities extend to rigorous evaluation of energy projects and regulatory updates to meet modern challenges, including the intricate process of pipeline abandonment. Aiming for a safer, cleaner energy future, CER’s initiatives reflect a proactive and inclusive approach to regulatory oversight, engaging stakeholders and adapting to technological advancements to foster a sustainable energy landscape in Canada.

Context — Problem/Issue

Canada’s energy sector holds a diversified energy mix that includes hydroelectric power (which constitutes over 60% of its electricity generation), oil and gas (of which Canada is a major producer and exporter), nuclear energy, coal, and a growing portion of renewables such as wind, solar and bioenergy. Canada aims to reduce its greenhouse gas emissions by 40-45% from 2005 levels by 2030 and achieve net-zero emissions by 2050. Energy activities are responsible for over 80% of the nation’s greenhouse gas emissions, with the oil and gas sector alone contributing about a quarter. To meet its climate goals, Canada has implemented various policies and regulations, notably a carbon pricing scheme.

Canada’s energy regulatory framework is complex, involving federal, provincial and territorial jurisdictions. Energy production, particularly oil and gas, is primarily regulated at the provincial level, whereas interprovincial and international energy trade and transmission are under federal jurisdiction. The Canada Energy Regulator (CER) is in charge of evaluating energy development projects, enforcing safety and environmental standards, and providing comprehensive information and reports on Canada’s energy sector, including production, consumption and infrastructure projects. The CER oversees federal infrastructure to guarantee energy’s safe and efficient delivery domestically and internationally, safeguarding the environment, acknowledging Indigenous Peoples’ rights, and enhancing management systems through technological and innovative advancements. Its regulatory scope includes evaluating pipelines, energy development and trade based on economic, environmental and social considerations, overseeing projects throughout their entire lifecycle.

Following its energy information mandate, CER published the report Canada’s Energy Future 2023, which outlines potential net-zero scenarios to enable Canadians and decision-makers to envision the possibilities of a net-zero future, helping to clarify the objectives and support informed decision-making processes, highlighting the shift toward cleaner energy sources and the vital roles of electricity, hydrogen, bioenergy and carbon capture, utilization and storage (CCUS) in the transition. In the report, CER proposes three scenarios (Global Net-Zero, Canada Net-Zero, and Current Measures) that vary by the intensity and pace of climate action within Canada and globally, transitioning from fossil fuels to electricity generated from clean sources. In the net-zero scenarios, the electricity sector is expected to achieve net-zero emissions by 2035, subsequently moving to net-negative emissions with the adoption of bioenergy combined with CCUS. The report underscores the need for comprehensive contributions from all economic sectors toward net-zero emissions, with significant reductions also expected in transportation, residential and commercial, and oil and gas sectors.

CER is also in charge of overseeing the country’s energy infrastructure, focusing on the safe and efficient transportation of energy through pipelines and powerlines across Canada, of which around 10% fall under its mandate or approximately 73,000 km. It regulates the entire lifecycle of pipelines or power line projects, taking into account economic, environmental and social considerations before making decisions or recommendations. CER’s scope, therefore, includes the regulating and monitoring of abandoned pipelines that involve permanently ceasing the use of a pipeline for transporting products to end users. This process can result in the pipeline being either removed or left in place, with efforts to restore the land to its original state. CER outlines a three-stage process for pipeline abandonment, including physical abandonment activities, reclamation monitoring and ongoing monitoring for pipelines left in place. Companies are required to engage with potentially affected communities, including Indigenous Peoples and landowners, and take measures to protect the environment and public. Opposing an abandonment project involves submitting a formal statement to CER, which will then consider the opposition as part of its decision-making process, assessing each application based on factors such as engagement with affected parties, environmental and public protection, and the company’s abandonment reasons. Furthermore, CER is constantly updating its pipeline regulatory framework; in 2022 it launched a comprehensive, multi-year effort to refine the regulatory framework for onshore pipelines, involving stakeholder engagement and public consultation. Key themes include improving clarity and transparency of regulations, enhancing regulatory flexibility to support competitiveness without compromising safety and environmental standards, and future enhancements to the regulatory framework for onshore pipelines, with a focus on inclusive engagement and updating regulatory guidance to reflect current realities and aspirations for reconciliation and environmental stewardship. Moreover, in 2023 CER updated its methodology for funding future pipeline abandonment, focusing on safety, environmental protection and community safeguarding, incorporating new data and assumptions for more accuracy that led to increased cost estimates for abandonment due to inflation and changes in infrastructure. An initial estimate suggests $18.6 billion CAD is needed for future abandonment, up from $10.4 billion CAD in 2019. Companies are required to secure funds for these costs through trusts or financial guarantees.

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Michigan 2

Pilot program- optional premium payment to encourage renewable electricity supply (Michigan)

In the United States, the Michigan Public Service Commission (MPSC) has implemented pilot green pricing programs, which enable customers to voluntarily choose a specific portion of their electricity to come from renewable energy sources by paying a premium to prevent non-participants from subsidizing these programs.

Context — Problem/Issue

To support decarbonization, the Michigan Public Service Commission (MPSC) has implemented Voluntary Green Pricing (VGP) Programs to enable customers to freely choose a specific portion of their electricity to come from renewable energy sources. The costs of the programs are billed to participating customers.

The VGP allows customers to voluntarily choose to have a portion of their electricity sourced from renewable energy, opting into programs where the additional costs are billed to them. Therefore, only participants of VGP programs bear the costs, calculated through a service formula to prevent non-participants from subsidizing these programs. Participants might see cost savings if the program’s costs decrease. Most customers, from residential to industrial, are eligible to participate in VGP programs, subject to specific utility program criteria. Participation in the VGP is optional and interested customers must sign up with their utility to join a VGP program.

All utilities in Michigan, whether regulated by the MPSC, municipal, cooperative or alternative electric suppliers, are mandated by the Public Act 342 of 2016 (section 61)  to offer VGP programs to their customers, with MPSC overseeing the approval for regulated utilities. Those providers under the regulation of the MPSC are required to receive approval from the Commission for their programs, which are subject to review every two years.

Public Act 342, nonetheless, lacks detailed guidance on the components and evaluation criteria for green pricing programs. In response, the MPSC issued orders in March and July 2017, under Case U-18349 et al., to fill this gap. In March 2017, the MPSC requested electric providers and stakeholders to share their insights on the VGP tariffs, including their structure, development and requirements. By July, the Commission offered explicit instructions for utilities on preparing their Section 61 proposals, emphasizing cost-of-service principles to prevent subsidization by non-participants, the necessity for transparency in program terms, renewable energy technologies, source locations and clear accounting of customer costs and savings. It also stressed the importance of accurate price signals, marketing and administrative cost transparency, and the requirement that renewable energy generation be additional to existing mandates, ensuring accurate renewable energy credits accounting to prevent overlap. The process has been ongoing since 2017, with utilities required to update their offerings periodically.

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Chile

CNE's adaptative role in decarbonization efforts (Chile)

Chile’s National Energy Commission (CNE) has shown an adaptive approach to facilitating Chile’s decarbonization while balancing economic and community impacts. CNE’s mandate includes setting tariffs, ensuring market transparency and overseeing the decommissioning of coal plants. The CNE faced a unique challenge in May 2022 when it had to delay the closure of a coal plant due to potential electricity shortages, highlighting the complexities of integrating renewable energies into Chile’s distinct electricity grid. To mitigate the impacts of coal plant phaseouts and support communities dependent on coal, the CNE introduced a “strategic reserve” mechanism, offering compensation to keep coal plants as backup and ensuring security of supply. Moreover, in April 2023, the CNE revised the compensation mechanism for utilities, so that coal generators could no longer pass through the costs of an emissions tax, thereby improving the competitive position of renewables.

Context — Problem/Issue

Historically dependent on imported fossil fuels and coal plants for electricity generation, Chile has made a decisive pivot, aiming to gradually phaseout/reconvert all coal-fired power plants by 2040 and significantly reduce its carbon footprint. Chile has set the goal to reach 80% of renewable generation by 2030 (which reached 60% in 2022, mainly hydro and solar) and aims to become carbon neutral by 2050. These goals are supported by different policies, like the 2015 National Energy Policy (updated in 2022) and the 2030 Decarbonization Plan, along with various legal and regulatory frameworks promoting clean energy investments, electric mobility, energy efficiency programs and the exploration of emerging technologies like green hydrogen. Chile’s energy transition is underpinned by both public and private sector initiatives, with the government facilitating this shift through incentives, regulatory reforms and international cooperation on climate and energy projects. The country’s emphasis on renewable energy, combined with a robust regulatory framework and clear long-term goals, has positioned Chile as a leader in Latin America’s energy transition.

Chile’s National Energy Commission (CNE) plays a crucial role in directing and executing Chile’s energy policies, with key responsibilities that include developing regulatory frameworks to encourage a competitive and efficient market with a focus on renewable energy and reliability; setting tariffs; overseeing the market to ensure transparency, fairness and consumer protection; advising the Government on all matters related to the improvement of the energy sector; issuing and overseeing tenders in the energy sector, including generation, capacity, transmission and distribution; developing transmission plans; and a specific mandate to approve the decommissioning of coal plants. Nonetheless, due to stability and security concerns, in May 2022, as an isolated case, the CNE had to postpone the closure of a coal plant that had previously been approved, on account of projected electricity shortages and further risks in the system.

Ensuring the integration of variable renewable energies poses challenges given the unique linear and isolated nature of Chile’s electricity grid and the relatively young age of many of its coal-fired power plants (64% being less than 10 years old); the system demands more reliability, flexibility and storage. Additionally, the economic reliance of communities on coal-fired plants and coal mining presents a critical issue in the absence of economic alternatives. Fostering community backing for a “just transition” and exploring technical-economic alternatives for repurposing the infrastructure of retired coal plants are essential. To reduce the negative impacts of an abrupt coal phaseout and reach stakeholder consent to motivate early decommissioning, a “strategic reserve” mechanism was implemented by the CNE (Decree 42/2020) (and updated in November 2023), through a coordinated effort with the government. The mechanism allows a 60% compensation for capacity for coal plants to be ready for dispatch, as a backup, if needed, despite not injecting power to the grid, based on the principle of security of supply.

Another example of CNE’s role in decarbonization is the modification of the compensation mechanism that requires utilities to compensate relatively high-cost generators in the power system, since the carbon tax is not factored into the marginal spot price of electricity during periods when a fossil fuel-based generator sets the price. The scheme required all utilities to cover the cost difference when a power plant’s operational costs, inclusive of the carbon tax, equal or surpass the market’s marginal spot price. This shifted the financial burden of the carbon tax from the polluting power plants to the utility companies purchasing electricity, thereby distorting market incentives since plants with higher emissions were not held financially accountable for their carbon tax, weakening the intended encouragement for cleaner energy investment. This meant that high emitting generation could pass through the costs of the emissions tax (stated in Art. 8, Law No. 20.780) and therefore undermined the purpose of the tax which was to make low emitting generation more competitive. This provision was modified in April 2023 so that emissions taxes would be better allocated to coal and other fossil fuel generators that were previously benefiting from this compensation mechanism.

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Georgia

GNERC's strategic initiatives: implementing a sustainable energy landscape (Georgia)

The Georgian National Energy and Water Supply Regulatory Commission (GNERC) is steering the sector toward alignment with European Union directives, emphasizing green energy, net metering and energy efficiency within its strategic goals. Since implementing net metering in 2016, GNERC has successfully integrated over 1000 micro power plants into the grid, enhancing renewable energy use and promoting energy independence among consumers. Significant reforms, such as the 2021 Rules for Electricity Distribution Network, have standardized connection requirements and facilitated the integration of electric vehicle charging stations, among other updates aimed at modernizing the sector. In 2022, GNERC established guidelines for connecting small power plants to the distribution network, supporting decentralized renewable energy production. The commission’s establishment of the Energy Training Center in 2022 further underscores its commitment to education and awareness in the energy sector. Additionally, GNERC’s recent Memorandum of Understanding with the Azerbaijan Energy Regulatory Agency in February 2024 highlights its dedication to regional cooperation and the sharing of best practices in energy regulation.

Context — Problem/Issue

Georgia’s energy sector heavily relies on natural gas and oil imports; domestic energy production comes mostly from hydropower that supplies about 80% of electricity and bioenergy. Georgia has been exploring and investing in other renewable energy sources, such as wind and solar, albeit to a lesser extent. The country has recently updated its greenhouse gas emissions reduction target from 35% to 47% by 2030 (relative to 1990 levels) and seeks to attain climate neutrality by 2050 via a swift and comprehensive technological transformation. Georgia’s strategic location between Europe and Asia positions it as a potential energy corridor, facilitating energy transit from the Caspian region to European markets. The country’s energy policy has increasingly focused on enhancing energy security, diversifying energy supply and integrating with European energy markets, following its intentions to join the European Union (candidate status was granted in December 2023). This includes efforts to connect with the European Network of Transmission System Operators for Electricity (ENTSO-E) and to liberalize its electricity market in line with EU practices.

The Georgian National Energy and Water Supply Regulatory Commission (GNERC) was established to ensure fair market competition, protect consumer rights and foster efficient utility services; it is responsible for setting tariffs, issuing licenses, monitoring utility service quality and promoting the development of energy markets. GNERC has been working on adapting Georgia’s regulatory framework to align with European Union energy directives. GNERC’s strategic goals include the promotion of green energy generation and net metering, as well as promoting energy efficiency. Its mandate is included within the framework of the Law of Georgia on Promotion of Production and Use of Energy from Renewable Sources and the Law on Energy and Water Supply. While GNERC maintains independence in areas such as transmission rules and tariff setting, it collaborates with the government on national energy policy, reviewed by the regulator before final approval.

GNERC implemented net metering in 2016, to incentivize individuals to produce their own electricity and sell any surplus back to the distribution network for a fee, aiming to promote renewable energy use and allow consumers or consumer groups to generate power through solar, wind or water sources (including wastewater), with a cap on micro power plant capacity at 500 kW. By January 2024, this system had successfully integrated over 1000 micro power plants into the grid, with an installed capacity of around 64 MW. GNERC is still drawing insights from other countries to improve net metering regulation.

In June 2021, GNERC issued the Rules for Electricity Distribution Network (Resolution 19) that implemented several changes in the electricity sector. Key updates include the standardization of connection requirements, specifying that the minimum connection capacity for each consumer must be at least 10 kW (applicable to residential, industrial, multi-apartment buildings and other units); deadlines for electricity consumption metering and reading; a raised cap on the total permissible installed capacity of micro-generation power plants; and specified conditions for installing smart meters in divided units.

The new Rules also introduced preferential connection terms for electric vehicles’ public charger stations to the distribution network, ensuring these facilities are accessible beyond personal use. The capacity of these charging stations is excluded from the overall capacity calculation of the facility or area where they are located, and their use is strictly for charging purposes only. The connection fee for these stations is set at 50% of the standard fee for new customers in the distribution network and the system operator has the right to terminate the connection if a charging station remains unconnected for a year after connection works are completed or is not used for ten years.

In 2022, GNERC approved a new rule for connection to the electricity distribution network for small power plants up to 15 MW. The rule established transparent and fair guidelines for connecting small capacity power plants to the distribution network, facilitating the growth of decentralized renewable energy production. It included provisions for the readiness of the electricity distribution network and the ability to connect for a reasonable fee, ensuring a non-discriminatory approach toward investors and allowing them to pre-determine the costs and conditions for network connection. In 2023, GNERC adopted the electricity market rules as well as dispute resolution rules. Day ahead, balancing and ancillary services markets are expected to start operations by mid 2024.

GNERC has also implemented an Energy Training Center in 2022, aiming to enhance education and raise awareness in the electricity, natural gas and water supply sectors. The center’s objectives include promoting critical issues, identifying priority areas for action in response to current challenges, facilitating the exchange of experience and knowledge, developing scientific and educational projects, establishing an electronic library, and organizing thematic conferences and scientific forums.

Furthermore, in order to enhance cooperation through the exchange of information on energy regulation, the GNERC signed in February 2024 a Memorandum of Understanding with the Azerbaijan Energy Regulatory Agency (AERA), aimed at fostering the development of energy sector regulation and to facilitate joint training programs, study visits and expert training sessions specifically targeting renewable energy and energy efficiency regulation.

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Japan

Japan’s launch of long-term decarbonized power resource auctions (Japan)

Japan’s energy sector is undergoing transformative changes and reforms, influenced by its scarce natural resources, heavy dependency on energy imports, and a significant shift from nuclear to fossil fuels following the 2011 Fukushima disaster, affecting both energy security and emissions. The government’s ambitious goals to cut greenhouse gas emissions by 46% from 2013 levels by 2030 and achieve carbon neutrality by 2050 have led to the full liberalization of the electricity and gas markets to foster competition and innovation, a process monitored by the Electricity and Gas Market Surveillance Commission (EGC). To spur investment in clean energy, Japan initiated the first Long-Term Decarbonized Power Resource Auctions (LTDA) by the end of FY 2023. LTDA encourage new projects in renewable energy and modernization of existing power plants, and offer stable, long-term income to successful bidders. The EGC is responsible for defining allowable costs in bid prices according to established regulations and for overseeing the monitoring of bid prices and revenues earned by successful bidders.

Context — Problem/Issue

The energy sector in Japan is characterized by its unique challenges and strategic responses, shaped by the country’s limited natural resources and high dependency on energy imports. The government has set ambitious targets to reduce greenhouse gas emissions by 46% by 2030 from 2013 levels, aiming to become carbon neutral by 2050. The Japanese government has undertaken various policy measures and regulatory reforms to support its energy transition and decarbonization goals. The government has introduced incentives and subsidies to support renewable energy deployment and energy conservation measures, and as well as financial mechanisms, including the introduction of carbon pricing in 2023. Carbon credits started to be traded in the Tokyo Stock Exchange by the end of 2023.

The Electricity and Gas Market Surveillance Commission (EGC) of Japan was launched in 2015 to strengthen the monitoring function of the energy markets after their liberalization (in 2016 for electricity and 2017 for natural gas). Its functions include the evaluation of tariffs and the development of new rule recommendations to the government to foster competition. Additionally, it has the authority to issue non-binding advisories to utilities.

The EGC plays an important role in the energy transition through its involvement in the  Long-Term Decarbonized Power Resource Auctions (LTDA), a new initiative that is managed by the Organization for Cross-regional Coordination of Transmission Operators (OCCTO), and aims to promote investment in creating, replacing and upgrading decarbonized power projects, with fixed costs recoverable over a 20 year period and specifically excluding projects already supported by existing capacity markets or FIT/FIP schemes (in accordance with the guidelines issued in July 2023 by the Agency for Natural Resources and Energy). The first auction, which opened in January 2024, targets a total of 4GW for decarbonized resources, 1GW for thermal plant renovations, and 1GW for battery storage and pumped hydro projects, with varying minimum bid volumes based on the project type. The EGC identifies permissible costs for inclusion in bid prices, ensuring these costs adhere to established rules; once the bidding period ends, it is in charge of monitoring the bid price and the revenues obtained by awarded bidders, ensuring that their annual reporting of additional market revenues is both accurate and fair.

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New Mexico 1

New Mexico’s regulator ensuring a just transition through energy transition bonds (New Mexico)

The New Mexico Public Regulation Commission (NMPRC) plays a crucial role in overseeing the State’s energy transition, ensuring utilities adhere to state objectives while maintaining reliable services. The Energy Transition Act of 2019 introduces relevant mandates to the NMPRC and financial mechanisms to support communities affected by coal plant closures, with specific funds aimed at aiding displaced workers and facilitating economic development in impacted areas. Despite facing opposition and challenges, including debates over financial burdens and ratepayer impacts, the NMPRC’s regulatory oversight continues to shape New Mexico’s path towards a sustainable and decarbonized future.

Context — Problem/Issue

New Mexico is a leading oil and gas producer in the U.S. and has historically relied on fossil fuels as economic drivers, which has brought environmental and sustainability challenges. Coal has historically been the primary source of electricity generation in New Mexico. Its contribution to the state’s energy mix, however, has been declining since 2004, driven by stricter air quality regulations, the lower costs of natural gas, and California’s 2014 decision to cease purchasing coal-generated electricity from neighboring states. These factors have led to the closure or conversion of coal-fired power plants to alternative fuel sources as part of broader efforts to reduce greenhouse gas emissions and increase the use of renewable energy. The state has set ambitious renewable energy targets, aiming to double the state’s renewable energy use by 2025, achieve 50% renewable energy by 2030, and 100% carbon-free electricity by 2045 for investor-owned utilities and by 2050 for cooperatives, as outlined in the Energy Transition Act of 2019. Currently, renewable energy has emerged as the predominant source of electricity in New Mexico (mainly wind, that in 2022 surpassed, for the first time, coal power generation).

The New Mexico Public Regulation Commission (NMPRC) oversees the utility sector, ensuring reliable service and guiding the energy transition in line with state objectives. It has several tools regarding decarbonization within its mandate. The NMPRC holds a critical role in ensuring a fair transition as mandated by legislation, which requires phasing out coal in favor of renewable energy sources. The Energy Transition Act provides the NMPRC with guidelines for transitioning from retiring coal plants toward future energy solutions.

To support this transition, the Act establishes three specific funds designed to assist communities impacted by the shutdown of coal facilities, allowing utilities to issue “energy transition bonds” covering costs associated with coal plant closures. This includes up to $30 million for coal mine reclamation and up to $40 million to assist displaced workers and communities through the Energy Transition Indian Affairs Fund, the Economic Development Assistance Fund, and the Displaced Worker Assistance Fund​​. The NMPRC is responsible for authorizing the bonds and overseeing the proper allocation of these utility funds into the designated support funds.

Nonetheless, these provisions have faced opposition, including the financial burden placed on ratepayers of the Public Service Company of New Mexico (PNM), the state’s largest electricity provider, rather than its shareholders. Further controversies have emerged regarding PNM customers still paying the same rates for non-operating facilities and despite the NMPRC’s approval of rate reduction; or about the NMPRC’s denial to issue bonds to recoup the costs of a coal plant abandonment. NMPRC’s decisions have been upheld by the Supreme court.

By July 2023, state agencies in New Mexico were actively working to distribute funds from the Energy Transition Act. Despite a delay in funds reaching communities and workers, caused by the time taken to refinance past investments through low-interest bonds, efforts are underway to allocate $5.9 million for community projects and support for displaced workers. The Indian Affairs Department has already earmarked its $1.8 million for agricultural projects, while the Department of Workforce Solutions has begun distributing $20,000 direct payments to displaced workers, many of whom have expressed interest in training for new careers.

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Egypt

EgyptERA’s strategic initiatives paving the way for renewable energy and efficiency

In response to Egypt’s strategic pivot toward renewable energy and improved energy efficiency, EgyptERA, the nation’s energy regulator, has taken assertive actions to facilitate this transition. These include enacting exemptions from integration fees for smaller solar photovoltaic projects participating in net metering and self-consumption initiatives, establishing the country’s inaugural framework for electric vehicle (EV) charging infrastructure, and devising an energy efficiency plan aimed at distribution companies. These measures underscore EgyptERA’s commitment to fostering a sustainable energy landscape, promoting the use of renewable resources, and supporting the nation’s ambitious energy goals.

Context — Problem/Issue

Despite possessing substantial oil and gas resources along with significant renewable energy potential, Egypt has encountered critical energy challenges in recent years. These challenges include power shortages triggered by escalating energy demand due to the nation’s swiftly growing population and expanding economy. Such conditions not only pose challenges in guaranteeing a reliable supply of energy but also open up opportunities for development within the energy sector. To tackle this, the country’s electricity sector is undergoing a profound transformation aimed at diversifying its energy sources by increasing renewable energy contributions and improving energy efficiency. The government’s reforms are focused on liberalizing the energy market to foster competition, reduce state control and promote sustainable and efficient energy use.

The Electric Utility and Consumer Protection Regulatory Agency (EgyptERA) is in charge of the regulation, supervision and development of the electricity sector, and it has a specific mandate toward energy efficiency. Electricity Law No. 87 of 2015 and its regulations set the legal foundation for the restructuring of Egypt’s electricity market toward liberalization and competitiveness. The regulator also has a responsibility to facilitate the development of renewable energy, which the government targets to increase to 42% of its electricity mix by 2035 and has issued several directives. Circular No 2/2020 (amended by Circular No 6/2022)  established Egypt’s net-metering scheme for renewable energy sources, introducing several new regulations to streamline the process and promoting the development of solar energy. These amendments include specific requirements for the location and capacity of generation facilities, limitations on the total and individual project capacities, and the necessity of additional studies for medium-voltage network interconnections. An annual settlement of net-metering charges, based on the latest purchase price/tariff, is required, and an integration fee has been introduced to cover the costs of balancing renewable electricity on the grid. Projects up to 10 MW and all self-consumption projects, however, are exempt from this fee. Circular No 5/2022 was the inaugural regulation for electric vehicle (EV) charging infrastructure in Egypt, facilitating the setup of EV charging stations across the nation. Circular No 2/2023 paved the way for the private sector to procure renewable energy directly from the New and Renewable Energy Authority (NREA), enabling three private telecom companies to shift their energy consumption entirely to renewable sources within NREA’s generation capacity. Circular No 3/2023 detailed the framework for solar photovoltaic (PV) self-consumption in Egypt, applicable to both grid-connected and off-grid projects exceeding 500 kW, intended solely for the project owner’s use and not for sale. The regulator extended the exemption of the merger fee to 10MW capacity PV plants under Net Metering (on-grid) projects. This showcases how EgyptERA, to foster investments (mainly in solar PV), offered innovative renewable energy schemes: net metering and self-consumption with fees exemptions for installations under 10 MW, leveraging the benefits of net metering and self-consumption regulations to encourage more renewable initiatives.

EgyptERA also developed policies to support the solid energy efficiency framework, based on the Egypt Strategic Vision 2030, the National Energy Efficiency Action Plan (NEEAP) for 2018/2021, and the Electricity Law No. 87 of 2015. Although national targets are in place to minimize both technical and commercial losses within the network, the regulator has established an energy efficiency distribution plan for distribution companies that shall cover, among other aspects, the enhancement of efficiency of electricity consumption, encourage the use of renewable energy, and educate consumers on the efficient use of electricity.

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United Kingdom 1

Responding to a broader regulatory mandate (United Kingdom)

The Energy Act 2023 in the United Kingdom marks a significant step forward in supporting the clean energy transition, positioning Ofgem, the energy regulator, as a pivotal figure in the government’s net zero mandate. This comprehensive legislation introduces major changes enhancing Ofgem’s influence in the transition. Firstly, it mandates Ofgem to consider net zero goals in regulatory decisions, requiring documentation of how decisions align with the 2050 net zero emissions goal and five-year carbon budgets. Secondly, it establishes Ofgem’s regulatory authority over heat networks, aiming to expand their heat supply contribution from 2% to 18% by 2050, by addressing pricing, reliability and service quality. Thirdly, it assigns Ofgem as the economic regulator for CO₂ transport and storage networks, crucial for the development of Carbon Capture, Usage and Storage (CCUS) technologies, by overseeing licensing and revenue models to encourage investment. Lastly, it shifts the responsibility of energy market rules oversight from industry to Ofgem, tasking it with setting strategic directions and consolidating energy codes. Furthermore, Ofgem had a proactive involvement in government consultations on heat networks and energy code reform, even before the legislation, that showcases its active role in energy transition.

Context — Problem/Issue

One of the issues that regulators raised in the interviews is the extent to which they might be expected by government to take on more responsibility to assist the clean energy transition. The United Kingdom has just passed the Energy Act 2023 which is a broad piece of legislation to support the clean energy transition. The energy regulator for the UK (Ofgem) emerges as a linchpin in support of the government’s net zero mandate. There are four major changes in the legislation that directly affect Ofgem’s ability to influence the clean energy transition:

1. Mandate to consider net zero in regulatory decision making. The legislation adds a specific duty to assist the government’s achievement of both the 2050 net zero emissions goal (which itself is enshrined in legislation) and the five-year carbon budgets, which restrict the total carbon dioxide emissions over a five-year period (currently 2023-27 inclusive). Ofgem will be required to apply this new duty in its decision making and to document how it has done so.
2. Development of a regulatory framework for heat networks. The government had identified heat networks (both district heating networks, which might supply multiple buildings, and communal networks, which would supply multiple residences in a single building) as an important provider of heat in a decarbonized energy system. Heat networks currently supply 2% of heat in the UK and government policy is for this to increase to 18% by 2050. The government sees the regulator as the key player to spur growth and investment in heat networks so that they become more common. With the legislation just passed, Ofgem will have authority to regulate the 14,000 existing heat networks. Ofgem will now have the ability to address disproportionate prices, and establish reliability and quality of service standards.
3. Development of a regulatory framework for CO₂ transport and storage networks. The government also identified Carbon Capture, Usage and Storage (CCUS) as an essential element of a Net Zero energy system. The Energy Act 2023 gives Ofgem legal powers as the economic regulator for CO₂ transport and storage networks and makes the transport and storage of CO₂ a licensable activity. The regulatory regime will set the allowed revenue that a licensee will recover from use of system charges paid by users of the network. The allowed revenue will enable licensees to earn a regulated return on their investment while allowing the economic and efficient development of the network.
4. Greater oversight over energy market rules. The legislation additionally shifts responsibility for energy codes — which cover the wholesale and retail market rules for the gas and electricity markets, as well as connections —from an industry responsibility to one that is overseen by Ofgem. Ofgem will set the strategic direction for energy codes, including expectations of changes in codes that will need to be delivered by code managers (licensed by Ofgem) for each year. Ofgem has identified consolidation to reduce the number of different codes (currently 11) as an early priority.

Ofgem has already been active in anticipation of the new responsibilities, two of which (heat networks and energy code reform) were set out by the government well in advance of the legislation. For heat networks, Ofgem has been active in government consultations on the topic, as well participating in a joint consultation with the government on consumer protection issues with respect to heat networks. On energy code oversight, Ofgem is currently working with the government on the regulations that will need to be passed to establish Ofgem’s oversight of the codes.

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Québec

Assessing ratepayer funding of a hybrid heating program (Canada, Québec)

In the context of regulatory decisions for major decarbonization initiatives, decarbonization often interacts with other criteria, leading to compromises rather than ideal solutions focused solely on carbon reduction. An example of this is the approval of a hybrid heating/electrification program in Québec. Here, the electricity and gas distributors proposed a program encouraging gas heating customers to switch to electric heating with natural gas backup. The Régie de l’énergie du Québec approved this hybrid approach over a complete transition to electric heating, considering the higher costs an all-electric system would impose on the power system and other consumers not participating in the program.

Context — Problem/Issue

One of the great challenges in decarbonizing energy systems will be the decarbonization of building heating. Heating demand is highly seasonal, and fuels (mostly natural gas where available, but also fuel oil) are drawn on most heavily on the coldest days and in many jurisdictions remain the lowest cost options for heating. Electrification of heating through heat pumps offers a very good solution in many situations, with their high efficiency, and they have been successfully deployed even in relatively cold climates, such as in Scandinavia. Regulators will be faced with the increasingly challenging task of encouraging this electrification of heating both as it affects the electricity system and the natural gas system. In jurisdictions where gas heating currently predominates, the switch to electric heating will affect both natural gas and electricity systems, the former from the loss of revenues and the latter from increase in costs, particularly to meet higher winter peak demands for electricity.

In the Canadian province of Québec, the government has announced targets to reduce greenhouse gas emissions by 37.5% by 2030 (compared to 1990 levels) and in particular to reduce building heating emissions by 50% by 2030. Decarbonization of building heating is particularly challenging in Québec because of the very cold winters. Temperatures can fall to levels at which even “cold climate” heat pumps will struggle to supply sufficient heat, necessitating either electrical resistance or some fuel-based heating as a backup supply. Furthermore, as the annual system demand already peaks in winter, more electric heat will drive an increase in the peak load and therefore system costs. In its Plan for a Green Economy 2030, the government noted that it had asked Hydro Québec, the government-owned supplier responsible for nearly all electricity supply in Québec, which it obtains from renewable (mainly hydroelectric) sources, and Énergir, the largest natural gas distributor, to team up to achieve “a partial conversion from natural gas to electricity [as] part of a balanced approach, based on optimum complementarity between the electricity and gas networks, in order to maximize economic benefits and minimize costs for customers.”

In response, the two companies reached an agreement to offer a building heating electrification program known as the Dual Energy Offer. The Dual Energy Offer is aimed at natural gas heating residential customers and involves installing a heat pump to supply heat with the existing gas furnace or boiler. Customers would rely on the heat pump to supply their heating needs on all but the coldest days when heating would be supplied by natural gas. Customers with the dual energy offer would also have access to an existing special electricity rate, the DT rate, which charges more than four times the standard rate for electricity on colder days, to encourage the customer to switch to natural gas during those periods, but 28% cheaper than the standard rate at other times. In addition, residential customers would be encouraged to switch their water heaters to electricity, regardless of the temperature. A later phase of the program will be aimed at commercial and institutional customers.

The Dual Energy Offer will lead to increases in costs for Hydro Québec (as it must procure additional generation, transmission and distribution) and for Énergir, because of a significant loss of revenue from its customers. To encourage Énergir to proceed with the offer, Hydro Québec agreed to make a financial contribution to Énergir each year depending on the amounts of natural gas displaced by the program. The purpose of the hearing was for Hydro Québec to get approval to recover from its electricity customers the amounts paid to Énergir.

In their proposal, the proponents stated two principal alternatives — an all-electrification scenario (TAE) and the dual energy scenario (bienergie). The dual energy proposal had significantly lower financial impacts, particularly for Hydro Québec, while achieving about two thirds of the emissions savings compared to the all-electrification scenario. As pointed out by some intervenors in their submissions, however, the dual energy proposal would prolong dependence on continued use of fossil fuels for space heating for these customers.

The decision from the Régie de l’énergie du Québec was in favour of the financial contribution from Hydro-Québec to Énergir. The main reasons given in the decision were that the dual energy alternative had much lower impacts on electricity and gas ratepayers than an all-electrification scenario, while still obtaining about two thirds of the emissions savings of the all-electrification scenario. It was estimated that the cumulative additional greenhouse gas emissions savings to 2030 of the all-electrification scenario would amount to just over one million tonnes, but the cumulative impact on Hydro Québec’s revenues would amount to over $1.68 billion (CAD), owing mainly to the need to increase generation and network capacity. In response to the concern raised about the continued reliance on fossil fuels, the regulator noted that the government had stated that they saw the complementarity of the natural gas and electric systems as a vector to achieving their 2030 decarbonization goals.

Upon appeal by some intervenors, however, this decision was overturned by a different panel of the regulator, stating the current law did not allow Hydro Québec to recover these costs from customers. Hydro Québec has indicated it will proceed with the program and pay the compensation to Énergir, but is challenging the regulator’s decision in the courts.

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France 3

CRE’s role in fostering innovation within fFance's energy sector through regulatory sandboxes (France)

France’s Energy-Climate Law of November 8, 2019, introduced a regulatory sandbox mechanism, empowering the French energy regulatory commission, Commission de Régulation de l’Énergie (CRE), to facilitate the energy transition and foster innovation. By granting temporary exemptions for the use of networks and facilities, the CRE enables the experimental deployment of innovative technologies and services aimed at advancing smart energy systems and infrastructure. CRE ensures that these innovations do not compromise the safety, reliability or efficiency of the national energy system, while also working to identify and remove regulatory barriers, assess projects for scalability and market impact, and engage stakeholders in aligning technological advancements with broader energy transition and decarbonization objectives. Through the regulatory sandbox, the CRE provides a structured pathway for innovations to be tested and potentially integrated into the energy market, highlighting the commission’s crucial role in adapting regulatory frameworks to support the evolution of France’s energy sector.

Context — Problem/Issue

The energy landscape is undergoing rapid transformation to meet global goals for CO₂ emissions reduction, which requires a more adaptable electricity system and occasions the rise of new technologies (like electric vehicles) and self-consumption demanding smarter, more flexible networks. To facilitate these shifts, regulatory frameworks need to evolve. Some jurisdictions have responded by implementing regulatory sandboxes as an essential tool to foster innovation.

In France, the Energy-Climate Law of November 8, 2019 established a regulatory sandbox mechanism in the energy sector. This innovative mechanism allows the Commission de Régulation de l’Énergie (CRE) to grant exemptions for using networks and facilities on a trial and temporary basis to test and deploy innovative technologies or services that support the transition to smart energy systems and infrastructures. CRE ensures the national energy system is not compromised due to safety, reliability or efficiency issues, and that trials do not interfere with the proper fulfilment of the public service mission. The CRE’s role extends to offering regulatory flexibility by identifying and addressing regulatory barriers, evaluating projects for their potential scalability and impact on the energy market, and fostering dialogue among stakeholders to align innovations with energy transition and decarbonization goals. Successful sandbox projects can influence regulatory adjustments and the broader adoption of new technologies and practices within the energy sector.

The CRE, after public consultation, issued a guide of application of the regulatory sandbox mechanism, offering a clear pathway for innovators looking to contribute to the energy transition through their projects. In 2020, the CRE released a decision detailing the establishment and operational guidelines of the regulatory sandbox, outlining the procedures for submitting applications and the monitoring process for experimental projects approved by the CRE. Moreover, the framework was updated in 2022 to specify that applications would be processed on a rolling basis, indicating a more flexible approach to handling submissions. Eligibility criteria for the projects to benefit of this mechanism include: supporting energy policy goals; the introduction of an innovative aspect; encounter a specific legislative or regulatory hurdle; have the capacity for broader implementation, especially upon successful experimentation; and offer advantages to the wider community upon eventual rollout. In November 2022, the CRE published the progress of several experimental projects in the French electricity and gas sectors under the regulatory sandbox framework. Furthermore, the CRE granted two additional exceptions in the regulatory sandbox program in September 2023 and February 2024.

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Italy 1

Enabling regulatory change through regulatory sandboxes (Italy)

The transition in the electricity sector toward a model dominated by variable renewable energies (VRE) necessitates significant changes in operating rules to accommodate many owners and operators. This shift requires regulators to foster innovation and adapt rules rapidly to ensure a cost-effective and reliable supply. The Italian Regulatory Authority for Energy, Networks and Environment (ARERA) has been at the forefront of adopting a “regulatory sandbox” approach since 2010, facilitating regulatory adjustments in response to the growing presence of VRE in the power system. ARERA’s efforts have included regulatory experiments, particularly in regions with high VRE penetration, to test smart grid solutions. Successful experiments have led to regulatory modifications for Distribution System Operators (DSOs) to implement these changes more broadly. Additionally, ARERA has focused on system-wide modifications for increased flexibility, such as customer aggregation for flexibility services and the introduction of “Virtual Aggregated Mixed Units” (UVAM), blending consumers and producers in the same offer to enhance system flexibility, and pilot projects for electric vehicle (EV) home charging with relaxed fee structures.

Context — Problem/Issue

The shift in the electricity sector from a system that is dominated by a few large fuel-based generators to one based on variable renewable energies, with many owners and operators, will require very different operating rules. Consequently, the regulator needs to allow a great deal of innovation so that changes to the rules can be made as quickly as possible and deliver more cost-effective, reliable supply.  One of the regulatory experts we spoke to cited the Italian Regulatory Authority for Energy, Networks and Environment (ARERA) as a leading user of a “regulatory sandbox” approach, which it has been doing since 2010, to help adjust its regulatory rules to adapt to a changing power system. The work of the authority was also cited in Ofgem’s latest proposals for a Future Regulation Sandbox.

ARERA has been active in encouraging “regulatory experiments” in the power sector since 2010, in response to a very rapid increase in variable renewable energy in the power system. ARERA recognized that changes to regulations would be needed to adapt the power system to these changes in the most cost-effective way. The first phase of regulatory experiments was focused on regions of the country where distributed VRE penetration was relatively high and so where potential smart grid solutions could be tested. The proven success of some of the experiments resulted in the modification of regulatory framework for the DSOs to implement these changes at a larger scale in a subsequent regulatory period.

The second phase of changes focused more on system-wide modifications such as the need for increased system flexibility to manage the increment in renewable energy.  For example, aggregation of customers to offer flexibility services has been developed in Italy through a series of pilot projects managed by the sole TSO, Terna. While early pilots allowed only aggregation of either consumers or producers, in 2018 Terna, with the approval of ARERA, introduced a pilot for “Virtual Aggregated Mixed Units” (UVAM), similar to a Virtual Power Plant.  For this pilot, ARERA agreed to the relaxation of the 1 MW limit for each individual participant and to allow the mix of consumers and producers to participate in the same offer. These projects, with a minimum aggregate size of 1 MW, are still mainly aimed at commercial and industrial customers, but residential projects are being gradually introduced. UVAM are paid both an energy fee (euros per MWh) but also a resource availability fee (euros per MW) and can participate in balancing and ancillary service markets. As of December 2021, there were 220 UVAM offering 1280 MW of capacity. Early analysis of these projects finds that the approach has been quite successful at tapping into a new source of system flexibility. Another more recent example is examining the issue of home charging of electric vehicles (EVs). While most EVs have onboard charging which allows for charging at home at a rate of 5-6 kW, the typical capacity limit for most Italian households is 3 kW, and those exceeding this demand will have an automatic trip of the power supply, due to the activation of a breaker in the smart meter. Network users wishing to upgrade to higher capacity will normally have to pay one-off charges for the capacity increase and pay higher monthly fees. ARERA  has approved a pilot project with a derogation from the higher fees, provided the customer’s EV charging equipment is capable of remote communications.

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Ontario

Getting government support for electricity tariffs that promote electrification (Ontario)

Electrification offers an opportunity to implement innovative electricity rates that incentivize smart charging for electric vehicle (EV) owners. While traditional time-of-use (TOU) pricing aimed at reducing peak consumption with minor price differences, electrification presents an opportunity to revisit these strategies to encourage charging during low-cost, off-peak hours. In Ontario, the Ontario Energy Board (OEB) has led successful reforms in rate structures to support electrification, particularly for EV charging. This initiative began with pilot programs and involved close collaboration between the regulator, the government and stakeholders, leveraging smart meters to introduce new rates that encourage off-peak charging, thereby aligning with non-emitting power generation periods. To further support innovation in the energy sector, the OEB introduced the OEB Innovation Sandbox program in 2019, facilitating pilot projects that explore new services, activities and business models in the electricity and natural gas sectors.

Context — Problem/Issue

Charging different prices for electricity by the time of day has long been a tool used by electric utilities and approved by regulators to discourage the use of energy during peak periods and encourage consumption at off peak. Most such programs offer a relatively modest difference in the price between peak and off-peak periods (a ratio of less than 3:1), but most were aimed at reducing peak consumption rather than encouraging greater use of electricity.

Electrification provides the opportunity to rethink that policy. For example, the owner of an electric vehicle with an ability to recharge at home can choose when to start or stop recharging the vehicle. Small differences in the price are unlikely to encourage them to charge during periods when the cost to supply electricity is lower. Conversely, the availability of very low-cost charging may encourage electrification of other flexible services, such as domestic hot water heating, to make them more competitive with fossil fuel alternatives.

Furthermore, the issue of electricity rates is a sensitive one for policymakers, and electricity subsidies to protect consumers against price increases has become very common in the past few years, reaching $400 billion USD globally in 2022. Getting policymakers to support changes in electricity rates, where prices at certain periods will be higher than previously, is crucial for a successful program.

The Canadian province of Ontario provides an example where the regulator has worked closely with the government and stakeholders to introduce a new rate that supports electrification. In that province, virtually all customers have a smart meter and most residential customers are on default time-of-use rates which are set by the regulator, the Ontario Energy Board. The Ontario TOU rates have a relatively modest difference between the price at the peak hours and the off-peak hours (roughly a 2:1 ratio). The regulator had, on its own initiative, previously undertaken a number of alternative pricing pilot programs.  One of these programs, targeted toward electric vehicle owners, was able to demonstrate the effectiveness of an alternative rate, where prices would be very low at night and up to ten times higher during peak hours. This pilot program was highly effective at shifting consumption of EV-owning customers to overnight hours, when non-emitting generation (largely nuclear power, hydroelectric or wind) predominates, compared to peak hours, when natural gas is often the marginal fuel.

Some years later, the government asked the OEB to develop an alternative rate that would encourage shifting to overnight hours. The OEB developed a detailed proposal for which it also carried out a stakeholder consultation. The government approved of the new optional rate and amended a regulation to allow the OEB to implement it. The new rate has received the full support of the government. In fact, the government has taken ownership of the initiative: its press release announcing the implementation of the new rate mentions the regulator only in passing. The regulator chose not to issue any press release on its role in developing the new rate, releasing instead its price report outlining the new rates and how they were established, and more detailed information as to how the new rate would operate. The new rate has been progressively rolled out to customers across Ontario since May 1, 2023.

The Ontario Energy Board (OEB) has launched further pilot projects to explore innovative activities, services and business models within Ontario’s electricity and natural gas sectors, through a regulatory sandbox approach. The OEB Innovation Sandbox program was launched in 2019 to provide information services and project-specific support. Some successful case studies from the program include: (i) the proposal of a non-wires alternative with whole-home battery energy storage systems (BESS) for customers in hard-to-access, forested areas, aiming to provide reliable power during outages, with an expected reduction in outage hours by 50% or more. Despite challenges such as site suitability and compliance with safety standards, 39 BESS installations had significantly reduced outage times by August 2022. (ii) the analysis of customer-owned distributed energy resources (DERs) to meet rising electricity demand through North America’s first local electricity market at the distribution level, resulting in considerable peak demand reduction and efficient local capacity utilization, highlighting the potential of DERs to address increasing electricity demand efficiently.

Furthermore, in October 2023, the OEB allocated $1.5 million in one-time funding to six projects as part of the Innovation Sandbox Challenge, aimed at scaling pilot projects and devising novel methods to educate consumers about their part in the energy transition toward sustainability. The projects selected focus on enhancing customer engagement, enabling demand response participation, and facilitating energy transition understanding among various groups, including low-income and indigenous communities. Funding for these initiatives is sourced from administrative monetary penalties collected by the OEB.

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France 1

Addressing carbon content in solar PV procurement (France)

France, as it procures new renewable electricity, particularly solar energy, is increasingly considering the carbon footprint of the equipment used in generating power and its manufacturing. Since 2017, the Energy Regulatory Commission (Commission de Régulation de l’Énergie, CRE) has conducted 14 procurements for large solar farms, totaling over 10 gigawatts peak (GWp). The CRE has developed a tender evaluation methodology that allocates points based on various criteria (including the project’s price and environmental impact), with a significant portion of points dedicated to the embodied carbon content of the solar panels and equipment used. This approach incentivizes developers to select equipment with lower carbon content and directly impacts the selection of solar panels based on their manufacturing origin due to the differing carbon emissions associated with their production.

Context — problem/issue

In several jurisdictions we interviewed, regulators have responsibilities for carrying out or overseeing procurements of new renewable electricity generation. Although the primary objective of these procurements is to increase renewable energy generation and thereby decrease emissions from electricity supply, decarbonization objectives of governments are becoming broader. It has been shown that a large share of emissions attributed to France come through embedded emissions from manufactured imports. As such, the carbon dioxide emitted in producing the generating equipment is also a consideration in the procurement of that equipment. Solar panels produced in China, where most of the world’s panels are made, result in more emissions than solar panels made in low emissions jurisdictions, such as France, primarily because of the relative low emissions from electricity needed to manufacture the panel components.

In France, the government procures new renewable electricity generation sources, including solar photovoltaic, through tenders operated by the Energy Regulatory Commission (CRE).  Since 2017, the CRE has carried out 14 such procurements for large solar farms, procuring a total of over 10 GWp.

The CRE publishes its methodology for evaluating the applications known as the Cahier des Charges (which is drafted by the government). Central to the methodology is the rating of criteria according to a points system for which the maximum possible is 100 points, which are allocated to a small number of criteria. Currently, for ground-based solar photovoltaic installations, price is by far the most important criterion, with up to 70 points allocated based on the price offered (more points for a lower price). Other criteria include if the project will be developed on a site which is already environmentally degraded (worth nine points) or if the project is governed or financed by a local community (worth up to five points). The remaining 16 points are allocated according to the embodied carbon content of the production of the panels and related equipment. The intent is to provide an incentive for developers to consider explicitly the carbon content of the equipment they plan to use in the solar farm. All major components of the installation are considered from the manufacturing of the polysilicon used to the inverters employed. While developers are encouraged to produce a specific life cycle assessment for their project, the CRE also produces a default table of estimates per kg of material that can be used. The results vary by country primarily because of the different emissions associated with the electricity that is used to produce the components:

Default emissions factors for c-Si solar panel components for selected countries of origin
All figures are kg CO2 equivalent per kg of material (unless otherwise indicated)

Source: extracted from Table 3, Cahier des Charges (Commission de régulation de l’énergie (CRE)). (2023, November). (p 59-63)

Applicants must demonstrate that the embodied carbon content for their solar farm falls below a ceiling value (now 550 kg CO₂/kWp). Any proposal with total emissions per kWp above the ceiling will not be considered. Conversely, any proposal with carbon content below a floor level (currently 200 kg CO₂/kWp) will receive all 16 points. Those in between are awarded points according to the following formula.

Where
ECS = the CO₂ emissions intensity of the project (kg CO₂/kWp)
NC       = Number of points to be awarded to the project for its carbon content
NCo     = Maximum number of points (16)
ECSsup = The ceiling value for emissions intensity (550 kg CO₂/kWp)
ECSinf   = The floor value for emissions intensity (200 kg CO₂/kWp)

In effect, what a points award does is reward lower carbon content in the same way a lower price is rewarded, for which there is a similar formula. It is therefore possible to deduce that a decrease of 38 kg CO₂/kWp earns the same number of points as a decrease of 1 euro per MWh in the bid price. This implies a carbon price of around 480 euros per tonne of CO₂ avoided.[1]

The CRE administers the tender, makes awards to the points system, and then publishes a (redacted) synthesis report on the tender results. The transparency that the regulator uses is helpful to both policymakers and potential bidders. They can learn the average prices paid, the share of bids accepted and the performance of the bids against the various criteria. This includes the mean carbon content, which in the latest tender has stayed within a range of around 400-500 kg CO₂/kWp. They also publish the national origin of the panels; in the latest round, nearly all the panels came from China, although in earlier rounds, European and American suppliers had played a significant role.

[1] The implied carbon price is calculated by assuming the bidder increases their bid price to offset their lower carbon content.  The additional revenue is discounted at 4%.

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Germany

Changes in transmission permitting — becoming more deeply involved in transmission line siting (Germany)

Germany’s ambitious Energiewende policy, aimed at transitioning from nuclear and coal energy to renewable sources, necessitated significant investments in transmission to link wind and solar generation in the north and east to demand in the west and southwest. Over 7,500 km of new or upgraded power lines were estimated to be needed. From 2009, six legislative reforms over 13 years aimed at accelerating the transmission expansion, granting the German regulator (Bundesnetzagentur) increased authority in the planning, approval and environmental assessment of transmission projects, and recently introduced provisions to start construction before final approval under certain conditions. Despite these efforts, significant projects have faced delays due to local opposition, permitting challenges, and the complexities of underground construction, which increased both costs and time. As of October 2023, only a fraction of the required line approvals had been secured, though the pace is expected to pick up following final planning approvals.

Context — Problem/Issue

The rise in the share of variable renewable energy will increase the importance of investment in transmission and distribution to link the new generation resources to the loads. It has long been recognized that the speed at which new transmission facilities have been developed could become a brake, rather than an accelerator, of the clean energy transition. Greater regulatory involvement in transmission siting has been suggested as one solution to this issue.

Germany’s Energiewende policy aims to replace nuclear energy (which was fully phased out in April 2023) and eventually coal-fired generation with renewable sources of energy, mainly wind and solar photovoltaic. As most of the wind resources (and all of the offshore wind resources) are located in the north and east of the country, compared to most of the industrial demand and retiring power plants that are located at the west and southwest parts of Germany, it was long recognized that major investments in transmission would be required to link the new supplies with demand. The government estimated that over 7,500 km of new power lines were needed to be upgraded or developed, and the government started to adapt the country’s electricity transmission grid through a coordinated network expansion.

The urgent need for grid expansion for the energy transition was first set by law in the Power Grid Expansion Act (EnLAG) of 2009 that aimed, among other things, to complete priority transmission lines by 2015. It listed twenty-two priority projects that are the exclusive responsibility of the federal states, referred to as the “start network,” since they would be the basis for any further transmission system expansion in the country. This was further enhanced in 2011 with the Grid Expansion Acceleration Act (NABEG) that established the planning of network expansion projects that crossed interstate or international borders. The NABEG set up responsibilities to the energy regulator Bundesnetzagentur (BNetzA) and set out the detailed planning process for the electricity network development plan, which the BNetzA must approve. Further enhancements were made in 2013 when the Federal Requirements Plan Act (BBPlG) came into force that defines the starting and finishing points of the identified projects, and established BNetzA as responsible for selecting the line routing for interstate or international projects. An additional change in 2015 was particularly significant in terms of its impact on cost and timing of transmission projects. An amendment to the Federal Requirements Plan Act was made that stipulates, by general rule, that underground cables are the standard for high-voltage projects, hence, only under strictly limited circumstances can overhead line sections be used. Still more changes were made in 2019 through an amendment to the Grid Expansion Acceleration Act (NABEG 2.0). The changes involved the legalization and standardization of compensation procedures to landowners affected by the network expansion, the establishment of a national offshore test field to system security, and the regulation of network bottleneck management aiming to a more efficient and cost-effective management in the future. Further modifications were made in 2022 when new rules were put in place that allow the BNetzA to grant approval to start construction work before the final planning approval is received. This allows the project developer to begin construction; however, the activities would need to be reversed and the original condition of the land restored if final approval is ultimately not given.

This series of six legislative reforms over 13 years has ensured that one of the BNetzA’s main tasks in the energy sector is “promoting efficient permit granting processes for Germany’s extra-high voltage network to accommodate the growing importance of renewable energy.”  Today, specific powers of the regulator with respect to transmission planning and siting include:  (i) Approving the overall framework for network expansion developed by the four transmission system operators (TSOs). The BNetzA holds a public consultation on the proposals and approves the framework, which binds the TSOs for the system plans; (ii) Reviewing and approving the network development plans of the transmission system operators, which include the corridors needed for grid expansion. These plans (NEP) are updated regularly and progress on implementation must be reported annually; (iii) Submitting to the government the NEP as a draft for the Federal Requirements plan that identifies the priority transmission expansion projects and includes an environmental report to the government at least every four years. The government submits the Federal Requirements Plan Act draft to the parliament.  These plans become binding upon adoption by the parliament; (iv)  Assessing the environmental impact of transmission projects that cross state or national boundaries, establishing the exact routes for the projects; and (v) Allowing early sectoral construction to begin on limited portions of the project before final planning approval is obtained to accelerate overall project completion. These new powers were in addition to their existing authorities to set network tariffs for the TSOs and to ensure an efficient level of investment in transmission.

The three electricity highways consist of direct current ultra-high voltage-lines known as SuedLink, SuedOstLink and the A Corridor that comprises the A-Nord and the Ultranet projects. The BNetzA had originally started the approval procedures for these three major electricity highways in 2013, with the intention that all three lines would be in operation by the end of 2022, the planned phaseout date for nuclear power plants. Despite all the regulatory changes made to speed up planning and permitting, none of the projects are yet operational. The three projects started construction in 2023. Despite the possibility for sectoral approval and constructions, direct current connection lines cannot become operational in sections, but only as a whole.

In the case of the SuedLink line, strong local objections regarding people not wanting the lines to affect their lands (“not in my backyard concerns”), and concerns about the technology and its further relation to policy, have considerably delayed the project. The project was originally expected to be finished by the end of 2022, but now, with sectoral construction just started in September 2023, the project will not be in service until 2028. Additional delays have been caused due to permitting and compensation bottlenecks; tens of thousands of landowners need to be approached, not an easy nor fast task. Undergrounding the line has also increased costs and time both to redesign the project and will take longer to construct.

SuedOstLink has suffered similar delays. Thanks to the acceleration of permitting procedures, SuedOstLink first converter station just started construction in March 2023; the permit’s approval only took seven months and is scheduled for completion in 2025.

The projects known as A-Nord and Ultranet, that are part of Corridor A (of about 600 km in total), received siting approval in 2021. Small sections of the A-Nord part of the project (totaling 6 km in length) began construction in October 2023, thanks to a provisional approval of early start of construction from BNetzA in October 2023. Final planning approval is expected by 2024 and completion of the line is now expected in 2027. The Ultranet project, which does not require undergrounding, since it will mostly be using existing power lines, has yet to begin construction but aims to be completed in 2025.

Despite all its expanded authorities over the approval of 7,400 km of new high voltage power lines, the BNetzA is not responsible for the 14,000 permits that must be issued by local and state authorities. BNetzA does monitor the status of these approvals and has found that by the end of October 2023 only 857 km of lines have the necessary approvals. It is worth noting that under new legislation, the lack of final planning approval (and hence permit issuance) is no longer a barrier to beginning construction and that the rate of permits issue is expected to accelerate beginning in mid-2024 after final approvals are received.

The BNetzA expects that permits covering an additional 4,400 km of lines are expected by mid-2025 which will also cover most of the Suedlink and SuedOstLink projects.

In summary, giving the regulator expanded authority for transmission line approvals did not, in this instance, result in an ability to proceed quickly with major transmission expansions needed to support the energy transition in Germany.  Six legislative reforms over 13 years have improved matters but overcoming local environmental and acceptance barriers have remained the main obstacles.

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Australia AER

Dealing with a loss of gas customers- Addressing implications of electrification: gas disconnection policy (Australia)

Regulators have just begun to grapple with the questions of the future of the natural gas network.  The issue was explored in depth in an information paper: Regulating gas pipelines under uncertainty published by the Australian Energy Regulator (AER). The AER was also responsible for changing policy on the recovery of gas disconnection costs, reducing disconnection charges driven by concerns about safety in light of the increasing number of households disconnecting from the gas grid.

Context — Problem/Issue

A government’s decarbonization policy will have implications for the natural gas networks and how they are regulated. Regulations may prohibit new gas connections and subsidies may encourage electrification.  Demand for natural gas is expected to decline over time.

As noted in Chapter 2 of the report, the Australian Energy Regulator (AER) has already begun to think about the long-term implications of a reduction in natural gas use by households in its information paper, Regulating gas pipelines under uncertainty. However, AER has also recognized that this is not a purely theoretical issue and contended with the issue in its latest hearing on a gas distributor (Gas Net Australia — which serves the state of Victoria), leading to a final decision published in June 2023. This included proposals from the gas distributor such as the pass through of carbon emissions permit costs (which was granted), and a request for accelerated depreciation of assets (which was granted only in part, to limit rate increases).  One of the more surprising issues raised related to gas disconnections, specifically how much to charge residential customers who decide that they wish to disconnect from the gas system.

When a customer ceases taking gas service and wishes to disconnect permanently from the gas system, safety requirements, set by the gas safety regulator in Victoria (Energy Safe Victoria), mean that the connection pipe from the gas main to the property should be removed and the gas main sealed at the connection point. Other options, such as disconnecting the meter and capping the pipe, are not considered sufficiently safe. The customer requesting disconnection is responsible for paying the disconnection costs, which are estimated to be around $1000 AUD per disconnection. With increasing electrification of customers (Victoria has banned new gas connections), the number of small customers getting off gas has significantly increased and can be expected to increase in the future.  Faced with high disconnection costs, however, many of these customers are instead opting for temporary disconnection, which is much cheaper but is neither a permanent nor a safe solution when gas is no longer needed. Concerned about the safety of this practice, the regulator considered whether to do away with disconnection charges altogether to ensure all departing customers were safely disconnected or retaining the full cost charge which would minimize the impacts of the departure on other customers. In the end, the regulator decided to adopt a hybrid approach: it cut the disconnection fee to $220 AUD per customer, less than a quarter of the fully allocated cost of disconnection, with the remainder of the costs to be recovered from other customers through the rates (the haulage tariff). It also recognized, however, that shifting costs onto remaining customers could not be a permanent answer:

This is not a long-term solution. Combined with declining throughput on remaining connections, it will put upwards pressure on haulage tariffs in the 2023–28 period until a more sustainable solution is identified. If, in future periods, we see further decline in demand and an increase in customers leaving the network, the upwards pressure on tariffs for remaining customers will only grow.

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Mexico

Efficiency mandates and externalities internalization: shaping renewable energy through regulatory insight, policy, legal and regulatory adaptation (Mexico)

Mexico’s energy regulator, the Comisión Reguladora de Energía (CRE), is an example of a relatively “early mover” in finding creative ways to incorporate decarbonization into regulatory decision-making. In the 1990s and early 2000s, the CRE effectively used its market efficiency mandate to support renewable energy sources, despite lacking a specific directive for clean energy. This strategy included interpreting market efficiency as addressing environmental externalities and was reinforced by subsequent policy, legal and regulatory modifications in Mexico which explicitly endorsed clean energy initiatives. Key regulatory measures, such as specific methodologies for cost considerations of renewable energy, exemplify the CRE’s indirect yet impactful role in promoting renewable energy development.

Who’s the Regulator?

The Comisión Reguladora de Energía (CRE, Energy Regulatory Commission) operates as an autonomous entity under the Ministry of Energy, with self-governance in technical and operational matters. Its principal mandate encompasses the regulation and oversight of the natural gas and electricity sectors, including the activities related to the extraction, refinement and distribution of hydrocarbon resources, as well as the generation, distribution and commercialization of electricity. Moreover, the CRE is tasked with the approval and implementation of regulatory frameworks and methodologies that dictate the interactions between energy suppliers, distributors and consumers, including setting tariffs, defining service standards, ensuring fair market practices, and the issuance and withdrawal of licenses for private power producers.

Context — Problem/Issue

Before a major energy reform in Mexico in 2013,[1] Mexico’s energy sector was characterized by state control and limited private sector involvement. The energy market, particularly for electricity and oil, was predominantly run by state-owned enterprises. Pemex held a monopoly within the oil sector and the Comisión Federal de Electricidad (CFE, Federal Electricity Commission) in the electricity sector, limiting private investment and participation. The market dynamics were largely controlled by government policies, with a focus on conventional energy sources like oil and gas and less emphasis on renewable energy sources. The energy sector was, and still is, heavily reliant on fossil fuels, with a significant portion of the economy depending on oil exports.[2]

Most greenhouse gas emissions in Mexico are produced by the energy sector, in part because historically most of electricity was generated with fossil fuels (mainly oil and gas). To address this, in the 1990s and early 2000s, the CRE utilized its mandate for market efficiency to indirectly promote renewable energy sources (RES), despite not having an explicit directive for clean energy. This approach hinged on interpreting market efficiency to include addressing externalities, a perspective bolstered later by the LAERFTE legislation (see below), which explicitly recognized clean energy mandates. In 1998, the CRE issued the methodology for determining charges for electric power transmission services (RES/083/98) and its subsequent modification in 1999  (RES/254/99). Later, in 2001, it published the methodology for setting transmission service charges, contract models, and agreements between suppliers, exclusively for power plants with renewable sources (RES/140/2001). These examples showcase how regulators can significantly influence renewable energy promotion through their efficiency mandates, even without direct authorization to promote renewables.

In 2007, the government issued the National Development Plan 2007-2012 that focused sustainable development as a key aspect of public policy. In the electricity industry, this meant encouraging methods to lessen the ecological footprint, including the adoption of renewable energy sources. At that time, renewable energy sources were not very competitive against traditional technologies (like gas), particularly when the environmental and social costs of conventional fossil fuel generation were not considered. Mexico, nonetheless, has a lot of potential for renewable energy sources, which fostered discussion among the government to implement the consideration of externalities into the analysis, in order to make renewable energy sources more competitive.

The CRE, in 2008, was one of the key stakeholders supporting a change in the law to explicitly recognize environmental externalities in acquisition of new electricity generation resources.  The new law, known as Ley para el Aprovechamiento de Energías Renovables y el Financiamiento de la Transición Energética (LAERFTE, Law for the Use of Renewable Energies and the Energy Transition Financing), along with the General Law on Climate Change (which stated that the Ministry of Energy shall seek at least 65% of clean energies in electric generation by 2024, in coordination with CFE and CRE) and the Ley del Servicio Público de Energía Eléctrica (Public Electricity Service Law), mandated developing a methodology to assess the externalities associated with electricity generation from both renewable and non-renewable sources across different generation capacities. With these laws, policymakers aimed to foster a more sustainable and environmentally responsible energy sector in Mexico. The emphasis is on internalizing the external costs associated with environmental and social impacts caused by the construction and operation of new generation plants, which traditionally may not have been captured by market mechanisms. This approach helps ensure that expansion strategies are not only cost-effective but also socially and environmentally sustainable​​​​.

The LAERFTE explicitly recognized clean energy mandates for CRE, which fostered the publication of methodologies to calculate fees for transmission services that suppliers offer to those generating electricity from renewable sources or through efficient cogeneration (RES/066/2010 and RES/194/2010). According to Francisco Salazar (Coordinator of ICER and former President of CRE, congressman and Chair of the Mexican Chapter of the World Energy Council), these fees aimed to fix the market shortcoming of not considering positive externalities into the calculation by reducing the cost of clean energy in order to achieve the desired social balance. Considering the geographical constraints of clean energy projects, CRE implemented a “green postage stamp type rate” as a uniform rate system based on usage levels, initially determined by long-term marginal costs and the short-term economic benefits of replacing costly fuel oil (with rates adjusted monthly for inflation). Salazar also noted that regulatory measures like these create positive externalities for renewable energy sources, not only encouraging renewable energy use but also driving down production costs due to increased demand. This benefits consumers through a self-reinforcing cycle of cost reduction and technological advancement.

The aforementioned laws paved the way toward publication of the methodology to value externalities associated with electricity generation in Mexico in December 2012 by the Secretaría de Energía (SENER, Ministry of Energy). This methodology set rules on how to include externalities as an operational cost in the dispatch of electricity and provided understanding of the cost-benefit analysis of investment projects for electric generation. The CRE held direct participation in the working group, led by SENER, for the development of this methodology. The aim was to encourage investment in low-environmental-impact technologies, by integrating the costs of social and environmental externalities and emissions into the selection of sources for electric power generation, thereby favoring investments in low-impact technologies and increasing generation from environmentally friendly power plants.

Although substantial legal changes came into force in 2015 with the publication of Ley de Transición Energética (Law of Energy Transition) that repealed the LAERFTE, externalities continue to be considered as part of electricity planning in Mexico, and the CRE is one of the entities involved in developing that methodology. One of the CRE’s significant responsibilities is to establish methodologies for calculating compensation for services rendered among entities within the energy sector, thereby promoting transparency and fairness in commercial relationships. With the enactment of the LAERFTE, the CRE was endowed with expanded powers to regulate and promote renewable energy sources. In January 2024, the CRE issued the General Criteria for the evaluation of the net benefit of works requested by private parties to be included in the Expansion and Modernization Programs of the National Transmission Network and the elements of the General Distribution Networks corresponding to the Wholesale Electricity Market, as well as for the transfer and acquisition of private networks (based on Art. 34 and 44 of the Electric Industry Law — Ley de la Industria Eléctrica), which contemplates the benefit from reduction of externalities.

Note: During the development of this Project, RAP did not interview the Mexican Ministry of Energy nor the Energy Regulatory Commission. We were nonetheless able to gather valuable information regarding the example described herein from an interview held with Francisco Salazar, Coordinator of ICER and former President of CRE, congressman and Chair of the Mexican Chapter of the World Energy Council (WEC), who had firsthand information on the matter.

[1] This energy reform aimed to liberalize the sector, by opening it up to private national and foreign investment, fostering a competitive market environment. This was expected to bring in new technologies, increase efficiency and diversify energy production, including a greater focus on renewable energy. The reform was seen as a significant change in regulation, potentially affecting the energy sector’s structure and the characteristics of energy use and production in Mexico.

[2] Mexico was one of the largest oil producers, with its economy heavily dependent on crude oil exports that contributed substantially to government revenues. The country, however, lacked the industrial capacity to meet its own demand for oil derivatives, leading to imports and relatively higher prices for these products when compared to prices in countries like the U.S.

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Australia AEMC and AER

Interpreting new requirements to consider decarbonization in regulatory decision making (Australia)

Several of the regulators RAP spoke to suggested that a statutory requirement that recognizes the need to achieve decarbonization goals would be useful for their decision making. Australia has recently passed legislation requiring regulators to explicitly weigh these decarbonization goals in their regulatory decision making.

Context — Problem/Issue

One issue that came up repeatedly in interviews with regulators was the value of having an explicit objective to address decarbonization, along with more traditional objectives such as price, quality, safety, reliability and security of supply. The most practical implication of such an objective is that it would be relatively straightforward to include the value of saved emissions in regulatory decision making. Another example of its usefulness regarded efforts by gas utilities to reduce methane losses: these could not be ratepayer funded on decarbonization grounds if there were no explicit objective to do so.

Australia is one of two jurisdictions (along with the United Kingdom) where a change to incorporate decarbonization as one of the regulatory objectives has recently been made. The legislation in Australia, known as the Statutes Amendment (National Energy Laws) (Emissions Reduction Objectives) Act 2023, received Royal Assent on September 21, 2023, and incorporates decarbonization objectives in the national laws respecting electricity, natural gas and energy retailing. The decarbonization objective for all three laws is the same. It requires energy regulators (Australian Energy Market Commission or AEMC and Australian Energy Regulator or AER) as well as the system operator (the AEMO or Australian Energy Market Operator) to give regard to the following objective that the long-term interests of consumers are to be served by:

the achievement of targets set by a participating jurisdiction— (i) for reducing Australia’s greenhouse gas emissions; or (ii) that are likely to contribute to reducing Australia’s greenhouse gas emissions.

The AEMC and the AER have each published guidance as to how they will interpret the new objective in their decision making. In the case of the AEMC, which makes and amends the rules for the energy markets, they have emphasized that inclusion of the new objective elevates the role of decarbonization in their decisions: whereas before such targets were part of the external context, now they are one of the central considerations (along with price, quality, safety, reliability and security of supply) that the AEMC must balance in making its decisions. The new objective also means that changes to the market rules for electricity or natural gas could be proposed based on achieving emissions reduction targets, something that would not have been a sufficient criterion before. For each proposed rule change, the AEMC will assess whether the emissions reduction impact is likely to be a material part of the benefits (or costs) of the change that is being proposed.  If so, it will address the emissions objective and how it is being evaluated in its consultation and decision documents. The evaluation could be either quantitative or qualitative depending on the context. One issue if a quantitative assessment is used, is the need to use an appropriate methodology to value emissions reductions. The AER and AEMC plan to rely on the methodology being developed by the Commonwealth government. Separately, the AEMC has published the targets for jurisdiction (state, territory or commonwealth) that it (and the AER) must have regard to in its decision making.

The AEMC is also amending the national electricity and gas rules to harmonize with the new objective. These changes include requiring network and pipeline operators to consider emissions benefits and costs in their regulated expenditure proposals, and in applying the regulatory investment tests.

The AER, who regulates the gas and electricity networks and oversees energy retailing, published its own guidance on how it deals with the new objective. It indicates a requirement to consider the new objective for applications currently underway for electricity transmitters and distributors. They point to a need to revise the regulatory investment tests that they apply to the network investment plans of electricity transmitters and distributors to estimate the carbon dioxide savings that would be made by the investment, as well as the value of those savings, in determining whether an investment proposal should be approved.  The AER also identifies the inclusion of the value of emissions saving in evaluating investments by network owners to support distributed energy resources (now referred to as consumer energy resources by the AER) as another area likely to be affected.

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St. Lucia

Balancing growth and grid stability: revising solar PV installation limits and pricing in Saint Lucia's transition to renewable energy (Saint Lucia)

The decreasing costs of solar photovoltaic technology have made rooftop installations increasingly appealing across the Caribbean, where fossil fuels have been predominantly used for electricity generation. The swift adoption of solar photovoltaic, however, has raised concerns about its effect on other consumers, which led the regulator in Saint Lucia, National Utilities Regulatory Commission (NURC), to establish limits on installations of 5 kilowatt (kW) for residential and 25kW for commercial customers. Such limitations, as well as the pricing mechanism for renewable energy sources are currently under revision.

Context — Problem/Issue

Saint Lucia, like other Caribbean islands, faces significant climate risks due to its geographical location and economic reliance on climate-sensitive sectors such as agriculture and tourism. The country’s energy sector is heavily reliant on fossil fuel imports (oil products, mainly diesel) for electricity generation, which results in one of the highest electricity prices in the world, with families paying an average of $0.44 per kilowatt (USD) hour (triple the rate paid in other countries, like the United States). This significantly undermines the island’s economic competitiveness by escalating the operational costs for businesses and heightening financial instability within the country. To tackle this, the government has been proactively shaping the trajectory of its energy sector, crafting a detailed national energy policy in 2010 that aims to lower the cost and volatility of electricity prices and reduce the island’s dependence on imported oil by integrating renewable energy into the electricity generation mix. In 2018, the National Energy Transition Strategy (NETS) was issued to pave the way for diversification of energy sources, and integration of renewable energy into its power generation landscape. This strategy outlines a comprehensive action plan for achieving a sustainable, reliable, cost-effective and equitable electricity sector. It emphasizes the importance of utilizing local resources and includes a detailed 20-year strategy, along with a suite of optimal near-term projects.

The NETS suggests that a mix of utility-owned solar, distributed solar, wind, diesel and energy storage presents the best economic outcome for Saint Lucia, aiming for about 40% renewable energy penetration and exploring the potential for geothermal energy to further increase this share. Additionally, efforts have been made to expand and enhance the rural electrification network, improving its distribution capacity and reach. Saint Lucia has a goal of reaching 35% of renewable energy penetration by 2025, and a 7% reduction in greenhouse gas emissions in the energy sector by 2030, relative to the 2010 (NDCs).

The National Utilities Regulatory Commission (NURC) was established in 2016 to oversee the water supply and sewerage services and regulate the electricity system, including the introduction and integration of renewable energy sources. It regulates the vertically integrated utility, the Saint Lucia Electricity Services Limited (LUCELEC), which is responsible for generation, transmission and distribution of electricity. The Electricity Supply (Amendment) Act of 2016 opened the door to competition in the generation of electricity from renewable sources. LUCELEC, however, retains the exclusive rights to generate electricity from fossil fuels and remains the sole entity for transmission and distribution up until 2045.

The NURC has a specific mandate to ensure compliance with the Government’s international and regional obligations including its greenhouse gas emissions reduction commitments, relating to utility supply services. The NURC plays a crucial role in guiding the transition to a low-carbon energy system, ensuring that LUCELEC is aligned with the government’s energy transition policy. To that end, the NURC has been advancing on the regulatory framework, including the Application Procedure for Solar PV Generation, that sets the guidelines for those who wish to generate electricity (with capacity limits of 5 kilowatts (kW) for residential and 25kW for commercial usage) through solar photovoltaic and interconnect their system to LUCELEC’s grid. This has allowed a growing contribution from distributed generators, notably domestic and commercial customers equipped with solar photovoltaic systems, who are currently engaged in a net metering program, which allows them to sell excess electricity back to the grid. This arrangement is under ongoing review, through a public consultation on renewable energy pricing and capacity limits held in April 2023, and will likely evolve with future sector legislation. This consultation also encompassed the analysis of the pricing strategy for renewable energy as the current net metering approach was unsustainable by not considering the grid’s maintenance expenses.

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France 2

Progressive hydrogen initiatives and regulatory framework development to advance decarbonization (France)

France is intensifying its decarbonization efforts, including a strategic focus on hydrogen. The country’s policy on hydrogen includes initiatives for a tender-based support mechanism for low-carbon and renewable hydrogen production and incentives to promote sustainable practices. The Commission de Régulation de l’Énergie (CRE — French Energy Regulatory Commission) is actively contributing to the hydrogen strategy, with recommendations to develop a regulatory framework for hydrogen infrastructure including the redeployment of natural gas infrastructure to support the sector’s growth, as well as reviewing the government’s proposed support mechanism.

Context — Problem/Issue

France is actively pursuing decarbonization and is currently embracing hydrogen as part of its broader strategy to achieve carbon neutrality by 2050. Hydrogen is a component of France’s latest national energy and climate plan (NECP), updated in November 2023, that states its goal to achieve a 30% reduction in final energy consumption by 2030 (compared to 2012 levels); a 58% increase of decarbonized energy by 2030 and 71% by 2035; a 45% increase of renewables in heating and cooling by 2030 and 55% by 2035; and a 15% injection of renewable gas into the network by 2030.

The NECP mentions the National Hydrogen Strategy, aimed at fostering the development of decarbonized hydrogen, with a significant emphasis on transforming heavy mobility into hydrogen-based systems. Specifically, France’s updated hydrogen initiatives include:

• A tender-based support mechanism for the production of low-carbon hydrogen (open for consultation until October 20, 2023), aiming to fund projects in both capital and operational expenses and targeting up to 1 gigawatt of production capacity in recognition of the significant portion of hydrogen production that electricity costs constitute.
• The introduction of either a tax or an incentive scheme within the Azote Climate Impact Fund (TIBICA/MIBICA) to promote the shift towards less carbon-intensive solutions, aiming to level the playing field between domestically produced and imported fertilizers, while supporting sustainable farming practices.
• The potential expansion of the Incentive Tax on the Use of Renewable Energy in Transportation (TIRUERT). As of January 1, 2023, renewable hydrogen is eligible for credits under the TIRUERT scheme, which allows the contribution of hydrogen to be valued in the reduction of the carbon footprint of conventional fuel production (refining), biofuels, or e-fuels of all kinds. From January 1, 2024, low-carbon hydrogen will also be eligible for TIRUERT. The incorporation of targets from TIRUERT in road fuels are expected to continue increasing to meet the RED3 directive’s goal of at least a 14.5% reduction in greenhouse gas emissions from fuels by 2030. The NECP also contemplates hydrogen infrastructure, moving toward the completion of a priority transport network by 2026, along with potential regulatory options. This consideration also extends to hydrogen imports and addresses the challenges related to energy targets by 2030, prompting the government to plan for hydrogen import structures (or derivatives) post-2030.

To support the government’s direction on hydrogen, the CRE (established in March 2000) has been active in outlining its policy with respect to conversion of existing gas networks and the status of regulating dedicated hydrogen infrastructure. These were outlined in the CRE’s Contribution to the French Energy and Climate Strategy, issued in September 2023, which drew from five years of forward-looking exercises with key stakeholders, including the recommendation to issue regulation for low-carbon hydrogen infrastructure to meet climate objectives and energy sovereignty, for which CRE is focused on ensuring transparent and non-discriminatory access to hydrogen transport infrastructure.

In its contribution, the CRE states that as hydrogen is expected to play an increasingly significant role in France’s energy mix in the future certain gas infrastructure elements, such as gas transport pipelines and salt cavern storage, could eventually be converted for hydrogen use. CRE plans to further investigate the conditions under which these conversions might feasibly occur. The CRE also identifies the need, in the medium term, to develop a low-carbon hydrogen regulatory framework for dedicated infrastructures. Substantial public subsidies for its development would be required, given hydrogen’s current high prices. Public efforts should focus on sectors where hydrogen is essential, primarily for industrial decarbonization (steel, hydrocarbon refining, fertilizer production, cement industry, etc.) and heavy transport, including sustainable fuel production for maritime and aviation sectors. Technology neutrality among low-carbon hydrogen technologies should be considered: hydrogen produced by electrolysis from low-carbon electricity (renewable or nuclear) or hydrogen from fossil fuels with carbon capture and storage (CCS/CCUS).

Regarding hydrogen infrastructure, a progressive approach is being adopted. Significant infrastructures (long-distance networks, storage) may be subject to regulation, and efforts are being made in France and Europe to develop an appropriate regulatory framework. The CRE advises, however, that it is too soon to finalize the regulatory framework,  especially in terms of applying a complete third-party access regime to all hydrogen sector infrastructures. Public support should focus on the most mature uses and areas where these uses are concentrated to foster the emergence of territorial hubs near industrial zones and major European heavy transport routes. The interconnection of these hubs through large-scale hydrogen transport infrastructure will be considered progressively, depending on the development of various uses, which remains uncertain at this stage.

In addition, the CRE has reviewed the government’s proposed support mechanism for the production of low carbon and renewable hydrogen, which aims to back 1 gigawatt of electrolyzers over the next four years with approximately €4 billion in public support. The CRE evaluated the proposal and in November 2023 provided a detailed opinion, providing some key suggestions that include avoiding competitive dialogues to expedite the selection process, favoring operational aid over investment aid to ensure project viability, and offering CRE’s technical support if necessary. CRE also emphasizes the importance of clear support duration, effective management of project delays and special consideration for newly created companies to leverage their leaders’ past experience. These recommendations aim to streamline the hydrogen production support process, ensuring projects are financially and technically feasible and encouraging broader participation in the sector.

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Kenya

EPRA's regulatory innovations fueling renewable adoption and EV infrastructure (Kenya)

In Kenya, the shift toward renewable energy and improved energy efficiency is being significantly supported by the Energy and Petroleum Regulatory Authority (EPRA). To facilitate this transition, EPRA has introduced several key initiatives, including special tariffs for electric vehicle (EV) charging under the E-Mobility category and guidelines for the establishment and operation of EV charging and battery swapping infrastructure. These measures aim to make EV charging facilities widely accessible, encourage the rapid adoption of electric vehicles, and ensure charging rates are affordable for both EV owners and operators. This approach reflects EPRA’s commitment to foster a sustainable energy landscape, promote the use of renewable resources, and support Kenya’s ambitious goal of a 100% renewable energy share by 2030 amidst challenges like data management in tracking environmental outcomes and decarbonization efforts.

Context — Problem/Issue

In the past, Kenya’s electricity generation heavily relied on oil and hydropower. Electricity generation is dominated by the Kenya Electricity Generating Company (KenGen) but independent power producers are steadily increasing their market share.

Kenya has made significant progress in both ensuring electricity access and reducing emissions from power generation. The country’s electrification rate saw a significant jump from 19% in 2010 to 77% in 2021. Over the same period, emissions from power generation have halved, despite a doubling of demand, thanks to robust growth in geothermal and wind resources in particular. In 2021, 90% of generation came from renewable sources led by geothermal (41%), followed by hydro (30%) and wind (16%), with bioenergy and solar accounting for 2% and 1% respectively. In 2022, Kenya achieved 78% of renewable installed capacity. The government has set a greenhouse gas emissions reduction target of 32% by 2030 (compared to business as usual), and a goal of achieving a 100% renewable share in the power mix by 2030.

The EPRA was implemented by the Energy Act of 2019, as the independent regulatory authority tasked with the technical and economic oversight of Kenya’s electricity, petroleum (including upstream, midstream and downstream operations), coal development and renewable energy sectors. Its functions include issuing licenses, economic regulation (tariff review and approval), construction permits, overview of minigrids, enforcing compliance, and complaints and dispute resolution. It has specific mandates to adopt and implement measures of energy efficiency, to establish specific energy consumption benchmarks for energy consumers, to improve energy demand management to promote rational use of energy and reduce the use of non-renewable energy sources, to facilitate renewable sources deployment, to educate the public regarding energy demand management and conservation, and to maintain energy sector data, among others. EPRA also holds advisory participation and constant communication with the government regarding energy policies, climate change, minimum performance standards and energy efficiency.

In Kenya, the electrification of the transportation sector is a critical topic in the fight against climate change, especially since transport contributes to over 13% of the nation’s total greenhouse gas emissions. To further push decarbonization, EPRA issued in September 2023 the Electric Vehicle (EV) Charging and Battery Swapping Infrastructure Guidelines, which aimed at streamlining the development and operation of EV charging infrastructure in Kenya. These guidelines emphasize the importance of making EV charging facilities widely accessible, promoting the swift adoption of electric vehicles, and ensuring affordable charging rates for both EV owners and charging station operators. Furthermore, the guidelines introduce regulations for battery swapping stations, including the requirement for battery management systems to monitor and analyze battery data for safety. The guidelines also detail the tariffs for electricity supplied to EV charging and battery swapping stations, as determined and published by EPRA. They state that the same tariff shall be applicable for e-mobility and domestic charging and that charging stations and points will require separate metering arrangements to ensure that electricity consumption is accurately recorded and billed according to the specified tariffs for EV charging. These tariff guidelines followed EPRA’s earlier approval of e-mobility tariffs, with a unique subsidized tariff for charging stations. In March 2023, EPRA issued a retail electricity tariff review to update tariffs initially set in July 2018, introducing a special tariff for the e-mobility category for charging electric vehicles (paragraph 26). The newly introduced e-mobility tariff is fixed until the 2025/2026 period, at 16 Kenyan shillings per kilowatt-hour (kWh) (about 0.11 USD) for energy usage during peak hours and 8 Kenyan shillings per kWh (about 0.05 USD) during off-peak hours (for usage from 200 to 15,000 kWh in both cases). This rate excludes taxes and additional charges that consumers will incur. By 2022, Kenya was home to approximately 350 registered electric vehicles, which increased to 1350 by February 2023. EPRA plans to closely observe how this new consumer group adapts to the special tariff, using these insights to guide future regulatory decisions. This retail electricity tariff review contemplated the approval of additional tariffs and customer categories, such as (i) Bulk Tariffs to allow large consumers to buy power at bulk and retail the same to their end customers; (ii) the Time of Use tariff for small commercial customers, with a 50% discount on the energy charge; and (iii) the introduction of a new domestic customer category (with consumption between 31 and 100 kWh per month) in order to promote electric/clean cooking and energy transition in support of climate change mitigation and related initiatives. EPRA was unable at this stage to provide a specific tariff to the domestic category, given that the e-cooking industry is in nascent stages and there is insufficient data to model an accurate tariff. The government has set the goal to reach universal clean cooking by 2028, for which EPRA, with a specific mandate regarding energy efficiency, must set the regulatory framework to achieve the government’s policy and objectives.

Energy Sector Data Management

One challenge on the path to environmental sustainability and decarbonization is the acquisition and management of relevant data. EPRA, despite having an explicit mandate for energy sector data collection and management, has encountered some struggles due to the lack of complete digitalization of the energy sector. For effective monitoring of environmental outcomes and tracking decarbonization efforts, a robust system for data collection and analysis is crucial. While gathering data on the supply side, as well as understanding the broader demand and supply dynamics is relatively straightforward, the real difficulty lies in obtaining detailed usage and activity data. This is particularly true for areas not connected to the grid, mainly consuming biomass or biofuels. To address this, the implementation of advanced data management systems, including the deployment of smart meters and the digitization of the energy system, is essential. Such technology would enable a clearer understanding of household energy use, pinpointing where more targeted actions are necessary for reducing fossil fuel dependency and enhancing electricity efficiency. The regulator indicated that it would be desirable to have further peer to peer exchanges and support in terms of data management through shared frameworks, guidelines and best practices designed to initiate and track the progress of the energy transition.

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Barbados

Regulatory initiatives for enhanced grid flexibility: setting tariffs and frameworks for electricity storage in Barbados

In Barbados, the Fair Trading Commission (FTC) plays a pivotal role in enhancing the energy system’s flexibility as the island transitions to renewable energy. Through strategic decisions, such as setting energy storage tariffs and frameworks for a four-year pilot project and approving incorporation of storage recovery costs, the FTC aims to assess storage systems’ performance and their grid contribution. In alignment with Barbados’ goal of becoming a 100% renewable energy and carbon-neutral island by 2030, the FTC seeks to ensure efficient, fair energy market operations and foster sustainable energy solutions.

Context — Problem/Issue

Barbados, as other Caribbean islands, faces significant climate challenges, including rising sea levels, more intense tropical storms, and shifting rainfall patterns that threaten vital sectors, like tourism. Barbados is exposed to volatility of energy prices due to its important reliance on imported fossil fuel products for electricity generation, with renewable energy sources accounting for only 7% (mainly solar) of total electricity generation. Renewable energy sources represent 5% of total energy supply (mostly bioenergy and solar) and 19% of installed capacity.

The government launched the Barbados National Energy Policy (BNEP) 2019 – 2030, aiming to transform Barbados into a 100% renewable energy and carbon-neutral island by 2030. This ambitious goal underscores the importance of energy system flexibility in Barbados, as the policy seeks to provide reliable, affordable and sustainable energy services. The transition involves diversifying energy sources, maximizing local participation (individual and corporate) in distributed renewable energy generation and storage, and enhancing energy efficiency across various sectors. The policy is a comprehensive approach to address the supply and consumption of energy, reflecting a collaborative effort involving extensive stakeholder engagement. The BNEP considers utilizing a mix of renewable energy technologies, including 205 megawatts (MW) of centralized solar photovoltaic, 105 MW of distributed solar photovoltaic, 105 MW of both onshore and offshore wind, and 200 MW of energy storage technologies, with an estimated cost of $4.4 billion BDS. Market participants interested in deploying these renewable energy resources must obtain specific permits for generation, storage, transmission, distribution, dispatch and sale, as required by the Electric Light and Power (Amendment) Act, 2019. The Government of Barbados has additionally embraced an aggressive decarbonization approach in its 2021 Integrated Resource and Resiliency Plan (IRRP), outlining yearly renewable energy technology investment allocations to shift toward a purely renewable energy based power system.

The Fair Trading Commission (FTC) of Barbados has a critical role in overseeing utilities and ensuring fair practices within the energy sector, particularly as the country transitions toward renewable energy. It regulates utility rates, monitors competition and addresses consumer complaints, ensuring that the energy market operates efficiently and fairly for all stakeholders. This regulatory oversight is crucial for implementing the Barbados National Energy Policy’s objectives, focusing on sustainability, affordability and energy independence.

To increase energy system flexibility and provide further security of supply and grid stability, the government has estimated in the BNEP the necessity for substantial investment in about 200 MW of storage capacity (centralized and distributed). To implement this, after holding a public consultation, in June 2023 the FTC issued the Decision on Energy Storage Framework and Tariffs, which outlines Barbados’ strategic approach for integrating energy storage to facilitate a 100% renewable energy powered economy by 2030. This decision sets out the Commission’s determination of a framework for and energy storage tariffs on a four-year pilot project, pursuant to its powers to assess energy storage systems’ (ESS) performance on the grid. It introduces tariffs for energy storage systems across various size categories and details the FTC’s role in tariff determination and procurement. The decision also outlines policy recommendations to enhance grid resilience and reliability and to reduce greenhouse gas emissions. It emphasizes the importance of energy storage in stabilizing intermittent renewable energy sources and sets a foundation for sustainable energy transition in Barbados. The four-year pilot program aims to collect data on how storage systems operate and their contribution to the electricity grid, focusing on battery energy storage systems for durations of four, three and two hours, totaling 50 MW capacity. Projects must adhere to “used and useful” criteria for eligibility for the Energy Storage Tariff (EST), a rate to be paid by utilities to storage providers for capacity and services. The proposed EST is designed to compensate and provide a fair return for pilot projects that support the grid. Insights gained from these pilots will guide the development of future energy programs. Nonetheless, granting storage licenses falls outside the FTC’s purview, renewable energy producers must apply for approval from the Minister, according to the Electric Light and Power Act (ELPA).

Additionally, in May 2023, the FTC issued the Decision on The Barbados Light & Power Company Limited Application to Establish a Clean Energy Transition Rider as a Cost Recovery Mechanism that offers a detailed review and approval of the Barbados Light & Power Company Limited’s (the vertically integrated electric utility, operating as a monopoly, regulated by the FTC, with an exclusive license to sell electricity in Barbados until 2028) proposal for a cost recovery mechanism to support its Clean Energy Transition Programme (CETP) investments, which include a 10 MW battery storage. In this decision, the FTC supports the inclusion of energy storage projects within the Clean Energy Transition Rider (CETR) mechanism for recovery costs, recognizing their role in transitioning to a fully renewable energy system. It stresses the need for a detailed cost-benefit analysis to justify the economic viability and proposed use of future energy storage projects under the CETP. The decision outlines the procedural framework for the approval of future CETP investments, including energy storage, by the FTC. It also mandates the electric utility to submit individual applications for each asset or project, detailing the cost-benefit analysis, updated rate base and expected bill impacts. The FTC’s approval process ensures that all transitionary and grid modernization costs, including those for energy storage, are prudently incurred and directly support the energy transition goals.

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Grenada 1

Strengthening Grenada's resilience: transitioning to renewable energy amidst climate challenges (Grenada)

The Public Utilities Regulatory Commission (PURC) plays a crucial role in Grenada’s energy sector, focusing on promoting and ensuring sustainable adoption and use of renewable energy sources. A key aspect of its mandate is facilitating the integration of renewable energy, aiming to reduce the country’s reliance on fossil fuels and support Grenada’s commitment to increasing renewable energy capacity and reducing its carbon footprint.

Context — Problem/Issue

Climate risks in Grenada, like many small island states, are particularly acute due to its geographic and economic vulnerabilities. These risks include sea-level rise, increased intensity of tropical storms and changes in precipitation patterns. Climate change poses a significant threat to Grenada’s critical sectors, including tourism and marine-based industries, impacting the entire spectrum of the nation’s economic activities.

The government of Grenada has pledged to cut its greenhouse gas emissions by 30% (from its 2010 levels) by 2025. With an electricity sector historically reliant on imported diesel fuel, the targeted addition of 27 megawatts of renewable electricity generation by 2025 is a key component of its strategy to meet the target, while enhancing energy security and reducing price volatility.

The Public Utilities Regulatory Commission (PURC), serving as the electricity sector’s independent regulatory body, is tasked with promoting and ensuring the sustainable adoption and use of renewable energy sources and aims to reduce the country’s reliance on fossil fuels. It was established by the PURC Act No. 20 of 2016 and launched in July 2019. The PURC sets and reviews tariffs for public utilities, handles consumer complaints, and oversees the procurement for generation, transmission and distribution systems, with a focus on facilitating renewable energy. Additionally, the PURC makes recommendations to the Minister on licensing for renewable energy production, emphasizing the government’s intention to significantly adopt renewable energy​.

The PURC has undertaken several actions to promote the development of renewable energy in Grenada. In December 2019, the PURC published several regulations, including the Draft Generation Expansion Planning and Competitive Procurement Regulations, which outlines a comprehensive regulatory framework for the expansion of electricity generation capacity in Grenada and was established under the Electricity Supply Act of 2016, (Amendment in 2017) that emphasized the development of electricity generation projects from renewable sources. It defines the procedures for identifying, analyzing and implementing renewable energy projects, including the criteria to select projects which prioritize environmental sustainability, technical viability, and the potential to reduce reliance on imported fossil fuels. The draft regulation also establishes the requirements for biennial updates of integrated resource plans that shall take into consideration (i) every potential resource, encompassing new generation capabilities, demand-side measures (such as demand response and energy efficiency), and the phasing out of existing generation capacities; and (ii) a variety of renewable and efficient generation options, alongside a prudent diversification of the generation portfolio. The framework aims to foster the integration of renewable energy into the national grid, promoting efficiency, sustainability and a reduction in electricity costs through competitive procurement processes. This approach supports Grenada’s commitment to increase its renewable energy capacity and reduce its carbon footprint. The PURC recently undertook a consultation with renewable energy suppliers to hear suggestions as to how these regulations could be improved.

In 2023, the PURC also published a standardized net metering connection agreement, which should facilitate the connection of small scale renewable energy by customers.

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Poland

Enhancing regulatory capabilities: URE's role and challenges in Poland's decarbonization journey (Poland)

Poland is steering its energy sector towards sustainability and diversification, underpinned by forward looking energy policy and EU alignment. This transition includes significant renewable energy adoption, particularly solar photovoltaic and wind, with ambitious goals for reducing coal dependency. The Urząd Regulacji Energetyki (URE) plays a pivotal role in regulating this shift by overseeing market compliance and fostering renewable energy integration and an efficient grid expansion. Recent legislative changes aim to address energy pricing and market structure, enhancing URE’s regulatory capacity amidst a growing workload and funding challenges.

Context — Problem/Issue

Poland’s energy sector, traditionally reliant on coal, is experiencing a dynamic shift toward decarbonization and energy diversification. The country is increasingly embracing renewable energy sources to meet EU climate goals and enhance energy security. In February 2021, Poland’s government approved the Energy Policy of Poland until 2040 (EPP2040), aligned with EU standards and the National Energy and Climate Plan (2021-2030), which outlined a comprehensive strategy for the nation’s energy transformation, emphasizing renewable energy expansion, energy security and economic sustainability. By 2030, the projected capacity of renewable energy electricity generation in Poland is expected to reach 23-25 gigawatts (GW), effectively doubling the capacity from 2020. Significant growth is anticipated in offshore wind development, with capacity expected to hit 5.9 GW by 2030 and approximately 11 GW by 2040.

Recent legal and regulatory changes have also affected the functions of the URE. The URE’s full powers are dispersed across various national legislations, each addressing different market segments (including the Energy Law Act and the Act on Renewable Energy Sources from 2015 — amended). Amendments in 2021 brought substantial updates to the regulatory framework, enhancing URE’s powers and the oversight of electricity and gas markets, especially focusing on the regulation of gas transmission infrastructure. Additionally, an extensive update to the Energy Law Act made it easier for larger users to connect directly to the transmission systems. Efforts are underway to create a regulatory framework for Poland’s hydrogen market operation, marking crucial steps toward modernizing the energy sector and incorporating new alternative fuels and energy systems. Amendments to the Electromobility Act in June 2022 granted the URE new powers related to charging station operations and introducing definitions for low-emission and renewable hydrogen.

The regulator has a role in managing the rapid increase in distributed solar photovoltaic power that has occurred in recent years. In 2021, Poland emerged as the fourth fastest-growing solar market in Europe, with 3.2 GW of newly installed capacity,[1]  surpassing countries like France, Italy and Greece in photovoltaic expansion. In 2022, settlement methods for prosumer-generated electricity shifted significantly from net-metering to net-billing, impacting how surplus energy is compensated. This change emphasizes the importance of self-consumption and introduces dynamic tariffs, which URE is now in charge of monitoring. Challenges in integrating micro-installations into the national grid have pushed recent regulatory adjustments to enhance system flexibility and improve network management and automation processes.

In 2023, URE organized and conducted renewable auctions for a total of 88 TWh of green energy offered, however, only about 6 TWh (6.8%) was contracted, due to further interest in long-term corporate power purchase agreements (cPPAs), which are emerging as a compelling option compared to the auction-based support scheme. Most of the awards were for solar photovoltaic (98%) and wind farms, all greenfields. Furthermore, capacity procured in auctions fell to 738 MW in 2022 and further to 618 MW in 2023.

URE’s mandate includes the approval of network codes for transmission and distribution systems, storage facilities and liquified natural gas facilities, as well as formulating guidelines and recommendations to harmonize the development strategies of natural gas and electric power transmission and distribution firms. With renewable energy source expansion, intensive transmission investment is needed to ensure proper grid development. To tackle these challenges, the URE had the initiative to develop, with the five largest electricity distributors in Poland, a work program to design a common agreement of the sectoral regulator and the distribution sector known as the Charter for the Efficient Transformation of Poland’s Power Distribution Networks, which was signed in November 2022. The Charter provides the comprehensive digitalization of the electricity grid and its adaptation to the rapidly growing number of renewable energy sources. It covers several key areas of the grid expansion, including direct lines, cable pooling, hybrid energy storage installations, easier connection for storage facilities, allowing renewable energy source installations to exceed connection capacity, and cost-sharing for connecting renewable energy sources to the grid. Its adoption is expected to significantly boost renewable energy, aiming to expand renewable energy source capacity to 50 GW by 2030 and achieve a 50% renewable share in the energy mix.

The URE has, nonetheless, expressed in its 2023 National Report that the expansion of regulatory responsibilities and a swiftly evolving market have led to a marked increase in workload at the URE, evidenced by a nearly 40% rise in administrative decisions in 2022 compared to the year before. Securing the necessary funding for these expanded tasks, however, has become increasingly challenging.

[1] The country saw a dramatic rise in prosumer energy (micro-installations of no more than 50 kilowatts), with installed capacity increasing from 0.35 GW in 2018 to over 9.3 GW in 2022 and a total electricity production of nearly 5.8 terawatt-hours (TWh) for 2022. Prosumers increased from 51,000 to over 1.2 million (mostly solar photovoltaic) in 2022.

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Michigan 1

Planning requirements — requiring utilities to model a decarbonized future (Michigan)

Michigan mandates its regulated electric utilities to present an integrated resource plan to the Michigan Public Service Commission (MPSC). These plans must incorporate various scenarios, including an environmental policy scenario that assesses the impacts of accelerating decarbonization on system reliability, emissions, financial requirements and risks. The inclusion of this scenario in planning has highlighted the environmental and economic advantages of earlier coal plant retirements. The MPSC’s approval of plans featuring early closures, challenged but upheld in court, demonstrates a proactive regulatory strategy to quantify and understand the trade-offs involved in moving toward a cleaner power system.

Context — Problem/Issue

Michigan law requires regulated electric utilities to submit to the regulator an integrated resource plan. The plan’s filing requirements, which are developed and approved by the Michigan Public Service Commission (MPSC), include an obligation for the regulated utilities (in the more populated part of the state) to undertake a series of scenarios. One of these scenarios, the environmental policy scenario, examines the implications of moving more quickly than current policy requires to decarbonize the power system. It includes an assessment of the scenario’s impact on reliability, emissions and annual revenue requirements and a risk assessment for each scenario modeled. The advantage of including the scenario in the required plan is to assist the regulator in understanding the costs and benefits of moving more quickly to a decarbonized system by presenting a quantification of these costs and benefits.

The requirement to develop the scenario led to analyses that demonstrated that closing a coal plant earlier than planned would have both environmental and economic benefits. The MPSC approved a plan that was negotiated with stakeholders for which the early closing was included as part of the environmental policy scenario. The MPSC’s ruling was challenged by another utility but upheld by the courts.

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