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Kenya: 5 energy policy briefs

The energy policies moving Kenya’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.

Electricity Market, Bulk Supply and Open Access Regulations · Legal Notice 79 of 2026

Kenya · Cabinet Secretary for Energy and Petroleum on the recommendation of EPRA · regulation · 2026

Where it stands: Gazetted and commenced 8 May 2026; market operational procedures, portal and wheeling charges still to be approved

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.

The problem

Section 131 of the Energy Act 2019 required EPRA to review the electricity market within three years of March 2019 and the Cabinet Secretary to publish regulations for its operation. That did not happen on time, so through 2022 to 2025 Kenya remained a strict single-buyer system: every kilowatt-hour was sold to Kenya Power under an EPRA-approved PPA and resold at a gazetted retail tariff. A factory that wanted cheaper geothermal or solar had only two options, a behind-the-meter captive plant on its own site or nothing, which is why captive capacity reached 630.1 MW by December 2025, more than half of it solar. There was no legal wheeling framework, no definition of an eligible consumer, no spot or forward market, and no congestion-management rule, while system losses of 22.07% ran 5.57 percentage points above the 16.50% allowed in the tariff.

What it does

Part II establishes the electricity market under section 131(2) with nine classes of participant (system operator, generation, transmission, distribution and retail licensees, eligible consumers, consumers, exporters and importers) trading through bilateral contracts, a spot market or forward contracts, across generation, capacity and energy market categories. The system operator, designated under section 138, gains market operational functions: registering participants, running an online market portal for buy and sell orders, matching supply and demand, clearing and settling transactions, holding performance security accounts, charging EPRA-approved processing fees and trading commissions, and reporting demanded and supplied capacity, market capacity prices, wheeling capacity and wheeled energy to the Authority. Part III allows a generation licensee to supply in bulk to another licensee for resale, or to an eligible consumer for own use under a bulk supply contract EPRA must approve, with the eligible consumer's load no less than 1 MVA on the distribution system or 10 MVA on the transmission system; the supplier must answer within thirty days and EPRA within sixty days of receiving the initialled agreement. Part IV obliges every network service provider to grant non-discriminatory open access: a thirty-day technical assessment, a no-objection from the system operator, a decision within forty-five days, a draft wheeling agreement, and EPRA approval within sixty days. Contracts are categorised as long term (five years or more), medium term (one to five years), short term (up to one year) or day-ahead and contingency. Regulation 40 puts allowable system losses on the parties to the bulk supply agreement and losses above the allowance on the network service provider. Regulation 42 gives the system operator dispatch priority and curtailment powers to relieve congestion, and regulation 19 routes regional trade through bilateral agreements or Eastern Africa Power Pool rules.

Market effect

This is the first legal route in Kenya for a generator to sell to anyone other than Kenya Power over the public grid, and it prices that route. A 1 MVA distribution-connected industrial site, or a 10 MVA transmission-connected one, can now contract directly with a geothermal, solar or wind licensee and pay EPRA-approved wheeling and use-of-system charges instead of a retail tariff that ran between KSh 24.90 and KSh 29.34 per kWh for commercial and industrial categories in the second half of 2025. For a large commercial customer that headline is built from a base tariff plus pass-through costs that swung between KSh 4.55 and KSh 5.68 per kWh and taxes and levies near KSh 4.65 per kWh, so the arbitrage is real. Putting excess losses on the network owner rather than the contracting parties is the sharpest commercial provision in the text: Kenya Power's losses at 22.07% against a 16.50% allowance become its own cost on wheeled volumes. The counterweight is regulation 22: during the transitional phase participation is voluntary, so Kenya Power is not compelled to put its portfolio into the pool, and licensees who do trade must disclose price and quantity to the system operator. Regulation 42 lets the system operator curtail to relieve congestion, which is the practical risk for a wheeled contract on a network where transmission from geothermal fields in the Rift to Nairobi is already constrained.

Key numbers

Eligibility threshold
Load of at least 1 MVA on the distribution system or 10 MVA on the transmission system (regulations 24(3) and 35(2))
Open access timetable
30 days for technical assessment, 45 days for the network provider's decision, 60 days for EPRA approval of the wheeling agreement
Contract tenors
Long term 5 years or more, medium term 1 to 5 years, short term up to 1 year, plus day-ahead and contingency
Loss allocation benchmark
Kenya Power's system losses were 22.07% in the half year to December 2025 against a 16.50% allowance in the tariff schedule

Who gains and who pays

  • Eligible consumers above 1 MVA (distribution) or 10 MVA (transmission) (gains): First statutory right to buy bulk power direct from a generator and wheel it.
  • Generation licensees and C&I developers (gains): Can sell outside the single-buyer PPA through bilateral, spot or forward contracts.
  • Kenya Power (costs): Loses its highest-value industrial load and absorbs losses above the 16.50% allowance on wheeled energy.
  • The designated system operator (obligation): Must build registration, a market portal, matching, clearing, settlement and performance security within EPRA-approved procedures.
  • KETRACO and distribution licensees (mixed): Earn approved wheeling charges but must grant non-discriminatory access on a 30/45-day clock.

Implementation

The regulations commenced on gazettement on 8 May 2026 but nothing trades until the system operator, with EPRA's approval, publishes electricity market operational procedures under regulation 10, sets the performance-security percentage under regulation 11, and stands up the online market portal. Tariffs for wheeling, use of system and ancillary services are set under the separate electricity tariff regulations and guidelines, so the charging framework is the gate that decides whether wheeling is economic. Bulk supply, ancillary service, open access application and wheeling agreements all follow prescribed forms in the Third to Sixth Schedules, and the first market structure is set out in the First Schedule following the first market review. Complementary instruments are already in force: the Energy (Net-Metering) Regulations 2024 (Legal Notice 104 of 26 July 2024) for smaller renewable systems exporting to the distribution network, and the Energy (Integrated National Energy Plan) Regulations 2025 (Legal Notice 83 of 7 May 2025). As a statutory instrument, Legal Notice 79 must be laid before the National Assembly and can be annulled by the Committee on Delegated Legislation.

Concerns

  • Participation is voluntary in the transitional phase, so the pool may stay thin while Kenya Power keeps its portfolio bilateral
  • Market operational procedures, performance security levels and the trading portal do not yet exist
  • Wheeling and use-of-system charges are set elsewhere and can make open access uneconomic at the margin
  • The system operator is not yet institutionally separate from Kenya Power, the dominant buyer and network owner
  • Regulation 42 gives the system operator unilateral curtailment powers to relieve congestion, with no compensation rule
  • The 1 MVA and 10 MVA thresholds exclude most commercial customers from direct purchase

Dates to watch

  • 2026-Q4: Publication of the system operator's electricity market operational procedures under regulation 10
  • 2027: First EPRA-approved wheeling agreements and the first reported wheeled energy volumes
  • 2027-H2: End of the transitional phase in which market participation is voluntary

Sources

Checked against sources on .

Kenya retail electricity tariff · the March 2023 control period and the withdrawn 2026 review

Kenya · Energy and Petroleum Regulatory Authority · decision · 2023

Where it stands: March 2023 base tariff still billing, with monthly gazetted pass-throughs; the 2026/27 to 2028/29 application was withdrawn

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 problem

Kenya Power's tariff has to carry a power purchase bill dominated by long-term capacity payments, system losses running well above the regulated allowance, and hard-currency debt, all in a currency that moved sharply against the dollar between 2022 and 2024. After the 2021 Presidential PPA Taskforce the government imposed a headline discount that was not matched by a reduction in underlying costs, so the utility ran on deferred recovery. The regulator then had to rebuild a cost-reflective base tariff without triggering the public backlash that had produced the discount in the first place, and to do it under section 10 of the Energy Act, which lets EPRA review tariffs on its own motion and requires county-level public participation before any decision.

What it does

EPRA approved the base tariff for the 2022/23 to 2025/26 control period in March 2023, restructuring the customer categories and setting energy charges by voltage level. For the 2025/26 financial year the base energy charge ran from KSh 12.14 per kWh for domestic consumption up to 30 kWh a month and KSh 16.50 for 30 to 100 kWh, to KSh 18.57 above 100 kWh; small commercial from KSh 12.28 to KSh 19.00; commercial and industrial from KSh 13.44 at 415 volts with a KSh 1 100 demand charge down to KSh 10.00 at 220 kilovolts with a KSh 200 demand charge; special economic zones at KSh 10.00; electric mobility at KSh 16.00; and street lighting at KSh 9.15. On top of the base sit monthly gazetted pass-throughs: a fuel energy charge that moved between KSh 2.99 per kWh in August 2025 and KSh 3.81 in November 2025, a foreign exchange rate fluctuation adjustment that fell from KSh 1.7742 per kWh in July 2025 to KSh 0.6809 in December 2025, a Water Resources Authority levy of about KSh 0.013 per kWh, and a biannual inflation adjustment held at KSh 0.44 per kWh through the period. In April 2023 EPRA extended the time-of-use tariff, which gives a 50 per cent discount on the energy charge between 2200 and 0600 on weekdays and across most of Saturday, Sunday and public holidays, to small commercial and electric mobility customers.

Market effect

The retail tariff is the reference price against which every private PPA, captive solar project and wheeling deal in Kenya is judged, and the arithmetic is transparent. For the DC3 domestic category, the largest group in the domestic class, December 2025 billed KSh 27.65 per kWh made up of a KSh 18.57 base tariff, KSh 4.55 of pass-through costs and KSh 4.67 of taxes and levies, so base tariff is 67.16 per cent of the bill, pass-throughs 16.46 per cent and taxes 16.89 per cent. Commercial and industrial customers paid between KSh 24.90 and KSh 29.34 per kWh across the second half of 2025 depending on voltage, and special economic zone and e-mobility customers KSh 16.25 to KSh 18.49. Against that, a 1.9 to 2.1 MW rooftop solar PPA of the kind EPRA approved for two Coca-Cola plants, or a wheeled geothermal contract under the 2026 open access regulations, prices well below the C&I tariff, which is why captive capacity reached 630.1 MW by December 2025 with 326.7 MW of it solar. Time-of-use volumes rose from 84.9 GWh to 148 GWh year on year and saved beneficiaries KSh 971.0 million in six months. The withdrawal of the fifth control period application in June 2026 leaves the 2023 base tariff running past its stated end date, which defers Kenya Power's revenue recovery and raises the probability of a larger catch-up later.

Key numbers

Control period
Base tariff approved in March 2023 for 2022/23 to 2025/26; fifth control period 2026/27 to 2028/29 application withdrawn
DC3 retail tariff, December 2025
KSh 27.65/kWh = KSh 18.57 base + KSh 4.55 pass-through + KSh 4.67 taxes and levies
Pass-through range, July to December 2025
Fuel energy charge KSh 2.99 to 3.81/kWh; FERFA KSh 0.6809 to 1.7742/kWh; inflation adjustment KSh 0.44/kWh
Time-of-use outcome
148 GWh sold and KSh 971.0 million saved in the six months to December 2025, up from 84.9 GWh
System losses
22.07% of energy purchased, 5.57 percentage points above the 16.50% allowed in the 2025/26 tariff schedule

Who gains and who pays

  • Industrial and commercial consumers (gains): The withdrawn 2026 application means no base tariff increase for now, on top of falling forex pass-throughs.
  • Kenya Power (costs): Continues to recover on a base tariff set in March 2023 while carrying 22.07% system losses against a 16.50% allowance.
  • Captive solar and C&I PPA developers (gains): A KSh 25 to 29 per kWh C&I retail benchmark keeps behind-the-meter and wheeled supply economic.
  • EPRA (obligation): Must run county public participation and decide by gazette notice; its independence was tested by the June 2026 withdrawal.
  • Domestic lifeline consumers (gains): Protected band at KSh 12.14 per kWh for the first 30 kWh a month plus time-of-use discounts.

Implementation

A tariff review starts with a Kenya Power application, which EPRA publishes, tests against its cost-of-service work, and takes to public consultative forums in the counties before deciding by gazette notice with a stated effective date. That sequence broke in 2026: the application was lodged on 31 March 2026, the forums scheduled to begin on 25 May 2026 were postponed by public notice on 24 May, and on 5 June 2026 EPRA announced that the application had been withdrawn 'following consultations within Government as well as engagement with key sector stakeholders, on the need to forestall escalation of electricity cost'. Monthly fuel, forex and Water Resources Authority pass-through notices continue to be gazetted, and the biannual inflation adjustment continues to apply, so the bill still moves month to month even with the base frozen. Any decision EPRA eventually makes can be appealed to the Energy and Petroleum Tribunal and then the High Court.

Concerns

  • A base tariff set in March 2023 is now operating beyond its stated control period with no replacement decision
  • Withdrawal of the application under government pressure cuts against EPRA's statutory independence under section 9(3)
  • Deferred recovery accumulates and usually returns as a sharper increase in the next control period
  • System losses 5.57 points above the allowance are a real cost that neither the tariff nor a wheeling counterparty absorbs
  • Forex pass-through exposure remains structural while power purchase costs and utility debt are dollar-denominated
  • The gazette notice number and effective date of the March 2023 decision should be confirmed before it is cited in a contract

Dates to watch

  • 2026-Q4: Whether Kenya Power refiles the fifth control period tariff application after the June 2026 withdrawal
  • 2027-01: Biannual inflation adjustment reset on end-user tariffs
  • 2027-H1: Earliest realistic effective date for a fifth control period base tariff if an application is refiled

Sources

Checked against sources on .

Ethiopia–Kenya 500 kV HVDC link · 2,000 MW of capacity, 200 MW contracted

Kenya · KETRACO and Kenya Power, with EPRA approval of the import power purchase agreement · decision · 2022

Where it stands: Link energised and importing commercially; 200 MW contracted against 2,000 MW of rated capacity, with transit wheeling to Tanzania

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.

The problem

Kenya's own fleet is cheap at the margin when the rains come and expensive when they do not: hydro is 23.78 per cent of installed capacity and heavy fuel oil and kerosene thermal plants, at 17.12 per cent, are the swing resource whose fuel cost passes straight into the monthly fuel energy charge. Geothermal, the largest single technology at 25.72 per cent, is baseload and cannot follow load. Ethiopia, meanwhile, had commissioned hydro capacity far ahead of its domestic demand and needed hard-currency export revenue. Neither country could realise that trade without a high-capacity link across more than a thousand kilometres of sparsely populated territory, nor without a legal framework for cross-border dispatch coordination that Kenya's pre-2019 energy law did not contain.

What it does

KETRACO built the Kenyan 612 km section of a 1,045 km HVDC line operating at 500 kV with a transfer capacity of 2,000 MW, terminating at a converter station at Suswa on the edge of the Rift Valley; Ethiopian Electric Power built the section from Welayta Sodo. Kenya Power and Ethiopian Electric Power signed a long-term import power purchase agreement that EPRA had to approve under section 10 of the Energy Act 2019 as a power purchase contract, with initial contracted capacity of 200 MW rising over the term. Section 138(2)(e) of the Energy Act requires the designated system operator to coordinate with the system operators of interconnected countries, and regulation 19 of the Energy (Electricity Market, Bulk Supply and Open Access) Regulations 2026 now provides that trade within the Eastern Africa region is conducted under bilateral agreements or Eastern Africa Power Pool rules, with system operation coordinated between the interconnected national operators or by the EAPP operator. The same link has been used for onward trade: EPRA records a net export of 136.55 GWh to Tanzania in the half year to December 2025 under an Ethiopia–Kenya–Tanzania wheeling arrangement, making Kenya a transit country rather than only an importer. KETRACO is building three further regional links in parallel: the 1,200 MW Lessos–Tororo line to Uganda, which raises Kenya–Uganda transfer capacity to 350 MW; the Isinya–Arusha–Singida 400 kV link to Tanzania rated at least 1,600 MW; and a 400 kV Kenyan component of the NELSAP interconnection toward Rwanda, Burundi and eastern DR Congo.

Market effect

Imports are now the cheapest block in Kenya's merit order and the fastest-growing. In the six months to December 2025 Kenya imported 939.23 GWh against 751.95 GWh a year earlier, an increase of 187.28 GWh or 24.9 per cent, out of total grid generation of 7,807.07 GWh, so imports are roughly 12 per cent of energy while occupying only 200 MW of the 3,193 MW of grid-connected capacity. That displaces heavy fuel oil, which still grew 24.27 per cent to 706.9 GWh as demand rose, and it is the main reason the fuel energy charge stayed in a narrow band of KSh 2.99 to KSh 3.81 per kWh through the period while peak demand set a record of 2,439.06 MW on 3 December 2025. For a trader the link turns Kenya into a node rather than a cul-de-sac: with 2,000 MW of rated capacity against 200 MW contracted, the headroom for further import contracts, for wheeling to Tanzania, and eventually for Eastern Africa Power Pool trading under the 2026 market regulations is large. The exposures are hydrological and political: Ethiopian export availability depends on the same East African rainfall that drives Kenyan hydro, and a single 500 kV bipole is a concentrated contingency for a system whose reserve margin above a 2,439 MW peak is thin.

Key numbers

Link specification
500 kV HVDC, 1,045 km total with 612 km in Kenya, 2,000 MW transfer capacity, Welayta Sodo to Suswa
Import capacity in the Kenyan fleet
200 MW installed and effective as at December 2025, out of 3,193 MW grid-connected
Imported energy
939.23 GWh from Ethiopia and Uganda in July to December 2025, up 187.28 GWh (24.9%) year on year
Transit trade
Net export of 136.55 GWh to Tanzania under the Ethiopia-Kenya-Tanzania wheeling arrangement in the same period
Other regional links under construction
Kenya-Uganda 1,200 MW (350 MW transfer), Kenya-Tanzania 400 kV at 1,600 MW or more, NELSAP 400 kV

Who gains and who pays

  • Kenyan consumers (gains): Cheap imported hydro displaces heavy fuel oil and holds the fuel energy charge between KSh 2.99 and KSh 3.81 per kWh.
  • Ethiopian Electric Power (gains): Hard-currency export revenue from surplus hydro over a 2,000 MW rated link.
  • Kenyan heavy fuel oil IPPs (costs): Displaced further down the merit order; the same plants the 2021 PPA taskforce targeted for renegotiation.
  • KETRACO (obligation): Owns and must operate the 612 km Kenyan section and the Suswa converter station, and wheel transit energy to Tanzania.
  • Regional traders and the Eastern Africa Power Pool (gains): Transit wheeling of 136.55 GWh net to Tanzania shows the corridor working end to end.

Implementation

The import PPA is administered like any other Kenya Power purchase contract: EPRA approves it under section 10 of the Energy Act, its cost enters the power purchase bill and is recovered through the base tariff and the monthly fuel and forex pass-throughs, and the volumes are reported in EPRA's biannual statistics. Physical delivery depends on KETRACO's converter station at Suswa and on dispatch coordination under section 138(2)(e) and regulation 19 of the 2026 market regulations, which route regional trade through bilateral agreements or Eastern Africa Power Pool rules. Planning for further import volumes runs through the twenty-year Least Cost Power Development Plan and the five-year Medium Term Power Development Plan prepared alternately by the LCPDP technical committee of the Ministry, sector agencies and EPRA and coordinated by Kenya Power, now given statutory form by the Energy (Integrated National Energy Plan) Regulations 2025. The open questions are the contracted capacity step-ups under the Ethiopian agreement, the commissioning of the Kenya–Tanzania and NELSAP links, and whether import volumes will be traded on the new spot and forward markets rather than only under the bilateral PPA.

Concerns

  • Ethiopian export availability is hydrological and correlates with the rainfall that drives Kenyan hydro
  • A single 500 kV bipole concentrates contingency risk on a system with a thin margin over a 2,439 MW peak
  • Contracted capacity of 200 MW uses only a tenth of the link's 2,000 MW rating, so the asset is under-utilised
  • Import pricing is dollar-denominated and feeds the forex pass-through that consumers carry
  • Cross-border settlement and congestion rules under the Eastern Africa Power Pool are still being built out
  • Cheap imports weaken the case for domestic dispatchable capacity that the system will need at higher peaks

Dates to watch

  • 2027: Commissioning milestones on the Kenya-Tanzania 400 kV and NELSAP interconnectors
  • 2027-H1: EPRA biannual statistics showing whether imports hold above 900 GWh a half year
  • 2028: Next Least Cost Power Development Plan revision and its treatment of contracted import capacity

Sources

Checked against sources on .

Presidential PPA Taskforce · IPP renegotiation and the freeze on new expressions of interest

Kenya · Presidential Taskforce on the Review of Power Purchase Agreements (Ministry of Energy and Petroleum, EPRA) · study · 2021

Where it stands: Advisory findings being worked through ministerial direction, EPRA PPA approvals, auction policy and the 2026 market regulations

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.

The problem

Power purchase costs were 66 per cent of Kenya Power's total revenue in FY2020 and the largest single driver of a retail tariff that compared badly with neighbouring countries and peer economies. The contracts behind those costs had been signed as unsolicited proposals under take-or-pay terms in hard currency, with capacity payments due whether or not the plant was dispatched, and with sovereign-style government support letters. The paradox the taskforce was asked to explain was a system with surplus contracted capacity, suppressed demand, unreliable supply and a financially distressed utility, alongside Kenya's ambition of becoming a competitive middle-income economy by 2030.

What it does

The taskforce's terms of reference were to review every PPA between Kenya Power and IPPs, test compliance with policy, law and regulation, and recommend termination or renegotiation; to review the risk allocation between IPPs and the utility; to replace take-or-pay with a pay-when-taken or merchant structure; to develop an engagement strategy with IPPs and lenders; and to recommend alternative sourcing frameworks including energy auctions. Its near-term recommendations quantified savings against Kenya Power's 2020 procurement costs at KSh 110 to the dollar: pursuing the heavy fuel oil thermal plants for PPA breaches to cut capacity charges by 40 per cent, worth USD 27 to 35 million a year across Athi River Gulf, Thika Melec and Triumph with further scope at Iberafrica and Rabai; improved fuel management across the HFO fleet for a 10 per cent reduction worth USD 12 million; centralised open-tender procurement of heavy fuel oil worth USD 6 million; renegotiating Lake Turkana Wind Power to the KenGen tariff, worth USD 12 million on a plant dispatching an average 150 MW against 300 MW of contracted capacity; renegotiating Kipeto Wind to the same benchmark, worth USD 45 million; and renegotiating OrPower geothermal to the KenGen tariff with refinancing of the mature project, for a near-term subtotal of USD 114 to 122 million a year, with a medium-term switch from HFO to natural gas potentially cutting fuel costs 40 per cent. On procurement it recommended that the Cabinet Secretary for Energy suspend the processing of all expressions of interest and feasibility study reports, including those submitted while the taskforce sat, and that Kenya Power run a pilot renewable energy auction for solar and wind open to all bidders, aligned to the Least Cost Power Development Plan and subject to a technically feasible maximum price. It also required EPRA to conclude the power market study and dispatch guidelines as the basis for appointing a system operator, with KETRACO to suspend work on independent system operator infrastructure in the meantime.

Market effect

The taskforce reset how generation capacity is bought in Kenya and how much a Kenyan PPA is worth. The suspension of unsolicited expressions of interest closed the route through which most of the existing IPP fleet had been procured, and the auction recommendation became the Renewable Energy Auctions Policy, so a developer's entry point is now a competitive process benchmarked to the LCPDP demand forecast rather than a bilateral approach to the utility. For incumbent IPPs the report created explicit, named renegotiation targets and a benchmark, the KenGen tariff, that any subsequent negotiation starts from, which changed the risk premium lenders attach to Kenyan offtake. The structural recommendation, replacing take-or-pay with pay-when-taken, moves volume risk from the utility to the generator and is the reason merchant and bilateral structures matter more in Kenya than in comparable markets. The measurable market effect since is in what EPRA now approves: the PPAs cleared in the half year to December 2025 were a 6 MW hydro plant, a KenGen gas turbine uprate and two commercial-and-industrial solar PPAs of 1.907 MW and 2.076 MW, not multi-hundred-megawatt thermal capacity contracts.

Key numbers

Cost asymmetry
IPPs supplied 25% of Kenya Power's energy for 47% of its purchase cost; KenGen supplied 72% for 48%
Power purchase cost share
66% of Kenya Power's total revenue in FY2020
Near-term savings identified
USD 114 million to USD 122 million a year at KSh 110 to the dollar
Largest single item
Lake Turkana Wind Power renegotiation to the KenGen tariff, USD 69 to 77 million, on average dispatch of 150 MW against 300 MW contracted
Procurement freeze
Cabinet Secretary to suspend processing of all expressions of interest and feasibility study reports

Who gains and who pays

  • Electricity consumers and industry (gains): Targeted savings of USD 114 to 122 million a year in IPP costs feed through the power purchase cost pass-through.
  • Incumbent IPPs (HFO thermal, Lake Turkana, Kipeto, OrPower) (costs): Named for renegotiation to the KenGen tariff, breach investigation and, for HFO, a 40 per cent capacity charge cut.
  • Project lenders and DFIs (costs): Renegotiation of signed, financed PPAs raises the country risk premium on future Kenyan offtake.
  • Kenya Power (gains): Lower power purchase costs, but must take on merit-order reporting and monthly disclosure to its board and EPRA.
  • New renewable developers (mixed): Lose the unsolicited route but gain a competitive auction aligned to the LCPDP with a capped maximum price.

Implementation

The taskforce was an advisory body, so its recommendations bind only through the instruments that followed: ministerial direction to stop processing unsolicited proposals, EPRA's approval powers over every PPA under section 10 of the Energy Act, the Renewable Energy Auctions Policy, and the power market study and dispatch guidelines that underpin the designation of a system operator under section 138. Those last threads were finally tied by the Energy (Electricity Market, Bulk Supply and Open Access) Regulations 2026, which give the system operator market registration, matching, clearing and settlement functions and create the spot and forward markets the taskforce argued should replace take-or-pay contracting. Renegotiation itself proceeds contract by contract between Kenya Power, the IPP and its lenders, with any revised tariff requiring EPRA approval; the report Kenya Power publishes is the redacted version dated 15 October 2021, so individual contract outcomes are not in the public record. The debt-side recommendations, extending the government's moratorium on on-lent loans to Kenya Power and restructuring commercial debt, sit with the National Treasury.

Concerns

  • Only a redacted version of the report is public, so the commercial detail behind each renegotiation target is not verifiable
  • Renegotiating financed PPAs can trigger lender defaults and raises the cost of capital for the next generation of projects
  • The suspension of expressions of interest was recommended, not legislated, and its current scope and duration are unclear
  • Auction volumes have to be aligned to an LCPDP demand forecast that has repeatedly overstated growth
  • Pay-when-taken moves volume risk to generators, which suits merchant hydro and geothermal far better than wind
  • Savings were quantified at KSh 110 to the dollar and are materially different at current exchange rates

Dates to watch

  • 2026-Q4: Whether the Ministry lifts or narrows the suspension on processing unsolicited expressions of interest
  • 2027: First competitive renewable energy auction round aligned to the Least Cost Power Development Plan
  • 2027-H2: Whether the 2026 market regulations displace take-or-pay contracting with spot and forward trading

Sources

Checked against sources on .

Energy Act 2019 · Cap. 314, EPRA, the system operator and the market review clock

Kenya · Parliament of Kenya (assented by the President) · statute · 2019

Where it stands: In force since 28 March 2019 and binding on EPRA, Kenya Power, KETRACO, KenGen and IPPs as Cap. 314

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 problem

Kenya entered 2019 with a 2006 statute written for a single vertically integrated buyer, a regulator (ERC) with a narrow mandate, and no legal architecture for the devolved county governments the 2010 Constitution had created. Generation had been liberalised in practice, with independent power producers supplying a quarter of Kenya Power's energy, but the law gave the regulator no explicit power to designate a system operator, no framework for an electricity market, and no route for a consumer to buy from anyone other than Kenya Power. Feed-in tariffs had been issued administratively, geothermal rights were governed by a separate 1982 Act, and there was no appellate body short of the High Court.

What it does

The Act consolidates the law in 218 sections. Section 9 establishes the Energy and Petroleum Regulatory Authority as a body corporate that is 'independent in the performance of its functions, exercise of its powers and shall not be subject to the direction or control of any person or authority', and section 10 gives it power to license generation, importation, exportation, transmission, distribution, supply and use of electricity, to set, review and approve retail tariffs and tariff structures whether or not an application has been made, and to approve every power purchase agreement and network service contract. Section 25 creates the Energy and Petroleum Tribunal to hear appeals from EPRA decisions. Sections 5 to 8 require the Cabinet Secretary to prepare an integrated national energy plan reviewed every three years, delivered in practice through the twenty-year Least Cost Power Development Plan and the five-year Medium Term Power Development Plan prepared alternately by a technical committee coordinated by Kenya Power. Section 43 establishes the Rural Electrification and Renewable Energy Corporation. Sections 91 and 92 put the renewable energy feed-in tariff system on a statutory footing. Section 131 obliges EPRA, in consultation with the Cabinet Secretary, to review the electricity market regularly to enhance competition, efficiency, reliability and quality, with the first review due within three years of commencement, and requires the Cabinet Secretary to publish regulations for the operation of the market. Section 138 lets EPRA designate a system operator responsible for matching demand with supply, running the National Control Centre, optimal dispatch and scheduling of energy and ancillary services, and coordination with interconnected neighbouring system operators. The Fourth Schedule assigns county energy planning, physical planning for generation sites, wayleaves and the licensing of biomass, biogas, charcoal and retail petroleum.

Market effect

The Act is the source of every commercial permission in the Kenyan power sector, and its timetable explains where the market is now. Kenya's grid-connected installed capacity was 3 193 MW at December 2025 against a peak demand of 2 439.06 MW recorded on 3 December 2025, with geothermal the largest technology at 25.72% of the 3 868.6 MW national total, hydro 23.78%, thermal 17.12%, solar 14.74% and wind 11.89%, plus 630.1 MW of captive plant and 200 MW of import capacity. Because section 10 makes every PPA subject to EPRA approval, the regulator is the gatekeeper for each new project: in the six months to December 2025 it approved PPAs for Muhoroni gas turbine, a 6 MW Ndunda Falls hydro plant and two commercial-and-industrial solar PPAs for Coca-Cola sites of 1.907 MW and 2.076 MW. Because section 131 fixed a review clock, the delay in performing it kept Kenya on bilateral single-buyer contracting until the market regulations were finally gazetted in May 2026. And because section 138 lets EPRA designate the system operator, the unresolved question of whether that role sits with Kenya Power or KETRACO has governed how quickly open access could start.

Key numbers

Enactment
Assented 12 March 2019, gazetted 29 March 2019 (Kenya Gazette Vol. CXXI No. 37), commenced 28 March 2019; now Cap. 314
Market review clock
First review within three years of commencement, and no more than five years between reviews (section 131(1))
Energy planning cycle
Integrated national energy plan reviewed every three years; 20-year LCPDP and 5-year MTPDP prepared alternately
Installed capacity at December 2025
3 868.6 MW total (3 193 MW grid-connected, 630.1 MW captive, 45.5 MW off-grid, 200 MW import capacity); peak demand 2 439.06 MW

Who gains and who pays

  • Independent power producers and C&I developers (gains): A statutory licensing and PPA-approval regime with an appeal route to the Energy and Petroleum Tribunal.
  • Kenya Power (KPLC) (obligation): Retail tariffs, PPAs and network service contracts all require EPRA approval; loses its monopoly under section 131.
  • EPRA (obligation): Must license, tariff-set, approve every PPA and review the electricity market on a statutory clock.
  • County governments (gains): Fourth Schedule functions over energy planning, land and rights of way for generation and transmission.
  • Consumers (mixed): Gain a regulator with an explicit consumer-protection mandate but carry the full cost of approved PPAs.

Implementation

The Act works through statutory instruments made by the Cabinet Secretary on EPRA's recommendation, laid before Parliament and scrutinised by the Committee on Delegated Legislation under the Statutory Instruments Act 2013. The operative electricity regulations have arrived slowly: the Energy (Reliability and Quality of Electrical Energy Supply and Service) Regulations in 2021, a revocation of the legacy instruments in 2023, the Energy (Net-Metering) Regulations 2024 as Legal Notice 104 of 26 July 2024, the Energy (Integrated National Energy Plan) Regulations 2025 as Legal Notice 83 of 7 May 2025, and finally the Energy (Electricity Market, Bulk Supply and Open Access) Regulations 2026 as Legal Notice 79, gazetted and commenced on 8 May 2026, which stand up the market section 131 required. Tariff control periods run in three-year blocks decided by gazette notice after county public hearings; monthly fuel, forex and inflation pass-through notices are gazetted separately. Appeals go to the Energy and Petroleum Tribunal and then the High Court.

Concerns

  • The section 131 first market review ran years past its three-year statutory deadline, delaying open access
  • EPRA's statutory independence coexists with government pressure on tariffs, as the June 2026 withdrawal of Kenya Power's application showed
  • The system operator designated under section 138 still sits inside Kenya Power, the dominant buyer and network owner
  • County functions over land and wayleaves add a second permitting layer for transmission and generation
  • Feed-in tariffs under sections 91 and 92 have been overtaken by auction policy without a clean statutory transition
  • Statutory instruments can be annulled by Parliament's Committee on Delegated Legislation after gazettement

Dates to watch

  • 2026-Q4: System operator market operational procedures required under the 2026 market regulations
  • 2027: Next review cycle of the integrated national energy plan under sections 5 to 8
  • 2031: Outer limit for the next electricity market review under the five-year cap in section 131(1)

Sources

Checked against sources on .