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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