All 127 energy policy briefs, by jurisdiction

Signed on 4 July 2025 and published on 7 July 2025, Decreto 450/2025 approves the adapted text of Ley 15.336 and a consolidated Ley 24.065: distributors must buy through spot purchases and competitive term contracts instead of a single administered supply, the dispatch operator becomes a company whose state shareholding can fall to 10 percent with a veto, and the Secretaría de Energía has 24 months to transfer CAMMESA's energy and fuel contracts to demand and supply.

After a decade of frozen tariffs, ENRE ran a full five-year review for the AMBA distributors, convened by Resolución ENRE 79/2025 with a public hearing on 27 February 2025, and set tariff paths applied from 2025 with monthly adjustments; in parallel Decreto 465/2024 replaced blanket energy subsidies with a focused regime for vulnerable households registered in a national scheme.

Published on 8 July 2024, the Ley Bases delegated to the Executive the power to adapt Leyes 15.336 and 24.065 to seven stated principles, created the merged Ente Nacional Regulador del Gas y la Electricidad, and established the RIGI, a thirty-year tax, customs and exchange-stability regime for single-project vehicles investing at least US$200 million, with an adhesion window now running to 8 July 2027.

The Milei government's founding deregulation decree, published in the Boletín Oficial on 21 December 2023, declared a public emergency including tariffs until 31 December 2025, repealed the decrees and the law that underpinned the frozen-tariff and price-control regime, gutted the distributed-generation incentive law, and gave the Secretaría de Energía an express mandate to redesign electricity and gas subsidies around household income.

Ley 27.191 obliges every consumer, and individually every large user with 300 kW or more of demand, to source a rising share of its electricity from renewables (8 percent by end-2017, 12, 16, 18 and 20 percent by 31 December 2025); the state met it first through the CAMMESA-contracted RenovAr auctions, whose Round 2 was launched in 2017, and then through the MATER private term market, which is now the only route for new build.

AEMO's 2026 ISP, published on 25 June 2026, sets the optimal development path for the NEM to 2050: about $106 billion of annualised capital, $16 billion of upfront transmission capital, a 14 per cent (6,000 km) expansion of the 44,000 km grid and $30 billion of avoided cost for consumers. Actionable status in the ISP is what unlocks regulated revenue for HumeLink, VNI West, Marinus and three newly actionable Queensland and Tasmanian projects.

The independent review of NEM wholesale market settings reported on 16 December 2025; energy ministers other than Queensland agreed in principle that month and on an implementation approach in March 2026. A draft bill amending the National Electricity Law and draft National Electricity Rules are in consultation from 14 September to 13 October 2026, creating an Electricity Services Entry Mechanism, a Market Making Obligation and new visibility of price-responsive resources.

The Capacity Investment Scheme underwrites revenue for new renewable generation and clean dispatchable capacity through national tenders. Expanded to 32 GW on 23 November 2023 and uplifted to 40 GW on 29 July 2025 (26 GW generation, 14 GW dispatchable), it has already awarded about 22.7 GW of generation and about 11.5 GW of dispatchable capacity and is now the single largest determinant of what gets built in Australia.

The 2023 reform turned a dormant emissions cap into Australia's only binding industrial carbon constraint: baselines at facilities emitting over 100,000 tonnes CO2-e fall about 4.9 per cent a year to 2030, tradeable Safeguard Mechanism Credits reward over-performance, and grid-connected generators sit under a single sectoral baseline. The statutory 2026-27 review is open, with submissions closing 18 September 2026, against a new 2035 target of 62 to 70 per cent below 2005 levels.

New South Wales legislated its own procurement machine in 2020: the Electricity Infrastructure Investment Act creates renewable energy zones and long-term energy service agreements to deliver at least 12 GW of renewable generation and 2 GW of long-duration storage, mobilising more than $77 billion of private investment by 2035. With 10.71 GW of REZ access rights awarded and Eraring now running to April 2029, it is the largest single state intervention in the NEM.

The AEMC's 2017 five-minute settlement rule aligned NEM financial settlement with five-minute dispatch from 1 October 2021, and its 2021 storage rule created the Integrated Resource Provider category from 3 June 2024. Together they are the price architecture behind Australia's grid-battery build, and the Reliability Panel's April 2026 review has now set the price caps and reliability standard that follow from 2028.

Portaria Normativa 50/GM/MME opened the Ambiente de Contratação Livre to every high-voltage (Grupo A) consumer from 1 January 2024, with loads below 500 kW represented by retail agents at the CCEE; MP 1.300/2025 tried to extend that to low-voltage consumers but its conversion law kept only the social-tariff measures, and the opening schedule was enacted instead in Lei 15.269/2025.

Lei 14.948/2024 created Brazil's low-carbon hydrogen legal framework, made the ANP the authorising regulator and set up the Rehidro tax regime; the funding articles were vetoed and re-enacted in Lei 14.990/2024 as the PHBC, a competitive tax-credit programme capped at R$18.3 billion, whose window Lei 15.269/2025 pushed from 2028-2032 to 2030-2034.

Brazil's distributed-generation statute ended unlimited net metering: units that applied for grid access after 7 January 2023 pay a rising share of the distribution wire charge on compensated energy (15 percent in 2023, 30, 45, 60, 75, 90 percent, then the full ANEEL tariff rule from 2029), while everything connected or requested before that date keeps full netting until 31 December 2045.

The law that privatised Eletrobras by capital increase also ordered the state to contract 8,000 MW of inflexible gas-fired capacity in regions without gas pipelines through reserve-capacity auctions; Medida Provisória 1.304/2025, converted into Lei 15.269/2025, replaced that mandate with up to 4,900 MW of sub-50 MW hydro plus 3,000 MW of biomass, restructuring Brazil's most expensive legislated procurement.

Brazil replaced weekly load-block pricing with an hourly PLD computed by the DESSEM model from 1 January 2021, and after the 15 August 2023 national blackout the ONS began curtailing wind and solar in the Northeast for reliability; Lei 15.269/2025 finally created a compensation right for those cuts from 1 September 2023 in exchange for dropping the litigation.

Alberta is rebuilding its energy-only market: interim supply-cushion and offer-mitigation rules already cap prices when supply is tight, and the AESO's REM design, whose ISO rules the Minister approved in March 2026, moves to real-time locational marginal pricing with scarcity pricing, an enhanced day-ahead market for operating reserves, tighter conduct rules and a reliability backstop, with go-live targeted for mid-2027.

Enacted in June 2025, the Building Canada Act lets Cabinet designate national-interest projects (pipelines, transmission, ports, mines, nuclear) and deem them approved, collapsing federal reviews into a single conditions-setting process with a two-year target and a Major Projects Office.

On 1 May 2025 Ontario replaced its two-schedule uniform-price market with a financially binding day-ahead market and a single-schedule real-time market using locational marginal prices, ending the Hourly Ontario Energy Price and most congestion make-whole payments.

Five refundable federal credits worth 15 to 60 percent of capital cost for storage, renewables, nuclear, interprovincial transmission, carbon capture, hydrogen and clean manufacturing, conditioned on paying prevailing wages; all five are enacted (the last, the Clean Electricity ITC, by Bill C-15 in March 2026) and they are Canada's answer to the US IRA and the main lever behind provincial procurement economics.

A federal performance standard of 65 tonnes CO2 per GWh on fossil generating units of 25 MW or more from 1 January 2035, with pooling, offsets and end-of-life relief for existing gas plants; the regulations are held in abeyance in Alberta under the May 2026 Canada-Alberta implementation agreement pending a court reference, after which they will be stood down by equivalency agreement or repealed.

From 1 June 2025 all new wind and solar output in China is sold at market prices instead of the coal benchmark tariff, with a CfD-like mechanism price set by provincial competitive bidding for a share of output; projects commissioned before June 2025 keep a price no higher than the coal benchmark, which is why the first half of 2025 saw a record installation rush and the second half a collapse.

In March 2025 the Ministry of Ecology and Environment extended China's national ETS, which had covered only power since 2021, to steel, cement and aluminium smelting, adding about 1,500 enterprises and 3 billion tonnes of CO2, with free allocation and intensity-based benchmarks at first and a transition toward absolute caps and tighter benchmarks; for the power sector the 2024 to 2026 allocation plans tighten benchmarks while allocation remains fully free, with a cap-based, part-paid market targeted by 2030.

China's first comprehensive energy statute, in force from 2025, gives legal priority to renewable development, a statutory basis for green certificates and energy markets, recognises hydrogen as an energy source, and codifies planning, reserves and emergency powers; it is a framework law whose bite comes through State Council regulations and NDRC/NEA measures.

Since 2024 China pays coal plants a fixed capacity charge, 100 yuan per kW-year in most provinces (about 30 percent of a plant's fixed cost) and 165 yuan in provinces with heavy renewables, rising toward 50 percent of fixed cost from 2026, recovered from users; it turns coal into the paid backbone of a renewables-led system and is the first two-part tariff in China's power market.

The 2023 basic rules standardised provincial spot markets (day-ahead and real-time, nodal or zonal pricing, contracts settled as financial hedges), and the 2022 guiding opinions, the April 2025 spot-acceleration notice and the February 2026 State Council Office opinions set the timetable: full provincial spot coverage by end-2025, formal operation nationwide before 2027, and a unified national market basically built by 2030 and fully by 2035, plus inter-provincial spot trading through the two national exchanges.

The tariff schedule EgyptERA published for April 2026 raises transmission-level and commercial prices sharply while freezing the protected residential blocks: extra-high voltage moves from 160 to 189 piastres per kWh, medium voltage from 194 to 255, and the smallest commercial block from 85 to 162, and the schedule states that prices are set on the Central Bank's published exchange rates and will be reviewed whenever those rates move.

Prime Ministerial Decree No. 1539 of 2025, issued on 4 May 2025, adds Article 35 bis 9 to the executive regulations of the Capital Market Law so that the energy source certificate created by Electricity Law 87/2015 counts as a financial instrument tradable on Egyptian stock exchanges, turning the green attribute of renewable generation into a security that can be sold separately from the electricity.

The 2024 update to Egypt's integrated sustainable energy strategy pulls the 42 percent clean-power target forward from 2035 to 2030 (30 percent renewables plus 12 percent nuclear) and sets a course to about 74 percent by 2040; NREA reports more than 8.8 GW of wind and solar operating, 4,020 MW under construction and 12,400 MW in development, for roughly 25.15 GW with about 3.35 GWh of batteries.

EgyptERA's board approved the Rules Governing Private-to-Private (P2P) Projects on 28 March 2024 and issued them as Circular No. 2 of 2024, opening the first genuine corporate PPA channel under Electricity Law 87/2015: new wind and solar plants of up to 100 MW may sell directly to as many as three eligible consumers across EETC's grid, but the whole programme is capped at 500 MW and the state gives no guarantees.

EgyptERA's wheeling charges for third-party use of EETC's grid rose on 1 September 2024 to an average of 7.25 piastres per kWh at extra-high voltage, 16.66 at high voltage and 19.09 at medium voltage, roughly a 46 percent increase on the January 2023 levels and more than double the 2019 levels; these are the prices that decide whether a corporate PPA or a green hydrogen project can beat the regulated tariff.

With the Grand Ethiopian Renaissance Dam operating and supplying about 52 percent of national generation, Ethiopian Electric Power announced on 16 September 2026 that exports to Kenya will double from 200 MW to 400 MW starting in December, alongside a 100 MW pilot to Tanzania, and set a target of 5,000 GWh of annual exports by 2030 with new corridors to Sudan, Djibouti, South Sudan, Somalia and Somaliland.

Directive FXD/01/2024, effective 29 July 2024, repealed every previous foreign exchange directive, let banks and dealers trade at freely negotiated rates and replaced the official peg with a published Indicative Daily Exchange Rate; the reform doubled foreign exchange available to business and, through the February 2026 relaxations and Directive FXD/04/2026, freed dividend repatriation and external borrowing approvals that power projects depend on.

Alongside the July 2024 currency float the government approved a multi-year schedule of electricity tariff increases intended to bring retail prices toward cost recovery by 2028, replacing a frozen tariff that had left Ethiopian Electric Utility unable to fund maintenance or pay its bulk supplier; the increases are phased and applied by the utility, with the Council of Ministers approving each step on the regulator's recommendation.

Article 51 of the 2021 executive-organs proclamation folded the Ethiopian Energy Authority into a combined Petroleum and Energy Authority, which now licenses generators and suppliers, issues the grid and service codes and reviews national-grid tariffs before submitting a recommendation to the Council of Ministers; the authority sits under the Ministry of Trade and Regional Integration, so the regulator that prices power is not inside the energy ministry.

Ethiopia opened generation to private capital through the public-private partnership framework and signed its first large independent power producer agreements in 2019 and 2020: the Metahara 100 MW solar project with Enel, 250 MW of solar with ACWA Power worth about 300 million dollars, and power purchase and implementation agreements with the Corbetti and Tulu Moye geothermal projects representing roughly 1.2 billion dollars of investment.

Regulation (EU) 2026/667, in force since 7 April 2026, writes a 90 percent net emissions cut by 2040 into the Climate Law, allowing up to 5 percent of 1990 net emissions to come from international credits from 2036 (85 percent domestic), and as part of the deal delayed the launch of the second emissions trading system for buildings and road-transport fuels from 2027 to 2028, keeping the power-sector ETS on its steep post-2030 decline path.

The Commission's December 2025 package to overhaul EU grid rules: a revised TEN-E regulation and a permitting directive amending three directives, plus guidance on grid connections and two-way CfDs, aimed at speeding cross-border and internal grid build, sharing interconnector costs and steering tariffs toward anticipatory investment; the Commission puts electricity grid needs at 1.2 trillion euros by 2040. Council general approaches followed on 26 June 2026 and trilogues have run since July 2026.

The post-crisis reform keeps marginal pricing but changes what surrounds it: two-way CfDs become the required form of public support for new renewables and nuclear, capacity mechanisms become a structural tool, member states must assess flexibility needs and may support non-fossil flexibility, suppliers must hedge, and the Council can declare a price crisis that unlocks retail price interventions.

The package rewrites EU gas market law for hydrogen and low-carbon gases: it creates a regulated hydrogen network regime with unbundling by 2033, a European hydrogen network operator body (ENNOH), tariff discounts for renewable and low-carbon gas, a ban on long-term unabated fossil gas contracts running past 2049, and powers to restrict Russian gas; the directive must be transposed by 5 August 2026.

In force since June 2024, the NZIA sets a benchmark that 40 percent of the EU's annual deployment needs in net-zero technologies be manufactured in Europe by 2030, imposes permitting deadlines of 12 to 18 months, requires non-price and resilience criteria in a share of renewable auctions and public procurement, and mandates 50 million tonnes a year of CO2 storage injection capacity by 2030.

From 2026 importers of electricity, steel, aluminium, cement, fertilisers and hydrogen must buy CBAM certificates priced at the EU ETS allowance price for the embedded emissions of their imports, with a 2025 simplification exempting small importers under 50 tonnes a year; free ETS allowances for the same sectors phase out in step through 2034.

CERC directed in July 2025 that bids from all three power exchanges be pooled and cleared as one day-ahead market, targeting January 2026; that target was missed, and CERC's April 2026 draft Power Market regulations now make Grid-India the sole market coupling operator with the go-live date to be notified, which would end IEX's near-monopoly on price discovery and create a single national day-ahead price.

The Ministry of Power's October 2025 draft would phase out cross-subsidies for manufacturing, railways and metro railways, let multiple distribution licensees share one network, force cost-reflective tariffs on a clock and create a national Electricity Council; it is a consultation draft, not yet introduced in Parliament, and every previous attempt since 2014 has lapsed.

India's compliance carbon market, notified in June 2023 under the Energy Conservation Act, sets emissions-intensity targets for seven heavy-industry sectors (490 plants) from 2025-26 with credits to be traded on the power exchanges under CERC rules notified in February 2026; power generation is excluded for now, so the scheme's electricity effect runs through industrial demand and the offset mechanism rather than plant dispatch.

From October 2023 India replaced point-to-point long-term transmission access with general network access: generators get connectivity on readiness rather than a PPA, drawee entities buy a quantum of access to the whole inter-state grid, and the renewable transmission-charge waiver phases out from July 2025.

The rules that fixed India's generator receivables problem: legacy discom dues were converted into up to 48 instalments and any new default triggers automatic loss of short-term market access, cutting overdue dues from about 1.4 trillion rupees in mid-2022 to a small fraction within two years.

Central rules that cut the open-access threshold for buying green power from 1 MW to 100 kW, deem approval within 15 days, cap increases in cross-subsidy surcharge and require banking, creating the corporate renewable PPA market that now accounts for gigawatts a year of contracts.

The Cabinet adopted the 7th Strategic Energy Plan on 18 February 2025 alongside the GX2040 Vision and the Plan for Global Warming Countermeasures, targeting a 73 percent greenhouse-gas cut by FY2040 against FY2013 and a FY2040 power mix of roughly 40 to 50 percent renewables, 20 percent nuclear and 30 to 40 percent thermal, with electricity generation rising to 1.1 to 1.2 trillion kWh.

The GX Promotion Act finances Japan's transition with ¥20 trillion of GX transition bonds and repays them with carbon pricing on a legislated timetable: a mandatory emissions trading scheme for companies emitting 100,000 tonnes of CO2 a year or more from FY2026, a levy on fossil-fuel importers and producers from FY2028, and paid allocation to power generators from FY2033.

OCCTO published Japan's first wide-area grid master plan on 29 March 2023, finding that about ¥7 trillion of network investment toward 2050 would still deliver net benefits, and identifying a new HVDC route from Hokkaido through Tohoku to Tokyo, reinforcement of the Kanmon link and more frequency-converter capacity; the 2 GW Hokkaido-Honshu Sea of Japan HVDC is now in the OCCTO planning process.

From 1 April 2022 Japan replaced the fixed feed-in tariff with a feed-in premium for larger renewable projects: generators sell into JEPX or to an offtaker and receive a supply-promotion subsidy equal to the gap between a base price and a reference market price, which moves merchant price risk, balancing responsibility and shape risk onto developers for the first time.

OCCTO's capacity market held its first main auction in July 2020 for delivery in FY2024, clearing 167.7 GW at the ¥14,137/kW cap; the FY2029 auction cleared 166.1 GW for ¥2.21 trillion at area prices of ¥12,388 to ¥15,112/kW. The long-term decarbonisation auction bolted on 20-year fixed-cost contracts for new low-carbon plant, batteries and LNG.

The third phase of Japan's electricity system reform forced the ten incumbent utilities to put their networks into separate legal entities on 1 April 2020, and wrote a conduct code into the Electricity Business Act: Article 22-2 bars a general transmission and distribution utility from retailing or generating for retail, and Article 23 bars affiliated retailer staff from working on neutrality-sensitive network functions.

Gazetted and commenced on 8 May 2026, Legal Notice 79 of 2026 establishes Kenya's electricity market under section 131(2) of the Energy Act, opens transmission and distribution networks to non-discriminatory third-party access, and lets eligible consumers buy in bulk direct from generation licensees. The eligibility threshold is one megavolt-ampere on the distribution system and ten on the transmission system, and participation is voluntary during a transitional phase.

EPRA approved the base electricity tariff for the control period 2022/23 to 2025/26 in March 2023, ending the emergency 15 per cent discount era and restoring a cost-reflective base. Kenya Power filed its application for the fifth control period (2026/27 to 2028/29) on 31 March 2026, EPRA postponed the county public forums on 24 May 2026 and then announced on 5 June 2026 that the application had been withdrawn after consultations within government to forestall an escalation in the cost of electricity.

The Ethiopia–Kenya interconnector is a 1,045 km, 500 kV direct-current line rated at 2,000 MW running from Welayta Sodo in Ethiopia to Suswa in Kenya, with 612 km inside Kenya. Commercial imports under the Ethiopian Electric Power–Kenya Power agreement began in late 2022. EPRA records 200 MW of import capacity in Kenya's installed base and 939.23 GWh imported from Ethiopia and Uganda in the half year to December 2025, a 24.9 per cent rise and the fastest growth of any supply category.

Appointed on 29 March 2021 and reporting on 15 October 2021, the taskforce found that independent power producers supplied 25 per cent of Kenya Power's energy but 47 per cent of its power purchase cost, against KenGen at 72 per cent for 48 per cent. It recommended renegotiating named wind, geothermal and heavy fuel oil PPAs to the KenGen tariff, replacing take-or-pay with pay-when-taken, competitive auctions, and suspending processing of all expressions of interest.

Assented on 12 March 2019, published in Kenya Gazette Supplement No. 29 and commenced on 28 March 2019, the Energy Act consolidated Kenya's energy law into what is now Cap. 314. It created the Energy and Petroleum Regulatory Authority, the Energy and Petroleum Tribunal, REREC and the Nuclear Power and Energy Agency, gave county governments statutory energy functions, and in section 131 required a first review of the electricity market within three years and no more than five years between reviews.

The 2025 framework replaced indicative PRODESEN planning with binding planning: SENER must publish a Plan de Desarrollo del Sector Eléctrico each May, though the first one came in October 2025, calculates the state's share of injected generation each February, and every permit, interconnection and mixed-investment project must conform to the plan, which is the instrument carrying the CFE-led generation and transmission expansion to 2030.

Published on 18 March 2025 and in force the next day, the Ley del Sector Eléctrico abrogated the 2014 Ley de la Industria Eléctrica: the state must keep at least 54 percent of the energy injected into the grid in a calendar year, private generation continues under permits from the new Comisión Nacional de Energía, which replaces the autonomous CRE, and joint state-private projects run through two defined schemes; the reglamento followed on 3 October 2025.

Transitory article three of the Ley del Sector Eléctrico keeps the Reglas del Mercado, the Código de Red and CENACE's manuals in force until replacements are issued, so Mexico's wholesale market still operates on rules written for the abrogated 2014 statute; clean-energy certificates survive but are now granted by the CNE on SENER criteria, are valid 30 months, and their annual requirement is set administratively three years ahead.

Mexican residential electricity tariffs are set by Executive agreement, not by the regulator, and have been held to increases at or below inflation since 2019 through a subsidy worth tens of billions of pesos a year; commercial and industrial users on basic supply face the full tariff, and the March 2025 statutes moved responsibility for transmission, distribution and basic-supply tariff methodologies from the CRE to the Comisión Nacional de Energía.

The 2021 reform of the Ley de la Industria Eléctrica put state legacy plants ahead of private renewables in dispatch, made long-term auctions optional and granted clean-energy certificates to all clean generation regardless of ownership or vintage; the Supreme Court could not muster the eight votes to strike it down, and the 31 October 2024 constitutional amendment then wrote CFE's primacy into articles 25, 27 and 28.

Nepal exports 3,965 GWh in the monsoon and imports 1,171 GWh in the dry season because its fleet is almost all run-of-river: the three Kulekhani storage plants supplied about 92 GWh of 19,078 GWh and both NEA thermal stations ran not at all. The ERC's Reservoir Plant Purchase and Sale Directive 2082 and its storage-hydro PPA pricing paper are the first attempt to price dry-season energy, while 12 pumped-storage projects of 9,851 MW were screened in FY 2025/26 and none has cleared feasibility.

Nepal ended FY 2025/26 with 7,110 circuit-kilometres of 66-400 kV line and 15,541 MVA of grid substation capacity, with a further 1,650 circuit-kilometres and 6,261 MVA under construction. The Butwal-Gorakhpur and Dhalkebar-Sitamarhi 400 kV cross-border lines are near completion, RPGCL's master plan sizes the eventual network to wheel 40 GW by 2040 at about USD 6.04 billion, and NEA has begun tendering transmission under a tariff-based competitive bidding framework.

Nepal's entire wholesale market is cross-border. Under the 2014 Nepal-India power trade agreement and India's CERC Cross Border Trade of Electricity Regulations 2019, amended in 2023 and again on 9 December 2025 to move access onto General Network Access, NEA holds 37 Indian approvals covering 1,200.01 MW and exported 3,965 GWh worth NRs 29.31 billion in FY 2025/26, including the first 40 MW of round-the-clock supply to Bangladesh across Indian territory.

Every Nepali power purchase agreement is signed by NEA as single buyer and needs the Electricity Regulatory Commission's consent under the Electricity Purchase-Sale and Licensee Conditions Regulations 2076. NEA now holds 545 PPAs totalling 12,135 MW with a further 277 applications for 16,344 MW in the queue, and has begun replacing administered rates with tariff-based competitive bidding, awarding 49 solar PPAs for 675 MW that way in FY 2025/26.

The ERC Act 2074 created Nepal's first independent electricity regulator, constituted on 6 May 2019, with power to set consumer tariff, fix PPA rates, consent to every power purchase agreement, set wheeling charges and provide for open access. In 2026 it issued the Electricity Consumer Tariff Determination Directive 2083 and the first marginal cost study since 2005, but the tariff order in force is still NEA's 2078 determination and the framework law is still the Electricity Act 2049 (1992).

The August 2024 gas shortage and historically low hydro storage forced industrial shutdowns and a policy reset. The Electricity Authority's answer is an emergency reserve scheme, decided on 13 January 2026: a new ancillary service run by Transpower that pays industrial users to reduce demand or add generation when supply is especially tight, worth an estimated $33 million in net benefits and due in place by the last quarter of 2026.

After the August 2024 fuel shortage and sustained high wholesale prices, the Electricity Authority and Commerce Commission created a joint Energy Competition Task Force. Its first tranche landed in 2026: Code amendments made on 8, 13 and 15 May 2026 impose non-discrimination obligations on Contact, Genesis, Mercury and Meridian in hedge trading, tighten hedge disclosure and market making, and require time-of-use and peak export pricing from 1 July 2026.

On 20 November 2024 the Commerce Commission made joint final decisions resetting the electricity distribution default price-quality path and Transpower's individual path for 1 April 2025 to 31 March 2030. Distributors were allowed $11.5 billion of revenue, up $3.5 billion, and Transpower $5.9 billion, up $1.8 billion, with a WACC of 7.1 per cent against 4.6 per cent previously and about $10 a month added to the average household bill.

The Fast-track Approvals Act 2024 replaced the Resource Management Act consenting path for nominated infrastructure and development projects with a ministerial referral and an expert panel that grants all approvals at once. Schedule 2 names 149 listed projects, including a large slate of wind, solar and hydro schemes, and the Act was extended and amended by the Fast-track Approvals Amendment Act 2025 in December 2025.

The Climate Change Response (Zero Carbon) Amendment Act 2019 gave New Zealand a legislated 2050 target, emissions budgets and a Climate Change Commission. The binding price signal comes from the ETS unit settings: the September 2025 amendment regulations set auction volumes falling from 11.7 million units in 2026 to 5.6 million in 2030, with an auction floor rising from $71 to $87. In 2025 Parliament also weakened the 2050 methane target and repealed the offshore petroleum exploration ban.

Russia legalised and registered cryptocurrency mining by federal law in August 2024 and then, within months, used government resolutions to ban or seasonally restrict mining in the regions where it was causing deficits, including parts of Siberia, the North Caucasus and the Far East, making mining the first large load class in the country to be managed by explicit administrative curtailment.

Russia is dismantling its non-price zones: Arkhangelsk and Komi entered the price zones in time for the 2028 capacity selection and the Far East followed for the 2029 selection held in February 2026, so regions that had been paid at tariff now clear against competitive capacity prices, while in parallel the government has pushed differentiated household tariffs and cross-subsidy limits to move cost off industrial consumers.

Federal Law 35-FZ of 2003 is the parent statute of the Russian power market, and almost every market change since 2017 has arrived as an amendment to it; the most consequential recent one, Federal Law No. 516-FZ of 2 November 2023, wrote demand-side response into the wholesale market as a paid service, which the System Operator now procures from aggregators in both price zones.

Russia supports renewables not through a feed-in tariff but through capacity-supply agreements awarded in competitive selections and paid for by wholesale consumers; the second programme, running from 2021 to 2035, cut the budget sharply against the first, switched the award criterion to the levelised cost of energy, and tightened localisation by adding an export obligation, which has left Russian renewables a small, industrially driven niche rather than a mainstream generation source.

Russia pays for availability through a competitive capacity selection held four years ahead, and since 2019 it has bolted on KOMMod, a government programme that awards guaranteed capacity payments to modernisation projects on ageing thermal plant; the 2029 selection held in February 2026 cleared 164,914 MW in the first price zone at 369,390.73 roubles per MW-month and 52,380 MW in the second at 590,713.14 roubles.

Construction contracts signed in October 2021 commit Saudi Arabia and Egypt to the region's first large high-voltage direct-current link, a roughly 3,000 MW bidirectional interconnector with converter stations in Medina and Tabuk on the Saudi side and Badr on the Egyptian side, designed to trade reserve and energy between two systems whose peaks fall at different times of day and year.

The 2020 amendment of the Electricity Law replaced Saudi Arabia's vertically integrated single-utility model with a principal-buyer market: Saudi Electricity Company was unbundled, transmission was carved out into National Grid SA, the Saudi Power Procurement Company became the sole offtaker for new generation, and the former ECRA was reconstituted as WERA with licensing, code and cost-of-service powers over both electricity and water.

On 1 January 2018 Saudi Arabia raised household and business electricity tariffs sharply and simultaneously lifted the administered prices of the gas, ethane and liquid fuels sold to power generators, converting a hidden producer subsidy into a visible cost, with the Citizen's Account cash transfer absorbing the effect on lower-income households; the schedule has been adjusted since, most recently in the 2024 review.

Saudi Arabia has built the institutional layer of a civil nuclear programme (a National Atomic Energy Project, the independent Nuclear and Radiological Regulatory Commission and a low-power research reactor) and has run a long-delayed tender for its first large reactors, but the decisive gate is not technical: it is the safeguards and non-proliferation framework, including a nuclear cooperation agreement with a supplier state and the move off the IAEA Small Quantities Protocol.

Launched in 2017 and now run by SPPC as principal buyer alongside a negotiated Public Investment Fund track, the National Renewable Energy Program has turned Saudi Arabia from a country with essentially no utility-scale renewables into one of the largest solar procurement pipelines in the world, working toward a target of roughly half of generation from renewables by 2030.

Passed on 9 September 2024 and fully in force since 1 September 2025, the act gives EMA the legal basis to fund and direct energy-transition infrastructure (a Future Energy Fund seeded with S$5 billion and topped up by a further S$5 billion in Budget 2025, powers to recover costs through market charges and to require participation in centralised gas and capacity arrangements), turning Singapore's market from purely merchant to a hybrid with state-directed investment.

Singapore plans to import about a third of its electricity by 2035 from Indonesia, Vietnam, Cambodia, Malaysia and Australia; EMA has granted conditional approvals for 13 projects totalling 9.25 GW (six of them with conditional licences), but subsea cables, source-country export politics and financing decide which reach commercial operation.

Since July 2023 EMA has capped the Uniform Singapore Energy Price when it spikes above a cost-based threshold, and it now procures new combined-cycle capacity centrally (three hydrogen-ready units awarded so far: YTL PowerSeraya for 2027, PacificLight Power for 2029 and Tuas Power for 2031, with 2032 units under tender), moving new-build risk from merchant gencos to a state-run process.

Singapore's carbon tax, paid by power generators and large industrial emitters, rose from S$5 to S$25 per tonne in 2024 and to S$45 from 1 January 2026, with a 2030 range of S$50 to S$80; because the tax passes straight into the wholesale electricity price, it is the single largest policy driver of Singapore's power price after fuel.

NERSA decided Eskom's sixth multi-year price determination on 30 January 2025 for 2025/26 to 2027/28, cutting the application heavily. Eskom took the decision on review, a settlement was interdicted, and on 21 December 2025 the High Court set the decision aside and remitted it. The redetermination approved on 7 February 2026 gives Eskom R54 734 million more, phased so that the 2026/27 increase becomes 8.76% and 2027/28 becomes 8.83%.

The IRP 2025 was promulgated as Government Notice 6767 in Government Gazette 53596 of 28 October 2025, replacing Gazette 53592 and Notice 6765 and superseding the IRP 2019. Its Proposed Balanced Plan adds 6 GW of gas CCGT and about 21.9 GW of wind and solar by 2030, then 5.2 GW of nuclear from 2036, 43 GW of wind and 28.7 GW of solar PV in total to 2042, against the shutdown of 8 GW of coal by 2030.

Assented on 16 August 2024 and gazetted on 20 August 2024, Act 38 of 2024 rewrites the Electricity Regulation Act 4 of 2006 to create a Transmission System Operator SOC Ltd that is at once transmitter, system operator, market operator and central purchasing agency, running an open market platform under a NERSA-approved market code. Until the TSO exists, and for no longer than five years, the National Transmission Company South Africa is deemed to be it.

After raising the embedded-generation licensing threshold to 100 MW in August 2021, the Minister published a draft Schedule 2 on 2 September 2022 (Notice 2459, Gazette 46850) that removes the capacity cap entirely: a generation facility of unrestricted capacity needs only to register with NERSA and comply with the grid code, and may wheel to customers over a third-party network under a connection agreement. The substituted Schedule 2 was gazetted as Notice 2935 on 17 January 2023 (Gazette 47877).

The Carbon Tax Act took effect on 1 June 2019 at R120 per tonne of CO2 equivalent, escalating by CPI plus two per cent to the end of 2022 and by CPI thereafter. The 2026 Budget Review confirms the headline rate rose from R236 to R308 per tonne on 1 January 2026, the start of phase 2, while the carbon fuel levy moves to 19c/litre for petrol and 23c/litre for diesel on 1 April 2026 and the liquid-fuels cost-recovery allowance rises from 0.99c to 1.29c/litre.

Korea is retiring the renewable portfolio standard that has driven its solar and wind build since 2012 and replacing it with government-run auctions and contracts: the renewable statute was renamed and rewritten by Act No. 21462 of 17 March 2026, new Articles 12-10 to 12-14 including a contract market system for renewable facilities commence on 1 January 2027, and a transitional provision fixes a cut-off for issuing supply certificates.

The 11th Basic Plan, confirmed in February 2025 after a year of delay and parliamentary fighting, fixes the capacity mix Korea will procure to 2038: more nuclear, including new large units and a first small modular reactor, a large increase in solar and wind, coal retirements, and a demand forecast lifted by semiconductor fabs and data centres.

Korea's emissions trading scheme entered its fourth phase in 2026 covering 2026 to 2030, with the governing Act amended by Act No. 21071 of 28 October 2025 and the Enforcement Decree by Presidential Decree No. 36285 of 28 April 2026, both in force from 29 April 2026, and with administration now split between the Ministry of Planning and Budget and the Ministry of Climate, Energy and Environment.

Korea's backbone grid act, promulgated on 25 March 2025 and in force six months later on 26 September 2025, lifts nationally significant transmission projects out of the ordinary Electric Source Development Promotion Act process and gives them a state-led committee, compressed approvals and statutory community compensation, because transmission, not generation, is what is failing to arrive.

Korea's Offshore Wind Special Act, promulgated on 25 March 2025 and in force a year later on 26 March 2026, replaces developer-led permit-hunting with government-led zoning: the state surveys and designates offshore wind promotion zones, runs a single integrated consent process, and tenders the zones, with transitional protection for projects already holding permits.

Korea's Distributed Energy Act came into force on 14 June 2024 to break the pattern of building generation far from load and then curtailing it: it creates distributed energy special zones where local supply can be sold directly, an installation obligation on large new loads, and a framework for regional pricing, against a background of persistent renewable curtailment on Jeju and in the Honam region.

Korea reintroduced a quarterly fuel-cost adjustment in 2021 and then suppressed it through the price shock, leaving KEPCO selling below cost and accumulating an enormous deficit; the repair since 2022 has come through repeated tariff increases loaded disproportionately onto industrial customers, with residential rates now at 120.0 to 307.3 won per kWh by tier.

Taiwan became nuclear-free on 17 May 2025 when the Maanshan Unit 2 operating licence expired, four decades after the unit started up. A 2025 amendment to the nuclear regulation law reopened the possibility of licence renewal, a national referendum on restarting Maanshan failed to clear the statutory approval threshold, and the Nuclear Safety Commission is now running a four-part licence renewal review.

Taiwan's electricity tariffs are set twice a year by an MOEA-convened Electricity Tariff Examination Council, with changes effective on 1 April and 1 October. Successive reviews since 2022 have raised rates, most visibly in April 2024, while the Executive Yuan has covered part of Taipower's losses with budget injections that the Legislative Yuan has repeatedly contested.

Taiwan's Climate Change Response Act, a 63-article rewrite promulgated on 15 February 2023, legislated net zero by 2050 and created a carbon fee on large direct and indirect emitters under Article 28, preferential rates for approved voluntary reduction plans under Article 29, offsetting under Article 30, and an import carbon declaration and credit obligation under Article 31.

Taiwan's third offshore wind round replaced feed-in tariffs with zonal development, allocating 15 GW from 2026 to 2035. The rules governing phase 3, amended 27 March 2026, changed the model: bidders are scored on capability rather than price, the localisation scoring that drew an EU trade complaint is now ESG and energy-resilience investment, and phase 3 projects hold a guaranteed floor price of NT$2.29 per kWh — a revenue backstop under what had been a merchant model.

The 2019 amendment to Taiwan's Renewable Energy Development Act created the large electricity user obligation in Article 12: consumers above a contracted-capacity threshold must install renewable generation and storage, buy renewable electricity and certificates, or pay a monetary substitute. The 2023 amendment added Article 12-1, obliging new and substantially rebuilt buildings to install rooftop solar.

Taiwan's 2017 Electricity Act rewrite opened the market from the renewable end first: it made the transmission and distribution business a single state-owned enterprise with ring-fenced accounts and a duty of non-discriminatory access, let renewable generators wheel power to users or supply them directly, created an Electricity Industry Regulatory Agency, and put tariffs under an Electricity Tariff Examination Council.

As Abu Dhabi's sole procurer, EWEC has awarded a series of gigawatt-scale solar projects at record-low tariffs and, in October 2025, broke ground with Masdar on the world's first gigascale round-the-clock renewable project: a 5.2 GW solar plant paired with a 19 GWh battery system designed to deliver 1 GW of baseload renewable power continuously, backed by more than AED 22 billion of investment and targeted at the emirate's artificial-intelligence and data-centre load.

FANR issued the operating licence for Barakah in February 2020 and the four Korean-designed APR1400 units entered commercial operation between April 2021 and 5 September 2024, giving the UAE 5,560 MW of nuclear capacity that supplies roughly 25 percent of national electricity and about 40 TWh of carbon-free output a year, and that has reshaped the despatch of the Abu Dhabi system.

Dubai runs the opposite model to Abu Dhabi: DEWA is utility, procurer and network owner under the Supreme Council of Energy, and since Law No. 6 of 2011 opened generation to private participation it has used the independent producer structure to build the 3,860 MW Mohammed bin Rashid Al Maktoum Solar Park in seven phases, alongside the 250 MW Hatta pumped-storage plant and the Warsan waste-to-energy facility, toward a Dubai Clean Energy Strategy target of 100 percent clean production capacity by 2050.

In 2023 the UAE put a federal legal framework around connecting renewable and clean-energy plants to the grid and, in the same year, updated the Energy Strategy 2050 to target roughly 30 to 35 percent clean generation by 2030-31, more than 28 GW of clean capacity and AED 150 to 200 billion of investment, turning what had been seven separate emirate programmes into a national build-out with a common connection right.

Abu Dhabi Law No. 11 of 2018 created the Department of Energy as the emirate's economic and technical regulator for electricity, water and wastewater; the DoE now licenses every generator, approves EWEC's capacity requirements, proposes tariffs to the Executive Council rather than setting them itself, binds the sector to a Clean Energy Strategic Target 2035 of 60 percent of electricity production from clean sources, and issues the Clean Energy Certificates policy that lets buyers claim solar and nuclear attributes.

Britain's first new support scheme for pumped hydro and other 8-hour-plus storage in decades: a revenue floor and cap modelled on the interconnector regime, opened by Ofgem in April 2025 with a first window that drew 171 applications (52.6 GW); Ofgem's June 2026 minded-to decisions selected 16 projects (7,645 MW), final awards are due in autumn 2026 and projects must be operational by 2030 to 2033.

Enacted 15 May 2025, the act creates Great British Energy, an Aberdeen-based state company with £8.3 billion over the Parliament to invest in, develop and own clean-energy projects alongside the Crown Estate and private capital, with a statutory bar on projects tainted by forced labour in their supply chains.

Ofgem approved NESO's reform in April 2025 to tear up the 750 GW-plus first-come-first-served connection queue and re-order it by readiness and by alignment with the Clean Power 2030 plan, with revised connection offers issued from late 2025 that move viable projects forward and push speculative ones out or to the 2030s.

On 10 July 2025 the government ended a three-year debate by rejecting locational (zonal) wholesale pricing for Great Britain and choosing reformed national pricing: strategic spatial planning, reformed transmission charges, constraint-management reforms and CfD changes to send locational signals without splitting the wholesale price.

The December 2024 plan sets a 2030 target of at least 95 percent clean generation with capacity ranges (43 to 50 GW offshore wind, 27 to 29 GW onshore, 45 to 47 GW solar, 23 to 27 GW batteries, 4 to 6 GW long-duration storage) and reforms the CfD scheme for AR7 with longer 20-year contracts, relaxed planning-consent entry rules and a Clean Industry Bonus, making the government's procurement the dominant driver of GB new build.

The largest UK energy statute in a decade: it created the publicly owned National Energy System Operator (live October 2024), gave Ofgem a net-zero duty, set up licensing and revenue models for hydrogen and carbon capture, brought heat networks under regulation and enabled competition in onshore transmission.

EIA's Annual Energy Outlook is the reference projection behind utility resource plans, RTO load forecasts and federal cost-benefit analyses. Laying AEO2015 to AEO2023 against actual 2015-2025 outcomes shows demand growth that every edition missed, coal retiring three times faster than projected, solar arriving nine times larger and gas burning harder than any edition assumed; AEO2025 and AEO2026 reset the demand path.

The IRA's technology-neutral production and investment credits were the largest subsidy in US power history; the July 2025 OBBBA cut wind and solar off for projects not started by 4 July 2026 or in service by end-2027, kept storage, nuclear and geothermal credits into the 2030s, and added foreign-entity restrictions.

FERC's rejection of the Talen-Amazon co-located deal, its PJM co-location proceeding (December 2025 directive and June 2026 compliance order), DOE's October 2025 directive on interconnection of loads above 20 MW and FERC's June 2026 show-cause orders to all six RTOs together decide how fast data centres connect and who pays for the grid they use.

After the 2025/26 auction cleared at $269.92/MW-day (up from $28.92), a settlement with Pennsylvania imposed a floor of about $175 and a cap of about $325/MW-day on the 2026/27 and 2027/28 Base Residual Auctions; FERC extended the collar in April 2026 to the 2028/29 and 2029/30 auctions, and all three auctions held so far cleared at the cap, signalling a structural capacity shortage.

Texas now requires loads of 75 MW or more to disclose duplicate requests and backup generation, pay interconnection study costs and standby charges, and accept curtailment or switch to on-site generation during grid emergencies, with PUCT approval needed for new behind-the-meter arrangements.

The 2024 Clean Air Act section 111 rule required 90 percent carbon capture by 2032 at coal plants running past 2039 and at new baseload gas units; EPA proposed repeal in June 2025 and on 14 September 2026 signed a final partial repeal (with a supplemental proposal to rescind the rest), so the binding constraint on coal retirements is now state policy and economics, not federal carbon rules.

Requires every transmission provider to plan 20 years ahead using at least three scenarios and seven named benefits, gives states a six-month window to shape cost allocation, and forces consideration of grid-enhancing technologies; compliance filings landed in 2025 and litigation is pending.

Replaces serial first-come-first-served interconnection studies with cluster studies, larger deposits, site-control proof and withdrawal penalties, and puts transmission providers on a 150-day clock with penalties for late studies.

Requires every transmission provider to rate lines hourly on actual temperature for the next ten days instead of a fixed seasonal number, unlocking transfer capability in cool hours; compliance was due 12 July 2025 and a dynamic-line-rating rulemaking is the next step.

Requires every FERC-jurisdictional RTO/ISO to let aggregations of 100 kW or more of batteries, rooftop solar, EVs and flexible load bid into energy, capacity and ancillary-service markets. The rule took effect on 21 December 2020, but market go-live is staggered: ISO-NE energy markets in November 2026, NYISO full compliance by end-2026, PJM in February 2028, and MISO and SPP around 2030.