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Ethiopia: 5 energy policy briefs

The energy policies moving Ethiopia’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.

Power export expansion · Kenya to 400 MW from December 2026 and a 5,000 GWh target by 2030

Ethiopia · Ethiopian Electric Power · plan · 2026

Where it stands: Export expansion announced 16 September 2026; joint technical committee running trial operations ahead of the December step to 400 MW for Kenya

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.

The problem

Ethiopia built generation faster than it built demand. Ethiopian Electric Power operates 24 stations with an interconnected-system capacity of 9,749.9 MW, of which 94.49 percent is hydro, 5.16 percent wind, 0.25 percent biomass and 0.07 percent geothermal, and the Grand Ethiopian Renaissance Dam alone accounts for 5,150 MW of that. Domestic demand cannot absorb it: about 55 percent of the population has no connection, per capita consumption is below 100 kWh a year, and the retail tariff has only just started moving toward cost. Exports are therefore the fastest route to hard currency, and the utility says power sales to neighbouring countries already generate roughly 300 million dollars a year. But a system that is more than 95 percent hydro is exposed to hydrology: a bad rainy season or an El Nino year hits exports and domestic supply at the same time, and Kenya's grid is itself interconnected with its neighbours, so an Ethiopian disturbance propagates across the Eastern Africa Power Pool.

What it does

Ethiopian Electric Power stated on 16 September 2026 that it is finalising preparations to double electricity exports to Kenya from the current 200 MW to 400 MW starting in December, following completion of technical and preparatory work between the two countries, with a joint technical committee overseeing trial operations and system stability before the additional power is dispatched; the utility says particular attention is being given to system security because Kenya's grid is interconnected with other neighbours. It is separately supplying 100 MW to Tanzania on a pilot basis, with regular exports to follow completion of infrastructure upgrades linking the Kenyan and Tanzanian systems. The National Load Dispatch Centre reported at an Eastern Africa Power Pool meeting that exports have grown 31 percent over the past decade and now account for between 6.5 and 10 percent of total generation, and that Ethiopia is pursuing a roadmap to reach 5,000 GWh of annual exports by 2030, with new cross-border links planned to South Sudan, Somalia and Somaliland and additional corridors to Djibouti and Sudan under development. The transmission build behind this is visible in procurement: a contract award for the 230 kV Semera to Galafi line on the Djibouti corridor and an agreement signed on 10 September 2026 for the Assosa 2 400 kV substation. Generation continues to be added: the 100 MW Assela wind farm and the first 80 MW of Ayisha II entered service in 2025, and the 201-metre Koysha hydropower dam has passed 77 percent completion with 6.27 million of 7.72 million cubic metres of roller-compacted concrete placed, first turbine testing expected in October or November 2028 and full completion targeted for May or June 2029, now financed from the utility's own resources after foreign-currency shortages had slowed it.

Market effect

Doubling the Kenyan link to 400 MW is the single largest change in East African cross-border flows this decade and it lands into a Kenyan system that is short of firm capacity in the evening peak. Ethiopian hydro is the cheapest dispatchable energy in the region, so incremental flow displaces Kenyan thermal and, at the margin, sets the price in the Eastern Africa Power Pool's early trading. For Ethiopia, exports at 6.5 to 10 percent of generation against total output above 35,000 GWh imply roughly 2,300 to 3,500 GWh sold across borders today, so the 5,000 GWh target for 2030 is a 40 to 115 percent increase depending on the base year, and it is a transmission problem rather than a generation problem given the surplus behind the dam. The hard-currency effect is what ties this brief to the rest of Ethiopian energy policy: about 300 million dollars a year of export revenue now converts at a market exchange rate rather than an administered one, which is why the utility could fund Koysha internally. The risks run the other way through the same wires. A system that is 94.49 percent hydro with exports contracted firm gives Ethiopia a genuine dispatch conflict in a dry year between domestic load, industrial parks and export obligations, and the utility itself says diversification into solar, wind, geothermal and gas, with preparatory work on nuclear, is needed to make the export commitment credible.

Key numbers

Kenya interconnector
200 MW today, doubling to 400 MW from December 2026
Tanzania
100 MW supplied on a pilot basis
Export target
5,000 GWh of annual exports by 2030; exports currently 6.5 to 10 percent of generation and up 31 percent over a decade
Generation base
9,749.9 MW of interconnected capacity, 94.49 percent hydro; GERD 5,150 MW supplying about 52 percent of more than 35,000 GWh generated in the fiscal year
Koysha hydropower
201 m dam, over 77 percent complete; first turbine testing October or November 2028, completion targeted May or June 2029

Who gains and who pays

  • Ethiopian Electric Power (gains): Hard-currency export revenue of about 300 million dollars a year, rising toward a 5,000 GWh target.
  • Kenyan and Tanzanian utilities and consumers (gains): 400 MW from Kenya's December step plus a 100 MW Tanzanian pilot displace costlier thermal generation.
  • Regional thermal generators (costs): Cheap Ethiopian hydro sets the marginal price in Eastern Africa Power Pool trading.
  • Ethiopian domestic consumers and industrial parks (costs): Firm export commitments compete for the same hydro in a dry year.
  • Transmission contractors (gains): 230 kV Semera to Galafi, the Assosa 2 400 kV substation and new corridors to South Sudan, Somalia and Somaliland.

Implementation

The Kenyan step depends on the joint technical committee completing trial operations and satisfying itself on the stability of the interconnected systems before additional power is dispatched, so December 2026 is a target rather than a fixed date, and regular Tanzanian exports wait on infrastructure upgrades linking the Kenyan and Tanzanian grids. The Djibouti and Sudan corridors and the planned South Sudan, Somalia and Somaliland links each require their own transmission build, of which the 230 kV Semera to Galafi line and the Assosa 2 400 kV substation are the contracted pieces. Ethiopian Electric Power's strategy sets the objective explicitly as becoming East Africa's most competitive power trader and most reliable transmission service provider, and it frames diversification of the generation mix, including solar, wind, geothermal, natural gas and preparatory work on nuclear, as the condition for making the export commitment resilient to climate variability. The Eastern Africa Power Pool is the forum in which the trading arrangements, El Nino preparedness and system-security coordination are being worked out.

Concerns

  • More than 95 percent hydro dependence leaves exports and domestic supply exposed to the same drought
  • Firm export commitments compete with unserved domestic demand and industrial park load
  • Kenyan grid interconnection means an Ethiopian disturbance propagates region-wide
  • December 2026 date depends on joint trial operations that have not concluded
  • New corridors to South Sudan, Somalia and Somaliland cross areas with security and permitting risk

Dates to watch

  • 2026-12: Kenyan exports scheduled to rise from 200 MW to 400 MW
  • 2028-10: First Koysha turbine expected to begin operational testing
  • 2030: Target of 5,000 GWh of annual power exports

Sources

Checked against sources on .

Foreign exchange liberalisation · Directive FXD/01/2024 and the 2026 relaxations

Ethiopia · National Bank of Ethiopia · directive · 2024

Where it stands: In force since 29 July 2024, as amended by FXD/3/2025, FXD/04/2026 and FXD/05/2026 and the February 2026 relaxation notice

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.

The problem

Every part of the Ethiopian power sector priced in dollars and earned in birr at an administered rate that bore no relation to the parallel market. Independent power producers with dollar-denominated tariffs could not be sure of converting or repatriating their receipts; contractors on transmission and generation projects could not import conductors, transformers or turbines without queuing for allocations; and Ethiopian Electric Power's own Koysha hydropower project, as its management has said, was slowed by foreign-currency shortages before the utility moved to self-funding. Meanwhile the utility's roughly 300 million dollars a year of export earnings from Sudan, Kenya, Djibouti and Tanzania were surrendered at an overvalued official rate, which understated the value of exports in birr and distorted every investment decision between serving domestic load and selling across the border. Without a market exchange rate, neither the tariff reform nor the private generation programme could produce a bankable transaction.

What it does

Directive FXD/01/2024 took effect on 29 July 2024 and repealed and replaced all foreign exchange directives and circulars previously issued by the National Bank of Ethiopia. Article 5 allows banks and authorised foreign exchange dealers to buy and sell currency from and to their clients and among themselves at freely negotiated rates; the National Bank compiles the rates actually used and publishes an Indicative Daily Exchange Rate that is the accounting rate for the day and a reference price rather than a mandatory transaction price. Article 6 keeps a repatriation obligation, requiring export proceeds to be brought home within three months, but replaces surrender to the central bank with a split: exporters convert 50 percent of proceeds to birr immediately at a negotiated rate and retain 50 percent in a foreign exchange retention account usable for the same legal entity's imports, services, dividends and external debt service, with retained balances to be sold to the transacting bank within 30 days as a temporary measure to build an interbank market. Foreign direct investment, grants, external loans and portfolio inflows are exempt from the conversion requirement. The National Bank then relaxed the regime further: a public notice of 11 February 2026, accompanying revised Directive FXD/04/2026, allows any service exporter to hold 100 percent of export proceeds indefinitely, lets banks handle approval of external loans and suppliers' credit without central bank sign-off, permits investors to remit net profit and dividends on documentation checked by their bank rather than by the National Bank, allows forward exchange transactions without central bank approval, permits foreign direct investment companies to open foreign currency accounts at any authorised bank without an approval letter, lets banks offer private external loan guarantees up to 10 percent of their capital, and opens outbound investment case by case. Directive FXD/05/2026 amended the regime again in May 2026.

Market effect

The National Bank's own one-year assessment, published on 29 July 2025, quantifies what changed: total foreign exchange inflows grew 33 percent to a record 32 billion dollars, made up of 8.3 billion in goods exports, 8.5 billion in service exports, 7.1 billion in remittances, 1.9 billion in official grants, 2.7 billion in new loans excluding the International Monetary Fund, 3.9 billion in foreign direct investment and 0.2 billion in other private inflows, funding close to 19 billion dollars of goods imports. For a project sponsor the operative numbers are that banks' average daily foreign exchange sales to businesses doubled from 11 million to 25 million dollars, monthly sales rose from 258 million to 500 million dollars, and new private external borrowing and suppliers' credit more than doubled from 204 million to 445 million dollars. That is the difference between a transformer order that ships and one that sits at the port. Inflation fell to 13.9 percent by June 2025 from 20 percent a year earlier, which matters because tariff increases are politically priced against the headline rate. The February 2026 relaxations matter most to independent power producers: dividend repatriation cleared by the commercial bank rather than the central bank, and external loan approval delegated to banks, remove two of the three sovereign discretion points that made Ethiopian power purchase agreements hard to finance, leaving offtaker credit as the remaining one. The counterpart risk is that a market rate transmits currency weakness straight into the cost of imported equipment and into the birr cost of dollar-linked tariffs, which is exactly the pressure the four-year electricity tariff path is absorbing.

Key numbers

Effective date
29 July 2024; repeals all previous foreign exchange directives and circulars
Export proceeds split
50 percent converted immediately, 50 percent retained and sold within 30 days; service exporters allowed 100 percent retention indefinitely from February 2026
Foreign exchange inflows, first year
Up 33 percent to a record 32 billion dollars, funding close to 19 billion dollars of goods imports
Bank sales to business
25 million dollars a day, up from 11 million; 500 million a month, up from 258 million
Private external borrowing
445 million dollars in the first year, against 204 million the year before
Amending directives
FXD/3/2025, FXD/04/2026 (February 2026) and FXD/05/2026 (May 2026)

Who gains and who pays

  • Independent power producers and their lenders (gains): Dividend repatriation and external loan approval moved from the central bank to commercial banks.
  • Ethiopian Electric Power (gains): Export earnings of about 300 million dollars a year convert at a market rate; Koysha now self-funded.
  • Equipment importers and EPC contractors (gains): Bank foreign exchange sales to business doubled to 25 million dollars a day.
  • Electricity consumers (costs): A market exchange rate feeds imported fuel and equipment costs into the tariff path.
  • Exporters of goods (obligation): Must repatriate within three months, convert 50 percent immediately and sell retained balances within 30 days.

Implementation

The directive is administered by the National Bank through a Foreign Exchange Market Operation Guideline and a Foreign Exchange Market Code of Conduct binding banks and authorised dealers, with banks reporting their daily transaction rates and the National Bank publishing the indicative rate at the start of the following business day. The retention share and the 30-day utilisation window are expressly variable and have already been changed for service exporters, so a project modelling convertibility should treat both as policy variables rather than fixed terms. Independent foreign exchange bureaus have been licensed and their cash holding limit raised from 10 to 25 percent of capital, and the National Bank has released security deposits to support their working capital. The reform sits inside a wider macroeconomic package that also created a policy rate, a monetary policy committee, open market operations and an electronic interbank money market, and that ended direct central bank lending to government for the first time in twelve years.

Concerns

  • Retention shares and utilisation windows are explicitly variable and have already been changed twice
  • A market rate transmits depreciation directly into imported fuel and equipment costs
  • Convertibility is improved but offtaker credit remains the binding constraint on power purchase agreements
  • Frequent amendment (FXD/3/2025, FXD/04/2026, FXD/05/2026) makes the operative text hard to pin down
  • Goods exporters still face a mandatory 50 percent conversion and a three-month repatriation deadline

Dates to watch

  • 2026-12: Further National Bank measures to deepen the interbank foreign exchange market and admit foreign banks
  • 2027: Review of the remaining conversion and repatriation requirements on goods exporters

Sources

Checked against sources on .

Phased electricity tariff reform · four-year path to cost reflectivity from September 2024

Ethiopia · Council of Ministers on the recommendation of the Petroleum and Energy Authority; applied by Ethiopian Electric Utility · decision · 2024

Where it stands: Phased schedule approved and being applied by Ethiopian Electric Utility since September 2024, with further steps to 2028

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.

The problem

Ethiopian retail electricity prices were among the lowest in the world and had been effectively frozen for years, at a level that recovered a fraction of the cost of supply even before the birr's devaluation. The Ethiopian Investment Commission reports per capita consumption below 100 kWh a year against an African average near 500 kWh, and about 55 percent of a population of roughly 116 million with no electricity access at all, so the subsidy was both fiscally expensive and badly targeted: it flowed mainly to the connected urban minority. Under-recovery starved the Ethiopian Electric Utility of the cash to maintain distribution networks and to pay Ethiopian Electric Power for bulk supply, which in turn left Ethiopian Electric Power funding generation and transmission from its own balance sheet and from concessional loans. The July 2024 exchange-rate liberalisation made the gap unsustainable overnight: fuel, transformers, conductors, meters and spares all reprice in birr terms at a market rate while the tariff is a cabinet decision, and the International Monetary Fund programme that accompanied the float carried an explicit commitment to cost-reflective energy pricing.

What it does

Tariff setting follows the route fixed by the Energy Proclamation 810/2013 and restated in the Petroleum and Energy Authority's mandate: a licensee, in practice the Ethiopian Electric Utility, submits a national-grid tariff proposal, the authority reviews it against its published electricity tariff setting methodology and cost of service study manual, and it submits a recommendation to the Council of Ministers, which approves. Once approved the authority regulates implementation and the utility applies the schedule. Off-national-grid and mini-grid tariffs follow a different and faster path, determined under authority directives, including a mini-grid directive and an off-grid tariff application and information submission procedure, so isolated systems can price closer to cost without a cabinet decision. The reform adopted in 2024 differs from earlier one-off adjustments in being a pre-announced multi-year path rather than a single step, phased over four years from September 2024 with the stated objective of reaching cost-reflective retail prices by 2028, and it is deliberately sequenced with the macroeconomic package: the National Bank of Ethiopia's Foreign Exchange Directive FXD/01/2024 took effect on 29 July 2024, and the tariff schedule began in the following quarter. The authority retains its Directive 001/2012 quality of service standards for grid supply as the counterpart obligation, and it can convene professional panels to mediate or arbitrate disputes between a licensee and its customers over tariff or quality of service.

Market effect

The phasing matters more than the level. A pre-announced four-year path gives Ethiopian Electric Power and Ethiopian Electric Utility a revenue trajectory that lenders can model, which is what a state utility needs in order to borrow for distribution investment without a sovereign guarantee, and it lets industrial consumers plan rather than absorb a single shock. The financial evidence that the reform is working shows up upstream: Ethiopian Electric Power reported revenue of 124 billion birr and net profit of 39.5 billion birr in the fiscal year to July 2026, on generation of more than 35,000 GWh nationwide, and is now self-funding the Koysha hydropower project after foreign-currency shortages had slowed it. Higher domestic tariffs also change the export calculus: Ethiopian Electric Power earns roughly 300 million dollars a year selling to Sudan, Kenya, Djibouti and Tanzania, and as the domestic tariff rises toward cost, exports stop being an unambiguous premium market and become one option among several for the same kilowatt-hour. For large industrial loads, including the industrial parks that the Ethiopian Investment Commission says need more than 2,500 MW between them, a rising tariff is the first real incentive to invest in efficiency or in behind-the-meter generation, neither of which had any payback at the frozen price. The risk sits on affordability and on political tolerance: with demand growing far faster than supply and access still around half the population, each step invites pressure to exempt more categories and to slow the path.

Key numbers

Reform shape
Phased increases over four years from September 2024 toward cost reflectivity by 2028
Ethiopian Electric Power fiscal year result
124 billion birr revenue and 39.5 billion birr net profit; more than 35,000 GWh generated nationwide
Consumption and access baseline
Under 100 kWh per capita a year against an African average near 500 kWh; about 55 percent of the population without access
Export revenue at stake
About 300 million dollars a year from sales to Sudan, Kenya, Djibouti and Tanzania
Sequencing
Foreign Exchange Directive FXD/01/2024 effective 29 July 2024; tariff path starting the following quarter

Who gains and who pays

  • Ethiopian Electric Utility (gains): Revenue trajectory that can fund distribution maintenance and payments to its bulk supplier.
  • Ethiopian Electric Power (gains): A solvent domestic offtaker; reported 124 billion birr revenue and 39.5 billion birr net profit in the fiscal year to July 2026.
  • Residential and small commercial consumers (costs): Phased increases on top of inflation that was 13.9 percent in June 2025.
  • Industrial parks and large loads (costs): First real price signal for efficiency and behind-the-meter generation.
  • Independent power producers (gains): A cost-reflective retail tariff underpins offtaker creditworthiness for long-dated power purchase agreements.

Implementation

Each step is applied by the Ethiopian Electric Utility on the schedule approved by the Council of Ministers, and the Petroleum and Energy Authority supervises implementation and holds the quality of service standards that are meant to travel with the price. The authority lists a Revised Electricity Tariff, an Electricity Tariff Setting Methodology, an Ethiopia Cost of Service Study Manual and an off-grid tariff procedure among its published documents, and none of them can be opened. Checked through the authority's own document feed on 19 September 2026, its library holds 74 documents across eight pages and every single link, the four tariff documents included, downloads the same file, the Energy Proclamation 810/2013. The other place a reader would look is the utility, and Ethiopian Electric Utility has served an expired TLS certificate since 18 September 2026, so its site cannot be opened either. The practical consequence is that Ethiopia publishes a tariff route but not a tariff: the schedule can be obtained only by asking the authority or the utility directly, and anyone pricing Ethiopian power risk should confirm which steps have actually been applied rather than which were announced, since Ethiopian tariff reforms have historically been announced in full and then implemented partially.

Concerns

  • The approved schedule and per-step tariff levels are not published in usable form by the regulator
  • Affordability pressure with about half the population unconnected invites exemptions and slippage
  • Historic pattern of announcing multi-year paths and implementing only the early steps
  • Cost reflectivity measured against a cost base that moves with the exchange rate
  • Quality of service standards not visibly enforced alongside the increases

Dates to watch

  • 2027: Later steps in the phased schedule and the regulator's review of cost of service
  • 2028: Stated end point of the path to cost-reflective retail tariffs

Sources

Checked against sources on .

Energy regulation restructured · Petroleum and Energy Authority under Proclamation 1263/2021

Ethiopia · House of Peoples' Representatives (Proclamation 1263/2021); Petroleum and Energy Authority · statute · 2021

Where it stands: Authority operating since 2021 under Proclamation 1263/2021, applying Proclamation 810/2013, Energy Regulation 447/2019 and the grid codes

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.

The problem

Ethiopia's electricity law, the Energy Proclamation No. 810/2013 published in the Federal Negarit Gazette on 27 January 2014, created a regulator with real powers on paper: licensing of anyone generating, distributing or selling electricity, competency certification, administrative penalties, and a tariff role. But the regulator was small, its board met rarely, and the sector it was meant to police consisted of two state monopolies, Ethiopian Electric Power for generation and transmission and the Ethiopian Electric Utility for distribution and retail, both answering to the same ministry. Tariffs were frozen for years at a level far below cost, the utilities accumulated losses and arrears, and independent power producers had no confidence that a licence, a grid code or a tariff decision would be applied to them on the same terms as to the incumbents. The government needed a regulator with a clear statutory home, a published rulebook and a defined route for tariff approval before private capital would sign twenty-year power purchase agreements.

What it does

The Authority is created by Article 51 of the Definition of Powers and Duties of the Executive Organs Proclamation No. 1263/2021, published in the Federal Negarit Gazette, 28th Year No. 4, Addis Ababa, 25 January 2022, at page 13751. Article 51(1) establishes the Petroleum and Energy Authority as an autonomous federal government body with its own legal personality, and Article 51(2) provides that its powers, duties and organisation shall be determined by a Council of Ministers Regulation rather than by the proclamation itself. Article 83(5) places it among the six executive organs accountable to the Ministry of Trade and Regional Integration, alongside the standards, metrology, conformity assessment and accreditation bodies and the Ethiopian Commodity Exchange. It merges the electricity regulator created by Regulation 308/2013 with the petroleum regulator. Its published mandate runs to twenty-six heads of power. It formulates the legal framework for the sector and submits it for approval; issues, renews, suspends, replaces and revokes professional certificates and business licences for anyone in the energy sector and imposes administrative penalties; issues, renews and revokes competency certificates across petroleum and energy; reviews the national-grid tariff submitted to it by a licensee and submits its recommendation to the Council of Ministers for approval, then regulates implementation, while issuing and enforcing directives for off-grid tariff determination; prepares petroleum wholesale and retail price and margin directives for the ministry; runs the national energy efficiency and conservation strategy; and issues the energy audit code, energy efficiency standards and labelling codes, the national grid code, the customer service code, the technical inspection code, the service quality standard code and the building electrical installation code. It sets the volume of the petroleum reserve with other bodies, grants permission for direct bulk fuel purchases for self-use, collects service fees at rates fixed by Council of Ministers regulation, and may convene professional panels to mediate or arbitrate disputes between licensees and customers over supply conditions, tariff or quality of service. The operating rulebook it publishes includes the Energy Regulation No. 447/2019, the Ethiopian National Transmission Grid Code and Distribution Grid Code, an electricity tariff setting methodology, a cost of service study manual, a mini-grid directive, an off-grid tariff application procedure, Directive 001/2012 on quality of service standards for grid supply and a uniform system of accounts directive. Structurally the authority is accountable to the Ministry of Trade and Regional Integration rather than to the energy ministry, and its director general reports into that ministry's annual sector council.

Market effect

For a developer the decisive feature is that the regulator recommends but the Council of Ministers decides the national-grid tariff, so electricity pricing in Ethiopia is a cabinet decision taken against fiscal and inflation constraints rather than a regulatory determination against a cost-of-service test. That is the single largest revenue risk in an Ethiopian power purchase agreement, because the offtaker's ability to pay depends on a political price. The licensing regime is more predictable: Proclamation 810/2013 requires anyone generating, distributing or selling electricity to hold a licence and to take the form of a joint stock company, obliges the authority to decide a permit or licence application within sixty days of a complete filing, allows exemption for generators supplying only their own use, and requires permit and licence decisions to be published in the Government Bulletin at the applicant's expense. The board approves model power purchase and network service agreements, which is what gives an independent power producer a template rather than a bespoke negotiation. The separation of the regulator from the energy ministry reduces the appearance of the ministry regulating its own utilities, but placing it under the trade ministry, whose day-to-day energy work is fuel-station enforcement and dispenser calibration, means electricity regulation competes for attention with the downstream petroleum agenda.

Key numbers

Founding instruments
Energy Proclamation 810/2013 (Federal Negarit Gazette, 27 January 2014); Energy Regulation 447/2019; Regulation 308/2013 establishing the predecessor Ethiopian Energy Authority
Authority created by
Article 51 of Proclamation 1263/2021 (Federal Negarit Gazette, 28th Year No. 4, 25 January 2022, page 13751); accountable to the Ministry of Trade and Regional Integration under Article 83(5)
Powers still to be conferred
Article 51(2) leaves the authority's powers, duties and organisation to a Council of Ministers Regulation; the authority lists that regulation, and a draft of it, among documents it does not serve
Licence decision deadline
60 days from a complete application under Article 14 of Proclamation 810/2013
Tariff route
Licensee proposal, authority review, Council of Ministers approval for national-grid tariffs; authority directives for off-grid

Who gains and who pays

  • Independent power producers and their lenders (mixed): A published licensing route and model agreements, but tariffs still decided by the Council of Ministers.
  • Ethiopian Electric Power and Ethiopian Electric Utility (obligation): Licensed entities bound by the grid codes, service quality standards and the uniform system of accounts.
  • Mini-grid and off-grid operators (gains): Off-grid tariffs determined under authority directives rather than the national-grid political process.
  • Large industrial and commercial consumers (costs): Bound by licensee tariffs with recourse only to the authority's mediation and arbitration panels.
  • Ministry of Trade and Regional Integration (obligation): Carries the regulator and its combined petroleum and electricity workload.

Implementation

Directives and codes are published on the authority's own website rather than in the Negarit Gazeta, so effective dates come from each instrument. The authority has been visibly rebuilding since 2026: it inaugurated a digital operating system and online service platform and new headquarters in July 2026, and its enforcement record in the fiscal year to July 2026 was concentrated on the petroleum side, with action against more than 350 stations for illegal fuel trading and temporary suspensions for tampered dispensers. On the electricity side it conducts on-site inspection of power infrastructure, including the Gada Special Economic Zone transmission project, complementary works at the Adama II wind plant and electric-vehicle charging facilities. The instruments most worth checking before a transaction are the Ethiopian National Transmission Grid Code, the electricity tariff setting methodology and the cost of service study manual, all listed in the authority's downloads. They cannot, however, be read there. The authority's document library catalogues 74 documents across eight pages, and on 19 September 2026 every one of them, checked through the site's own feed, pointed at a single file, the Energy Proclamation 810/2013 PDF. That is not an occasional broken link but the whole library: the Revised Electricity Tariff, the tariff setting methodology, the grid codes, the mini-grid directive and the authority's own establishment regulation all download the same proclamation. The Council of Ministers Regulation that Article 51(2) requires is itself among the casualties, listed twice, once as a Petroleum and Energy Authority Establishment Regulation and Explanation and once as a draft regulation defining the authority's structure, training and duties, with neither retrievable, so the twenty-six heads of power the authority publishes on its mandate page cannot be checked against the instrument that is supposed to confer them.

Concerns

  • National-grid tariffs are approved by the Council of Ministers, not determined by the regulator against a cost test
  • The regulator sits under the trade ministry, where downstream petroleum enforcement dominates its workload
  • Directives are published by website and circular rather than gazetted, so effective dates are hard to fix
  • All 74 documents in the authority's library resolve to a single file, so no code, directive or tariff can be read from the regulator
  • No published record of contested tariff or licence proceedings against the incumbent utilities

Dates to watch

  • 2027: Next Council of Ministers decision on national-grid tariffs on the authority's recommendation
  • 2026-12: Completion of the authority's digital licensing and service platform rollout

Sources

Checked against sources on .

Private generation programme · geothermal PPAs of March 2020 and the 19,900 MW 2030 target

Ethiopia · Ministry of Finance PPP Directorate and PPP Board; Ethiopian Electric Power as offtaker; Ethiopian Investment Commission · plan · 2020

Where it stands: First independent power producer and public-private partnership agreements signed 2019-2020; projects in development against the 19,900 MW 2030 target

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.

The problem

Ethiopia's 10-Year Development Plan targets a rise in installed generation capacity from about 4,500 MW to 19,900 MW by 2030, and the Ethiopian Investment Commission estimates national potential at 60,000 MW, including 45 GW of hydropower and very large wind and solar resources, with average irradiance around 5.2 kWh per square metre a day. That build cannot be financed from the public balance sheet: Ethiopian Electric Power was already carrying the Grand Ethiopian Renaissance Dam, Koysha and a national transmission programme, and foreign-currency shortages were slowing projects it had already started. Demand was meanwhile rising fast, with more than twenty industrial parks requiring over 2,500 MW between them and an electric-powered national railway covering 4,744 km. The government therefore needed a legal route by which a private developer could build, own and operate a plant and sell to Ethiopian Electric Power under a bankable long-term contract, in a country with no history of honouring such contracts and no convertible currency.

What it does

The framework runs through the Public Private Partnership Proclamation No. 1076/2018, published in the Federal Negarit Gazeta, 24th Year No. 28, Addis Ababa, 22 February 2018, at page 10235, whose recitals put its purpose as promoting privately financed infrastructure by improving transparency, fairness and long-term sustainability in the award of contracts by public entities. The Ministry of Finance chairs a PPP Board that approves the pipeline, approves each project to tender and to award, approves project structures and feasibility studies, sets minimum standards and requires value for money to be demonstrated; its other members are the National Bank of Ethiopia, the ministries responsible for water and electricity, transport and peace, the public enterprises holding body, the national planning body and two members representing the private sector. A Public-Private Partnership Directorate General inside the ministry acts as the Board's secretariat and runs project development and monitoring, framework and contract support, and capacity building. Ethiopian Electric Power signs the power purchase agreements and the government signs the implementation agreements that cover the sovereign undertakings a lender needs. The Ethiopian Investment Commission, which provides one-stop services to investors through pre-implementation, establishment and operation, records the resulting transactions: the Metahara Solar independent power producer project signed in 2019, developed by Enel Power of Italy for 100 MW; two solar power projects also signed in 2019 with ACWA Power of Saudi Arabia for a combined 250 MW and a value of about 300 million dollars; and, in March 2020, power purchase agreements and implementation agreements with the Corbetti and Tulu Moye geothermal projects representing approximately 1.2 billion dollars of total investment, which the commission describes as paving the way for further geothermal projects and creating openings for other independent power producer developers. Alongside this, Ethiopian Electric Power's own mandate under Council of Ministers Regulation 381/2016 as amended keeps it responsible for building plants, transmission and substations and for the wholesale of electricity, so the private programme sits beside rather than in place of state construction. The Petroleum and Energy Authority licenses any private generator under Proclamation 810/2013, which requires licensees to take the form of a joint stock company and obliges the authority to decide within sixty days of a complete application, and the authority's board approves model power purchase and network service agreements that set the template.

Market effect

The first cohort establishes the price and the risk allocation everything after it is measured against. Solar at Metahara and the ACWA projects put utility-scale photovoltaic tariffs into an Ethiopian power purchase agreement for the first time, and the geothermal agreements did something harder: they placed resource risk in the Rift Valley with private developers in exchange for a long-dated dollar-denominated offtake, on a combined investment of about 1.2 billion dollars for two projects. The binding constraint on all of them has never been resource or construction cost but convertibility and offtaker credit, which is why the July 2024 exchange-rate liberalisation and the tariff reform matter more to this pipeline than any procurement round: a developer paid in birr at an administered rate against a utility that could not recover its costs had no bankable transaction. With Ethiopian Electric Power reporting 124 billion birr of revenue and 39.5 billion birr of net profit in the fiscal year to July 2026 and funding Koysha from its own resources, the offtaker is a materially better credit than it was when these agreements were signed. The gap between the 19,900 MW target for 2030 and the 9,749.9 MW of interconnected capacity operating today is roughly 10 GW in four years, which no state programme can deliver, so the practical test is whether the geothermal and solar cohort reaches commercial operation and whether a repeatable tender follows rather than one-off negotiated deals.

Key numbers

2030 capacity target
19,900 MW planned installed capacity, up from about 4,500 MW in the 10-Year Development Plan
Geothermal agreements
Corbetti and Tulu Moye power purchase and implementation agreements signed March 2020, about 1.2 billion dollars of investment
Solar independent power producers
Metahara 100 MW (Enel, 2019) and 250 MW across two ACWA Power projects worth about 300 million dollars (2019)
Resource base
About 60,000 MW of total potential, including 45 GW of hydropower and average irradiance of 5.2 kWh per square metre a day
Current interconnected capacity
9,749.9 MW, 94.49 percent hydro; wind 504 MW, biomass 25 MW, geothermal 7.3 MW and no solar in Ethiopian Electric Power's capacity table
PPP framework
Proclamation 1076/2018 (Federal Negarit Gazeta, 24th Year No. 28, 22 February 2018, page 10235); Ministry of Finance chairs the PPP Board, which approves pipeline, tender and award
Published pipeline
23 projects approved as at March 2021: 1,050 MW solar, 1,848 MW hydro, 710 MW wind, plus toll roads, housing and a petroleum depot; still the ministry's current published list

Who gains and who pays

  • Independent power producers (Enel, ACWA Power, Corbetti and Tulu Moye geothermal) (gains): Long-dated offtake with government implementation agreements on about 1.5 billion dollars of committed projects.
  • Ethiopian Electric Power (obligation): Offtaker under the power purchase agreements and the party that must connect and evacuate the output.
  • Ministry of Finance PPP directorate and PPP Board (obligation): Approves projects and carries the contingent liabilities in the implementation agreements.
  • Industrial parks and the national railway (gains): New capacity against demand of more than 2,500 MW from parks alone.
  • Ethiopian taxpayers (costs): Sovereign undertakings and dollar-denominated tariffs against birr revenue.

Implementation

Projects move through the PPP Board and the Ministry of Finance directorate, then to a power purchase agreement with Ethiopian Electric Power and an implementation agreement with government, and finally to a generation licence from the Petroleum and Energy Authority under Proclamation 810/2013. The Ethiopian Investment Commission handles investment permits, land and one-stop services and publishes the investment legal framework, including Investment Proclamation 1180/2020 and Investment Regulation 474/2020, which the energy regulator also lists among its reference instruments. The commission says new generation projects are being developed through public-private partnerships and independent power producers while Ethiopian Electric Power focuses on managing its existing hydro and wind fleet, substations and transmission lines. The measurable milestones are commercial operation at Corbetti and Tulu Moye, the Metahara and ACWA solar plants reaching the grid, and whether a standardised competitive tender replaces the negotiated route. On the first two, Ethiopian Electric Power's own generation page answers plainly: of the interconnected fleet it manages, geothermal accounts for 7.3 MW, 0.075 percent of installed capacity, and solar does not appear at all, the balance being 9,213 MW of hydro at 94.49 percent, 504 MW of wind at 5.16 percent and 25 MW of biomass from the Reppie waste plant in service since 2019. Six years after the first solar agreements and more than six after the geothermal ones, no megawatt from that cohort is visible in the operator's own capacity table. On the third, the pipeline the Ministry of Finance publishes is still the 2020/21 booklet issued in March 2021, in which the Board had approved twenty-three projects, eight solar photovoltaic, six hydro, five wind, three toll roads, one affordable housing and one petroleum storage depot, totalling 1,050 MW of solar, 1,848 MW of hydro and 710 MW of wind, with Gad and Dicheto solar awarded to ACWA Power and the remaining six solar projects at request-for-proposal stage. That document remains the ministry's current published pipeline, so there is no public evidence of a refreshed tender programme since.

Concerns

  • Dollar-denominated tariffs against an offtaker whose revenue is in birr
  • Geothermal resource risk in the Rift Valley carried by developers with long lead times
  • Negotiated rather than competitively tendered awards leave no benchmark price
  • Roughly 10 GW of new capacity needed by 2030 against a delivered private pipeline under 1 GW
  • Contingent liabilities under implementation agreements are not published
  • The operator's capacity table still shows 7.3 MW of geothermal and no solar, so the 2019-2020 cohort has yet to deliver
  • The ministry's published PPP pipeline has not been updated since March 2021

Dates to watch

  • 2027: Expected commercial operation milestones for the first geothermal and solar independent power producers
  • 2030: Target of 19,900 MW of installed generation capacity

Sources

Checked against sources on .