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South Africa: 5 energy policy briefs

The energy policies moving South Africa’s power markets, one brief each: the problem, the mechanism, the market effect, who gains and who pays, where it stands on the path to binding law, and the official text.

Eskom MYPD6 · 30 January 2025 decision and the R54.7 billion RAB redetermination

South Africa · National Energy Regulator of South Africa (NERSA) · decision · 2025

Where it stands: Redetermined MYPD6 revenues are in tariffs from 1 April 2026 for Eskom customers and 1 July 2026 for municipalities

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 problem

Eskom's allowable revenue is set under a cost-of-service, rate-of-return methodology (MYPD4, published October 2016) that values a 40 GW coal fleet at depreciated replacement cost. Small changes in the regulatory asset base move tariffs by whole percentage points, and the parties have litigated the RAB repeatedly, including a 2022 court order on valuation. Eskom applied for revenues built on an average Generation RAB of R828 717 million in 2025/26 rising to R909 656 million in 2026/27; NERSA cut it, Eskom sued, and the resulting legal uncertainty sat directly on the tariff paid by every South African customer and on the cost base of every energy-intensive exporter.

What it does

At its meeting on 30 January 2025 the Energy Regulator approved Generation allowable revenue of R249 682 million for 2025/26, R258 574 million for 2026/27 and R257 734 million for 2027/28 (including approved RCA liquidation), against an application of R291 640 million, R323 952 million and R322 376 million, and set separate determinations for Distribution and for NTCSA. Reasons for Decision were published on 9 June 2025. Eskom filed a review on 26 June 2025 attacking the depreciated replacement cost, transfers to commercial operation, work under construction, component-level depreciation and RAB roll-forward, and proposed a settlement of R62 676 million; the Electricity Subcommittee recommended R54 billion and the Regulator settled on 30 July 2025. AfriForum and the Minerals Council interdicted the settlement in October 2025, and on 21 December 2025 the High Court reviewed and set aside the decision and remitted it for a procedurally fair redetermination. NERSA consulted (comments closed 21 January 2026) and, on 7 February 2026, approved revised Generation RAB-related revenues of R188 005 million (R70 678 million returns plus R117 327 million depreciation) against the R216 416 million applied for, cutting the WACC from 5% to 4.08% in 2026/27 and from 6% to 4.2% in 2027/28.

Market effect

The redetermination hands Eskom R54 734 million of additional revenue, all of it depreciation and none of it extra return, and NERSA chose phased recovery (Option 2): R12 000 million in 2026/27 and R23 013 million in 2027/28, with R19 721 million deferred beyond MYPD6. That converts the original headline path of 12.74%, 5.36% and 6.19% into 12.74%, 8.76% and 8.83%. Full recovery (Option 1) would have produced 12.21% and 7.39% with a sharper first-year shock; NERSA's own economic impact assessment put Option 1 at about 41 104 jobs lost in 2026/27 against 22 790 under Option 2, and GDP losses of R12 710 million versus R7 047 million. For an industrial buyer this is a roughly 8.8% nominal tariff step on 1 April 2026 for Eskom-supplied customers and 1 July 2026 for municipal customers, on top of a 12.74% step the year before. It sharpens the arithmetic behind wheeled private PPAs, rooftop PV and captive generation, and it is the single largest driver of the carbon-intensive industrial cost base outside coal and logistics.

Key numbers

Additional revenue from the redetermination
R54 734 million (R0 additional returns, R54 734 million additional depreciation)
Resulting price path
8.76% in 2026/27 and 8.83% in 2027/28 under phased recovery, against 5.36% and 6.19% before the redetermination
Generation allowable revenue approved 30 January 2025
R249 682m (2025/26), R258 574m (2026/27), R257 734m (2027/28)
WACC applied in the redetermination
4.08% in 2026/27 and 4.2% in 2027/28, cut from 5% and 6%
Deferred balance
R19 721 million recovered beyond the MYPD6 control period

Who gains and who pays

  • Eskom Holdings (gains): R54.7 billion additional allowable revenue; interest cover projected at 5.68x in 2026/27 and debt service cover at 1.46x.
  • Energy-intensive industry and mining (costs): Two consecutive double-digit or near-double-digit increases; the Minerals Council litigated the settlement.
  • Municipal distributors and their customers (costs): Bulk purchase cost rises from 1 July 2026 and is passed into separately approved municipal tariffs.
  • Private IPPs, wheeling traders and rooftop PV installers (gains): Every tariff step widens the spread against a private PPA or self-generation.
  • NERSA (obligation): Must run lawful, rational and transparent processes under PAJA after two adverse High Court outcomes.

Implementation

Eskom had to submit NERSA-approved tariffs to Parliament by 15 March 2026 for implementation on 1 April 2026; municipal tariffs follow on 1 July 2026 after separate NERSA approval of each municipality's schedule. The Reasons for Decision on the redetermination were published on 12 July 2026, with an annexure analysing stakeholder comments and an economic impact report. Regulatory Clearing Account applications continue to reopen closed years: NERSA decided the 2022/23 RCA (year 1 of MYPD5) on 9 May 2025, and the 2025/26 Eskom Retail Tariff and Structural Adjustment decision was issued the same day. The unresolved items are the treatment of the deferred R19 721 million after 2027/28, the next RCA liquidations, and whether AfriForum, the Minerals Council or Eskom return to court over the redetermination.

Concerns

  • The deferred R19.7 billion is an unfunded liability that lands in MYPD7 or a later RCA
  • Two successive High Court setbacks make every NERSA revenue decision reviewable and therefore provisional
  • Depreciated replacement cost valuation of ageing coal plant keeps the RAB, and the tariff, contestable
  • Tariff increases above inflation accelerate grid defection, shrinking the sales base that has to carry the same fixed costs
  • NERSA's own modelling projects 22 790 job losses in 2026/27 from the chosen option
  • Municipal arrear debt to Eskom is not addressed by the revenue determination

Dates to watch

  • 1 April 2027: Third MYPD6 year takes effect at 8.83% for Eskom-supplied customers
  • 1 July 2027: Municipal tariff implementation of the same determination
  • 2028: MYPD6 control period ends; MYPD7 application and the deferred R19.7 billion fall due

Sources

Checked against sources on .

Integrated Resource Plan 2025 · gazetted 28 October 2025, 6 GW of gas and 5.2 GW of nuclear

South Africa · Minister of Electricity and Energy under the Electricity Regulation Act 4 of 2006 · plan · 2025

Where it stands: Gazetted and being turned into section 34 determinations, NERSA concurrences and IPP Office bid windows

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.

The problem

The IRP 2019 assumed coal shutdowns and a renewables build that never happened on schedule, and its capacity allocations were exhausted by the ministerial section 34 determinations that followed. Meanwhile Eskom's energy availability factor collapsed, 8 GW of coal at Camden, Hendrina, Grootvlei and Arnot reached the end of a 50-year life by 2030, and the Cape wind and solar resource could not be evacuated to northern load centres. Because section 34 determinations, NERSA concurrences and REIPPPP bid windows can only procure what the IRP allocates, a stale plan froze procurement: without a gazetted allocation for gas, storage or nuclear at scale, the IPP Office had nothing to tender.

What it does

The IRP 2025 models a Reference Case plus Gas at Risk, Nuclear, Aggressive Battery Learning and Delayed Shutdown scenarios to 2050, scoring each on net present cost, total new capacity built, CO2 emissions and diversity. Gas at Risk and Nuclear both scored 3.5 out of 5, so the Proposed Balanced Plan blends them. For 2026 to 2030 it allocates 3 000 MW of gas through the IPP programme and 3 000 MW of Eskom gas, 10 313 MW of solar PV, 7 341 MW of wind, 4 500 MW of distributed generation and 3 723 MW of storage. For 2031 to 2042 it adds 12 250 MW of gas IPP, 5 200 MW of nuclear starting in 2036, 1 332 MW of pumped storage, 18 400 MW of solar PV, 35 700 MW of wind, 4 500 MW of distributed generation and 4 500 MW of storage, giving grand totals of 15 250 MW gas IPP, 3 000 MW Eskom gas, 5 200 MW nuclear, 28 713 MW solar PV, 43 041 MW wind, 9 000 MW distributed generation and 8 223 MW of storage. Three policy decisions are stated: keep Eskom's fleet energy availability factor above 60%; treat 6 GW of gas CCGT by 2030 with a minimum 50% load factor as essential when 8 GW of coal shuts; and demonstrate clean-coal technology by 2030. The plan is set against the discount rate of 11.3%, an exchange rate of R18.35/USD and a gas price of USD 15/GJ, with demand growing 2.3% a year.

Market effect

The gazetted allocation is the legal precondition for procurement, so the IRP 2025 reopens tenders that had stalled. On the public side it counts as committed the REIPPPP Bid Window 5 projects (1.2 GW, of which 0.8 GW wind and 0.4 GW solar in construction), 0.4 GW of Bid Window 6 solar, 0.4 GW of the Risk Mitigation IPPPP that reached financial close out of 2 GW offered, and 1.7 GW from Energy Storage IPPPP Bid Windows 1 to 3 plus a further 2 GW of four-hour storage for grid support; Bid Window 7 capacity is expressly excluded from committed capacity. A ministerial determination for 3 GW of gas was gazetted with 2 GW so far offered to the market. The 6 GW gas decision with a 50% minimum load factor is the single biggest commercial signal in the document because it anchors LNG import and upstream processing investment. On the grid side the plan carries the Transmission Development Plan 2024 result: 14 494 km of new lines by 2034, of which 5 044 km by 2029, 132 730 MVA of transformer capacity of which 41 325 MVA by 2029, eight synchronous condensers, 40 capacitors and 59 reactors, as generation grows from 66 GW in 2024 to 107 GW by 2034. That is the real constraint on the renewables allocation, and it is why the plan tells government to advance the Independent Transmission Project initiative.

Key numbers

Gazette reference
Government Notice 6767, Government Gazette 53596 of 28 October 2025 (replacing Gazette 53592, Notice 6765)
New capacity 2026-2030
6 000 MW gas, 10 313 MW solar PV, 7 341 MW wind, 4 500 MW distributed generation, 3 723 MW storage
Grand total to 2042
15 250 MW gas IPP, 3 000 MW Eskom gas, 5 200 MW nuclear, 43 041 MW wind, 28 713 MW solar PV, 8 223 MW storage
Transmission requirement (TDP 2024)
14 494 km of new lines and 132 730 MVA by 2034; 5 044 km and 41 325 MVA needed by 2029
Coal shutdown
8 GW by FY2030 (Camden, Hendrina, Grootvlei, Arnot); a further 15 GW between 2034 and 2042

Who gains and who pays

  • Gas-to-power developers and LNG importers (gains): 6 GW of CCGT by 2030 with a stated 50% minimum load factor, the anchor demand for import terminals.
  • Wind and solar developers (gains): 43 041 MW of wind and 28 713 MW of solar PV allocated to 2042, unlocking future REIPPPP bid windows.
  • Eskom Generation and coal supply chains (costs): 8 GW of coal shuts by 2030 and a further 15 GW between 2034 and 2042, with no new coal allocated.
  • NTCSA and transmission contractors (obligation): 14 494 km of new lines and 132 730 MVA of transformation by 2034, with servitude acquisition the primary delivery risk.
  • Battery storage suppliers (gains): 8 223 MW of storage allocated plus 2 GW of four-hour storage provisioned for grid support in the Cape.

Implementation

An IRP allocation only becomes procurement through a ministerial determination under section 34 of the Electricity Regulation Act, with NERSA concurrence, followed by an IPP Office request for proposals, preferred-bidder announcement and financial close. The Electricity Regulation Amendment Act 38 of 2024 extends section 34 to transmission infrastructure determinations covering the nature, type, extent, ownership, operation, maintenance and procurement of transmission assets, which is the legal basis for the Independent Transmission Projects programme the IRP 2025 tells government to advance. Any deviation from the IRP or the Transmission Development Plan must be gazetted for comment, and NERSA's tariff determinations must now take planned IRP and TDP projects into account under the new section 15(1A). The next gates are the outstanding 1 GW of the gazetted 3 GW gas determination, the Bid Window 7 award decision, the nuclear procurement framework needed before the 2036 commissioning assumption is credible, and the servitude and supply-chain constraints the TDP flags as its primary delivery risk.

Concerns

  • The 6 GW of gas by 2030 depends on LNG import infrastructure and a 50% load factor commitment that no procurement has yet contracted
  • Nuclear at 5 200 MW from 2036 requires a procurement framework, financing and a NERSA concurrence that do not exist
  • Transmission delivery of 14 494 km by 2034 is exposed to servitude acquisition, transformer supply chains and Eskom capitalisation
  • Flexibility analysis shows a peak-period shortfall of 6.5 to 12.7 GW by 2040 as variable renewables rise
  • No allocation is made beyond 2040, leaving the post-coal endgame undefined
  • Delayed coal shutdown, if used as a fallback, raises system cost by about R210 billion and CO2 by 23 Mt on the plan's own scoring

Dates to watch

  • 2026-Q4: Offer of the remaining 1 GW of the gazetted 3 GW gas determination and the Bid Window 7 decision
  • 2029: TDP milestone: 5 044 km of new lines and 41 325 MVA of transformation required
  • 2030: 8 GW of coal shutdown and the 6 GW gas CCGT commissioning assumption both fall due
  • 2036: Assumed start of the 5 200 MW nuclear build in the Proposed Balanced Plan

Sources

Checked against sources on .

Electricity Regulation Amendment Act · Act 38 of 2024 and the NTCSA transition

South Africa · Parliament of South Africa (assented by the President) · statute · 2024

Where it stands: In force and being applied by NERSA; TSO not yet incorporated, market code and platform still to be approved

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.

The problem

South Africa ran a single vertically integrated utility that generated, transmitted, dispatched and bought all wholesale power, which meant the same company that owned the coal fleet decided who got grid capacity and at what price. The consequence was a decade of load-shedding, an unbankable connection queue, and no legal route for a generator to sell to anyone other than Eskom. The Electricity Regulation Act 4 of 2006 contained no concept of a market operator, a balancing mechanism, a balance responsible party or a market code, so even after Eskom was told to legally separate its transmission arm, there was no statutory basis for competitive trading over the national grid.

What it does

The Act inserts definitions of ancillary services, balance responsible party and balancing mechanism, then inserts sections 34A and 34B. Section 34A(1) requires the Minister of Public Enterprises to establish a juristic person called the Transmission System Operator SOC Limited 'in order to provide an open market platform that shall allow for competitive electricity trading', with four statutory roles: transmitter, system operator, market operator and central purchasing agency. Section 34B(1) makes the transmitter responsible for the transmission development plan, for transmission use-of-system charges approved by the Regulator, and for non-discriminatory third-party access. Section 34B(3) requires the market operator to provide a transparent, non-discriminatory trading platform approved by NERSA and to develop a market code and rules, including qualifying criteria for participants and governance arrangements, covering both physical and financial transactions across market timescales. Section 35C is the transitional clause: from the effective date until the TSO is established, and for a period no longer than five years, the National Transmission Company South Africa SOC Limited (registration 2021/539129/30) is deemed to be the TSO, must perform its duties independently and with fair and equitable treatment of all system users, and must be licensed by NERSA for those functions. The Act also extends section 34 ministerial determinations beyond new generation capacity to transmission infrastructure, adds offences carrying fines up to R5 000 000 or ten years' imprisonment, and commences on a date determined by the President under section 33.

Market effect

The Act converts a single-buyer system into a scheduled multi-market, and the value of a South African generation asset now depends on where it sits in that transition. Roughly 6.2 GW of utility-scale renewables procured under the REIPPPP (3.3 GW wind, 2.3 GW solar PV, 0.6 GW CSP) plus a private pipeline the IRP 2025 puts at about 8 GW operational, under construction or holding a budget quotation still sell under long-term PPAs to the central purchasing agency, so their cash flows are unaffected in the near term. New entrants, traders and large industrial offtakers get a statutory right to a NERSA-approved trading platform, which is why NTCSA has stood up the South African Wholesale Electricity Market (SAWEM), a South African Wholesale Market Code and a SAWEM School to qualify participants. Because section 34B(1)(c) puts transmission use-of-system charges under NERSA approval and section 34B(1)(d) mandates non-discriminatory access, wheeling economics stop being an Eskom commercial decision and become a regulated tariff question. The five-year cap in section 35C is the timing risk for lenders: if the standalone TSO is not incorporated, the deemed-TSO arrangement leaves market operation inside an Eskom subsidiary whose balance sheet also carries the generation fleet.

Key numbers

Transitional period
No longer than five years for NTCSA to act as deemed TSO (section 35C(1))
Statutory roles of the TSO
Four: transmitter, system operator, market operator, central purchasing agency (section 34A(2))
Maximum penalty
R5 000 000 fine or ten years' imprisonment for the aggravated offences added by the Act
Gazette reference
Act 38 of 2024, assented 16 August 2024, Government Gazette 51100 of 20 August 2024 (Presidency Notice 5139)

Who gains and who pays

  • Traders, aggregators and large industrial offtakers (gains): A statutory open market platform and regulated non-discriminatory grid access replace bilateral negotiation with Eskom.
  • National Transmission Company South Africa (NTCSA) (obligation): Deemed TSO under section 35C; must operate independently, build market systems and hold NERSA licences for all four roles.
  • Eskom Generation (costs): Loses privileged access to dispatch and to the buyer; must compete in a market it no longer operates.
  • Municipal distributors (mixed): Gain the right to buy from third parties but lose the surplus margin on resale of Eskom bulk supply.
  • IPPs with existing REIPPPP PPAs (mixed): Contracts novate to the central purchasing agency; counterparty and credit support arrangements change.

Implementation

Commencement is by presidential proclamation under section 33; NERSA's February 2026 redetermination of Eskom's MYPD6 Generation revenue already applies 'the Electricity Regulation Act, 2006 (Act No. 4 of 2006), as amended by Act No. 38 of 2024', including the new section 15(1A) duty to take the IRP and the Transmission Development Plan into account and the section 15(1B) duty to set separate tariffs for each licensed activity, so the operative provisions are in force. The remaining work is secondary: NERSA must approve the market code and the trading platform, license NTCSA for the TSO functions, and settle transmission use-of-system charges. The Department of Electricity and Energy published an Electricity Sector Market Transformation Position Paper, 2026 in Government Gazette 55226 of 21 August 2026 (Notice 7841) with comments due by 20 September 2026, and a Revised Electricity Pricing Policy in Gazette 55257 (Notice 7852) with comments due 28 September 2026. Those two documents, not the Act, will decide how fast the multi-market opens and how wheeling is priced.

Concerns

  • The standalone TSO has not been incorporated; the five-year clock in section 35C is running with NTCSA still an Eskom subsidiary
  • Market operator independence is hard to demonstrate while the same group owns 40 GW of coal generation
  • The market code, qualifying criteria and platform all require separate NERSA approval and can slip
  • Transmission capacity, not market rules, is the binding constraint on new entry in the Cape resource regions
  • Municipal distributors' revenue model and Eskom's arrear debt from municipalities are unresolved by the Act
  • Section 34 determinations for transmission infrastructure are new and untested against procurement law

Dates to watch

  • 20 September 2026: Comments close on the Electricity Sector Market Transformation Position Paper, 2026 (Gazette 55226, Notice 7841)
  • 28 September 2026: Comments close on the Revised Electricity Pricing Policy (Gazette 55257, Notice 7852)
  • 2029: Outer limit of the five-year section 35C transition in which the standalone TSO must be established

Sources

Checked against sources on .

Schedule 2 licensing exemption · unrestricted capacity registration and wheeling

South Africa · Minister of Mineral Resources and Energy under sections 9(1) and 36(4) of the Electricity Regulation Act · notice · 2022

Where it stands: Substituted Schedule 2 operating; registration with NERSA replaces licensing for grid-connected generation of any size

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 problem

Under the original Schedule 2 any grid-connected generator above 1 MW needed a NERSA generation licence, a process that routinely took a year or more and required a ministerial section 34 determination for anything selling to a third party. With Eskom's energy availability factor below 60% and load-shedding running at record levels in 2021 and 2022, the licensing queue was the binding legal constraint on private capacity that mines, smelters and retailers were willing to fund themselves. Raising the threshold to 100 MW in August 2021 (Notice 737 of 12 August 2021, corrected by Notice 751 in Gazette 45023 of 20 August 2021) helped, but it still capped project size below the scale at which wind and solar plants in the Northern and Western Cape are efficient.

What it does

The substituted Schedule 2 restructures the exemption into three tiers. Activities wholly exempt from licensing and registration include standby or back-up generation during a supply interruption, any facility of any capacity with no point of connection, and facilities up to 100 kilowatts that comply with the code and are entered on a distributor's register. The pivotal tier is item 3.1: 'the operation of any generation Facility with or without energy storage, of unrestricted capacity, with a Point of Connection on the transmission or distribution power system' is exempt from licensing but must comply with the code and be registered with NERSA, in three cases: supply to one or more customers without wheeling; supply to one or more customers by wheeling, where the generator has a connection agreement with the holder of the transmission or distribution licence over whose network the electricity is wheeled; and a facility with a connection point that neither exports nor imports. Schedule 2 defines wheeling for the first time as conveyance from the point of connection to a point of consumption through a third-party network. Distribution facilities up to the point of connection and resellers are also brought into the registration regime under section 9(1).

Market effect

Removing the cap decoupled project size from the licensing calendar and moved the bottleneck to grid capacity and offtaker credit. The IRP 2025 records about 6 GW of small-scale embedded rooftop PV already installed and assumes a further 900 MW a year of rooftop PV to 2035, and it describes a private pipeline in which roughly 55%, about 8 GW, is operational, under construction or holds a budget quotation, with the remaining 45% queued under the Interim Grid Capacity Allocation Rules on a first-come, first-served basis. That is a private build comparable in scale to the 6.2 GW procured through the whole REIPPPP (3.3 GW wind, 2.3 GW solar PV, 0.6 GW CSP) over more than a decade. Commercially the regime created a South African corporate PPA and trading market: registered generators sell directly to mines, retailers and data centres and pay regulated use-of-system charges, while Eskom loses its highest-margin industrial sales volume. The residual risks are not legal but physical and financial: connection capacity in the Cape resource regions, curtailment, and the credit of municipal networks over which power is wheeled.

Key numbers

Licensing threshold
1 MW until August 2021, 100 MW from August 2021, unrestricted capacity under the substituted Schedule 2
Fully exempt tier
Facilities up to 100 kW with a point of connection, plus all back-up and off-grid facilities
Private pipeline
About 8 GW operational, under construction or holding a budget quotation (roughly 55% of the pipeline); the balance sits in the IGCAR queue
Rooftop PV
About 6 GW of small-scale embedded generation installed; IRP 2025 assumes 900 MW a year to 2035

Who gains and who pays

  • Private IPPs, corporate PPA developers and traders (gains): Unrestricted project size with registration rather than licensing, and an express statutory route to wheel.
  • Mines, smelters, retailers and data centres (gains): Can contract directly for firmed renewable supply and hedge against 12.74% and 8.76% Eskom tariff steps.
  • Eskom Distribution and municipal distributors (costs): Lose high-consumption industrial and commercial customers while retaining fixed network costs.
  • NERSA (obligation): Must run a registration regime at volume and police grid-code compliance without the leverage of licensing.
  • Network owners hosting wheeling (mixed): Earn regulated use-of-system charges but must offer non-discriminatory connection agreements.

Implementation

Registration is administered by NERSA and the relevant distributor, and the exemption bites only once a connection agreement and grid-code compliance are in place, which is why the Interim Grid Capacity Allocation Rules and the Transmission Development Plan now determine project timing rather than the Minister's notice. The Electricity Regulation Amendment Act 38 of 2024 layers a market code and a regulated open market platform on top, so registered generators will eventually trade through the South African Wholesale Electricity Market rather than only bilaterally. Two live consultations will reset the economics: the Revised Electricity Pricing Policy gazetted on 21 August 2026 (Gazette 55257, Notice 7852, comments due 28 September 2026), which governs how wheeling and use-of-system charges are built, and the Electricity Sector Market Transformation Position Paper, 2026 (Gazette 55226, Notice 7841, comments due 20 September 2026).

Concerns

  • Grid connection capacity, not licensing, is now the constraint, and the IGCAR queue is first-come first-served rather than merit-based
  • Wheeling tariffs and loss factors are set by the network owner subject to NERSA approval, leaving pricing risk with the offtaker
  • Municipal networks used for wheeling often have weak credit and poor metering
  • Registered generators still need environmental authorisation, land use approval and servitudes
  • Loss of industrial load worsens the fixed-cost recovery problem inside the regulated tariff
  • The final 17 January 2023 notice is published as a scanned gazette image, so the operative wording should be checked against the printed text

Dates to watch

  • 28 September 2026: Comments close on the Revised Electricity Pricing Policy, which sets the wheeling and use-of-system charging framework
  • 2026-Q4: Next Interim Grid Capacity Allocation Rules round and NTCSA grid capacity statement updates
  • 2027: Expected NERSA approval of the wholesale market code that registered generators will trade under

Sources

Checked against sources on .

Carbon Tax Act 15 of 2019 · phase 2 and R308 per tonne from 1 January 2026

South Africa · Parliament of South Africa (National Treasury and SARS administer) · statute · 2019

Where it stands: In force since 1 June 2019 and collected by SARS; phase 2 began on 1 January 2026 at R308 per tonne

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.

The problem

South Africa's electricity system is about 60% coal by installed capacity and its industrial base is among the most emissions-intensive of any middle-income economy, yet until 2019 emitting carbon was free. The country needed a price signal compatible with its nationally determined contribution and, from 2026, with the EU carbon border adjustment mechanism that taxes the embedded carbon in its steel, aluminium and cement exports. The political constraint was that a meaningful carbon price applied to Eskom would land directly on an electricity tariff already rising faster than inflation, so the Act was designed with a long allowance ladder and an explicit electricity-sector offset rather than a headline rate that bites immediately.

What it does

Section 5 imposes the tax at R120 per tonne of CO2 equivalent, increased by consumer price inflation plus two per cent per year until 31 December 2022 and by inflation alone thereafter. Sections 7 to 13 create the allowances: a basic tax-free allowance for fossil-fuel combustion set at 60% for most activities in Schedule 2, allowances for industrial process and fugitive emissions, a trade-exposure allowance capped at ten per cent, a performance allowance, a five per cent carbon budget allowance for taxpayers participating in the mandatory carbon budget system, and an offset allowance. Section 14 caps the sum of allowances at 95% of a taxpayer's emissions unless Schedule 2 sets the maximum at 100%. Section 6(2) applies a separate formula to electricity generated from fossil fuels, deducting a gazetted renewable energy premium and the environmental levy on electricity generated in the Republic. Section 15 makes SARS administer the tax as an environmental levy under the Customs and Excise Act. A section 17A inserted in 2025 gives a refund where an entity complies with its five-year carbon budget, and the 2026 Budget proposes replacing the capacity-based threshold for commercial and institutional back-up generators (IPCC code 1A4a) with a 25 000 tonne CO2e emissions threshold from 1 January 2026.

Market effect

The step from R236 to R308 per tonne on 1 January 2026 is a 30.5% increase in the headline price and the largest single-year move since the tax began, and it marks the start of phase 2 in which the allowance ladder narrows. For a coal unit emitting roughly one tonne of CO2e per megawatt-hour, R308 per tonne is about 30.8c/kWh gross, but a 60% basic allowance and the 95% cap mean the effective rate on most combustion emitters is a small fraction of that, which is why carbon tax remains a modest line in Eskom's MYPD6 allowable revenue relative to primary energy. The commercial consequence is at the margin rather than in the average: it improves the relative economics of a registered private solar or wind PPA against an Eskom tariff, it makes gas-fired capacity cheaper per unit of output than coal, and it gives South African exporters a domestic carbon price they can set against a CBAM liability. Carbon tax collections of about R2.4 billion in the current Budget's estimates, against total tax revenue in the trillions, show the rate is still policy signalling rather than a revenue instrument, and the phase-2 trajectory is the variable to model, not the 2026 rate.

Key numbers

Headline rate
R120/tCO2e from 1 June 2019; R236/tCO2e in 2025; R308/tCO2e from 1 January 2026
Escalator
CPI plus two per cent to 31 December 2022, CPI thereafter (section 5(2) and 5(3))
Allowances
60% basic combustion allowance, 10% trade exposure cap, 5% carbon budget allowance, 95% cap on the sum (section 14)
Carbon fuel levy
19c/litre petrol and 23c/litre diesel from 1 April 2026; cost-recovery quantum up from 0.99c to 1.29c/litre

Who gains and who pays

  • Coal-fired generators and energy-intensive industry (costs): Pay the levy on combustion emissions above allowances; phase 2 narrows the allowance ladder.
  • Renewable and gas generators (gains): Relative merit-order advantage widens with each rate step; gas emits roughly half the CO2 per MWh of coal.
  • Exporters of steel, aluminium and cement to the EU (gains): A domestic carbon price paid can be set against the EU carbon border adjustment liability.
  • Electricity consumers (costs): Carbon tax on Eskom generation is an allowable cost recovered through the MYPD6 tariff.
  • Commercial and institutional back-up diesel generator operators (mixed): Proposed move to a 25 000 tCO2e threshold from 1 January 2026 removes most from the net.

Implementation

SARS collects the tax as an environmental levy through the Customs and Excise Act with an annual account and payment cycle on eFiling, tariff items having been inserted into Part 3F of Schedule No. 1 with retrospective effect to 1 June 2019. The rate is reset each year by the Rates and Monetary Amounts and Amendment of Revenue Laws Act, and the phase-2 design is being built through the annual Taxation Laws Amendment Bill: the 2025 bill inserted section 17A to refund tax paid on emissions above a mandatory carbon budget where the taxpayer complies over the five-year budget period, and the 2026 Budget proposes deleting the ambiguous reference to 'the immediately preceding tax period', allowing a refund claim in the third year for the first two tax periods and in the sixth year for the whole five-year period, and amending the Customs and Excise Act so the two-year prescription period does not defeat those claims. Carbon budgets themselves are allocated by the Department of Forestry, Fisheries and the Environment under the Climate Change Act 22 of 2024, so the tax and the budget system are now legally linked.

Concerns

  • The 60% basic allowance and the 95% cap keep the effective rate far below the headline, blunting the abatement signal
  • Phase-2 allowance reductions after 2030 are not fixed in legislation, so long-dated project models rest on policy intent
  • Interaction with the electricity environmental levy and the renewable energy premium deduction has been repeatedly extended and remains in flux
  • Carbon budget refunds under section 17A depend on the Climate Change Act allocation process that is still being stood up
  • Passing the tax through Eskom's MYPD6 revenue makes it an electricity tariff increase rather than a producer incentive
  • EU CBAM recognition of the South African carbon price net of allowances is unresolved

Dates to watch

  • 2027-02: Budget 2027 sets the carbon tax rate for the 2027 calendar year and the fuel levy from 1 April 2027
  • 2027-07: Annual carbon tax account and payment for the 2026 tax period, the first at the phase-2 rate
  • 2030: End of the period over which the 60% basic combustion allowance has been signalled to hold

Sources

Checked against sources on .