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Saudi Arabia: 5 energy policy briefs

The energy policies moving Saudi Arabia’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.

Saudi-Egypt HVDC interconnection · 3,000 MW between two non-coincident peaks

Saudi Arabia · Ministry of Energy, National Grid SA and the Egyptian Electricity Transmission Company · decision · 2021

Where it stands: EPC contracts signed October 2021; converter stations, overhead lines and the Gulf of Aqaba crossing under construction with staged energisation planned

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

The problem

Saudi Arabia and Egypt both build generation for a summer air-conditioning peak, but the peaks are not coincident: Egypt's system peaks earlier in the evening and its winter profile differs from the Saudi one, so each country carries reserve capacity that the other does not need at the same moment. Without a link, both must build for their own worst hour. The Gulf Cooperation Council Interconnection Authority already ties the Saudi grid to its Gulf neighbours, but the GCC link is an alternating-current tie sized mainly for emergency support rather than for large commercial energy trade, and there was no connection at all to the much larger North African and Levantine systems. Saudi Arabia also faced the prospect of a large midday solar surplus from the National Renewable Energy Program with no export outlet, while Egypt was building its own solar and wind fleet and needed firm imports at its evening peak. The two systems are also at different frequencies in practice and need controllable power flow, which is why an AC tie was not the answer.

What it does

In October 2021 the two governments and their transmission companies signed the engineering, procurement and construction contracts for the Saudi-Egypt electrical interconnection: a bidirectional high-voltage direct-current scheme rated at roughly 3,000 MW, built around three converter stations (in the Medina and Tabuk regions in Saudi Arabia and at Badr, east of Cairo, in Egypt) connected by overhead lines and a submarine cable crossing the Gulf of Aqaba. The Saudi side is delivered by National Grid SA under the restructured sector, the Egyptian side by the Egyptian Electricity Transmission Company, with the converter and cable packages awarded to international HVDC suppliers and regional civil contractors. The project was conceived to be delivered in stages, with a first tranche of capacity energised ahead of full rating, and it is governed by an intergovernmental framework plus commercial arrangements between the two transmission entities that set the terms on which energy and reserve are exchanged. Total project cost has been put at around US$1.8 billion, split between the two sides. Commissioning has slipped from the original target: the first stage was expected in the mid-2020s, and the current expectation is energisation in the second half of the decade.

Market effect

A 3,000 MW controllable link is roughly the size of two large combined-cycle plants and is large enough to change dispatch on both sides. For Saudi Arabia it creates the first real export outlet for surplus solar energy in the middle of the day and a source of import during the extreme summer evening ramp, which reduces the firm capacity both systems must hold and defers thermal build. For Egypt it is a firm-capacity lifeline at the evening peak and, in the other direction, an outlet for its own surplus, which strengthens the case for the Egyptian renewable pipeline and for Egypt's ambitions as a transit point toward Europe through the Mediterranean cables. Because the tie is HVDC, flow is scheduled rather than determined by impedance, so the commercial arrangements between National Grid SA and the Egyptian transmission company decide who captures the value; the absence of a wholesale spot market on the Saudi side means the gain accrues to the state entities rather than to merchant traders. The strategic reading is that this is the first physical step toward an Arab common electricity market linking the GCC grid, Egypt, Jordan and the Levant, and eventually to Europe, which is why lenders and equipment suppliers treat it as a template rather than a one-off.

Key numbers

Rated capacity
About 3,000 MW, bidirectional HVDC
Converter stations
Medina and Tabuk regions (Saudi Arabia) and Badr (Egypt)
Contracts signed
October 2021
Reported total cost
About US$1.8 billion, shared between the two countries

Who gains and who pays

  • National Grid SA (obligation): Builds and operates the Saudi converter stations and lines and holds the trading interface.
  • Egyptian Electricity Transmission Company (gains): Gains firm import capability at the evening peak and an export outlet for surplus.
  • Saudi renewable generators (gains): An export path for midday solar surplus that would otherwise be curtailed.
  • Thermal generators in both systems (costs): Shared reserve reduces the firm capacity each country must build and pay for.
  • HVDC equipment suppliers and cable contractors (gains): Converter, line and submarine cable packages worth a substantial share of the project cost.
  • GCC Interconnection Authority and neighbouring systems (mixed): A larger interconnected footprint, but also competition for the same trading value.

Implementation

Delivery sits with the two transmission companies and their EPC contractors. The critical path runs through the converter stations, the overhead line corridors across desert terrain and the submarine crossing of the Gulf of Aqaba, and the project has been staged so that a first tranche of transfer capability can be commissioned before the full rating. Beyond the physical works, the commercial arrangements matter as much: scheduling rules, loss allocation, reserve-sharing terms and settlement between National Grid SA and the Egyptian transmission company determine whether the link is used as an emergency tie or as a genuine trading interface, and those documents are not public. Schedule has slipped repeatedly against the original mid-decade target. Because National Grid SA's site did not resolve from this environment and the Egyptian counterpart publishes mainly in Arabic, the capacity rating, the cost split, the staging plan and the current commissioning date should all be confirmed against ngrid.sa and the Egyptian Ministry of Electricity before being relied on.

Concerns

  • Repeated schedule slippage against the original mid-decade commissioning target
  • Commercial and scheduling arrangements between the two transmission entities are not public
  • Currency and payment risk on the Egyptian side of any energy trade
  • Submarine crossing of the Gulf of Aqaba is the highest-risk construction package
  • Neither country has a wholesale market, so price discovery on the link is administrative
  • Political dependence of cross-border flows on the bilateral relationship

Dates to watch

  • 2027: Expected energisation window for the first stage of transfer capability
  • 2028: Full 3,000 MW rating and start of routine commercial exchange

Sources

Checked against sources on .

Amended Electricity Law and sector restructuring · principal buyer, National Grid SA, WERA

Saudi Arabia · Council of Ministers and the Water and Electricity Regulatory Authority (WERA) · statute · 2020

Where it stands: Amended law in force; unbundling completed with National Grid SA and SPPC operating as separate licensed entities under WERA

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

The problem

Until 2020 the Saudi power sector was effectively one company. Saudi Electricity Company owned most generation, all transmission and all distribution, bought fuel at administratively set prices far below export parity, sold electricity at tariffs that did not cover cost, and was kept solvent by government balances and soft loans. That structure could not finance the build-out Vision 2030 assumed. Independent power producers had no creditworthy counterparty separate from the incumbent, lenders could not see a ring-fenced transmission revenue stream, and there was no regulator with the statutory tools to set third-party access terms, approve a grid code or run a transparent cost-of-service review. The government also wanted to open generation to competition and eventually to a wholesale market without privatising the wires, which required the network and the procurement function to sit outside the incumbent's balance sheet. The original Electricity Law issued by Royal Decree in 2005 had created a regulator but not an unbundled market, so the statute itself had to be reopened.

What it does

The amended Electricity Law, approved by the Council of Ministers and issued by Royal Decree in 2020, sets out a licensed, unbundled sector: generation, transmission, distribution, retail supply and the principal-buyer function each require a separate licence, and cross-holdings are constrained. Three structural moves followed. First, Saudi Electricity Company was separated into ring-fenced activity companies, and its transmission business was transferred to the National Grid Company (National Grid SA), which since 2021 has operated as the licensed transmission owner and system operator with its own regulated revenue. Second, the Saudi Power Procurement Company (SPPC) was separated from SEC and placed under state ownership as the single principal buyer: it signs every new power purchase agreement, holds the offtake obligation for independent power and water projects and for the National Renewable Energy Program rounds, and resells to the distribution and supply businesses. Third, the Electricity and Cogeneration Regulatory Authority was reconstituted as the Water and Electricity Regulatory Authority (WERA), which issues licences, the Saudi Grid Code and Distribution Code, connection and third-party access rules, performance standards and the cost-of-service methodology, and consults on drafts through the Istitlaa platform. Consumer tariffs remain a Council of Ministers decision on the Ministry of Energy's proposal rather than a WERA determination, so price-setting and network regulation sit in different hands.

Market effect

The practical change for anyone financing a Saudi plant is counterparty identity. Before 2020 an IPP sold to SEC, a leveraged utility; after the restructuring it sells to SPPC, a state-owned single buyer whose only business is procurement, which is why Saudi solar PPAs since 2021 have cleared at tariffs among the lowest in the world and have attracted international lenders and export-credit agencies without sovereign guarantees on every deal. Ring-fencing transmission created, for the first time, a regulated network business whose revenue is set by WERA-approved cost of service, which is the precondition for open access, for connecting the multi-gigawatt renewable sites in the north and west, and for treating the Saudi-Egypt interconnection as a network asset rather than a company project. The licensing regime gives developers an enforceable connection path and gives WERA a lever over SEC's build programme. What has not changed is the demand side: distribution and supply remain a regulated monopoly with Council of Ministers tariffs, so competitive pressure stops at the meter, and the wholesale spot market that the law contemplates has not been launched. Traders should read Saudi Arabia as a single-buyer market with bankable long-term contracts, not as a merchant market.

Key numbers

Parent statute
Electricity Law issued by Royal Decree in 2005 (M/56 of 1426H), amended by Royal Decree in 2020
Structure created
Five licensed activities: generation, transmission, distribution, retail supply, principal buyer
Single buyer
Saudi Power Procurement Company (SPPC), sole offtaker for new IPP and renewable capacity
Transmission
National Grid SA, licensed transmission owner and system operator from 2021

Who gains and who pays

  • Independent power and renewable developers (gains): A dedicated state offtaker (SPPC) instead of a leveraged utility counterparty.
  • Saudi Electricity Company (costs): Lost transmission and the procurement function; now a licensed, regulated set of activity companies.
  • National Grid SA (gains): Regulated transmission owner and system operator with its own revenue and build programme.
  • WERA (obligation): Must issue licences, codes, access rules and cost-of-service determinations for electricity and water.
  • Lenders and export-credit agencies (gains): Ring-fenced, licensed counterparties make limited-recourse project finance workable.
  • Retail consumers (mixed): Better-financed supply, but tariffs still set administratively by the Council of Ministers.

Implementation

Implementation runs through WERA's licence conditions and codes rather than through the statute. The regulator has issued or revised the Saudi Grid Code, the Distribution Code, connection and metering rules and the licensing framework, each posted in draft for consultation on the Istitlaa platform before Board approval. SPPC's procurement regulations, standard PPA and water purchase agreement templates and qualification rules are published separately and are what bidders actually price against. The remaining gaps are the ones to watch: the wholesale market envisaged by the amended law has not been opened, third-party access for large consumers is still narrow, and the cost-of-service review that would put SEC's distribution business and National Grid SA on a formal revenue cap is a continuing WERA workstream. Because WERA and SPPC publish mainly in Arabic and their sites were not reachable for this review, the decree number, the exact commencement date and the current code versions should be confirmed against the Umm Al-Qura gazette and the WERA site before relying on them.

Concerns

  • No wholesale spot market yet, so price discovery is limited to procurement rounds
  • Tariff-setting sits with the Council of Ministers, not the regulator, which weakens cost-reflectivity
  • SPPC's credit quality is ultimately sovereign, concentrating offtake risk in one entity
  • Transmission build must keep pace with multi-gigawatt renewable sites far from load
  • Regulatory texts are published mainly in Arabic, raising diligence cost for foreign lenders
  • Distribution and retail remain a monopoly, so efficiency gains depend on regulation rather than competition

Dates to watch

  • 2027: Expected further WERA code and cost-of-service revisions as renewable penetration rises
  • 2030: Vision 2030 target date for a 50 percent renewable generation mix, the stress test for the single-buyer model

Sources

Checked against sources on .

Electricity tariff and domestic fuel-price reform · the 2018 step and the later adjustments

Saudi Arabia · Council of Ministers on the proposal of the Ministry of Energy · decision · 2018

Where it stands: Reformed tariffs and administered fuel prices in force since 2018, with periodic Council of Ministers adjustments including in 2024

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

The problem

Saudi electricity was among the cheapest in the world because two subsidies stacked on top of each other. Generators bought crude, heavy fuel oil, diesel, ethane and methane at administered prices that were a fraction of export parity, and consumers then bought the resulting electricity at tariffs below even that subsidised cost. The result was per-capita consumption comparable to the coldest or hottest rich countries, no incentive to insulate buildings or buy efficient air-conditioning, a peak that grew several percent a year, and a fiscal transfer that showed up as forgone oil-export revenue rather than as a budget line. It also made efficiency investment and, later, renewables look artificially unattractive, because the fuel they displaced was priced at a few dollars a barrel. Fixing generation economics therefore required fixing the price of the input, and fixing demand growth required fixing the price of the output; the government did both in the same package so that the utility was not squeezed between them.

What it does

Effective 1 January 2018 the Council of Ministers, on the Ministry of Energy's proposal, raised residential electricity tariffs to a two-block structure and lifted commercial, industrial and government tariffs, while the associated energy-price reform raised the administered prices of methane and ethane sold to industry and power generation and of gasoline, diesel and heavy fuel oil. The reform was deliberately paired with the Citizen's Account, a means-tested monthly cash transfer that compensates eligible Saudi households for the cost-of-living effect, so that the price signal reaches every consumer at the margin while the income effect is offset for lower-income families. Because generators buy fuel at the administered price and sell at regulated tariffs into the principal-buyer framework, the two decisions have to move together: a fuel-price rise without a tariff rise simply moves the deficit onto Saudi Electricity Company's balance sheet. The Council of Ministers has revisited the schedule since, including adjustments in 2024 to the fuel prices charged to the power and desalination sectors and to parts of the tariff schedule, with the stated direction of travel being gradual movement toward cost-reflective prices while protecting households through the Citizen's Account rather than through the tariff.

Market effect

The 2018 step is the single most important number in any Saudi demand forecast: it broke the pre-2018 growth trend, cut residential consumption in the first years after the increase and permanently changed the economics of efficiency retrofits, district cooling and rooftop solar for commercial customers. On the supply side, raising the price of gas and liquids to generators is what makes the renewable programme work financially. When a combined-cycle plant burns gas priced near a token level, a solar PPA at US$15 to US$20 per MWh saves almost nothing; when the fuel is priced closer to its opportunity cost, the same PPA displaces a genuinely expensive marginal fuel and the saving is real and appears in SPPC's portfolio cost. That is the mechanism that links this brief to the National Renewable Energy Program: the fuel-price decisions, not the tariff decisions, are what make gigawatt-scale solar rational for the state. The reform also changes the risk a lender takes on the distribution business, because a utility selling closer to cost needs less government support. What remains is the gap: tariffs are still administered rather than cost-based, the Council of Ministers rather than WERA sets them, and the residual subsidy is now explicit and therefore politically visible, which makes the timing of further steps a live uncertainty for any long-dated demand model.

Key numbers

Effective date of the main tariff step
1 January 2018
Residential structure introduced in 2018
A two-block tariff with a lower rate up to a monthly consumption threshold and a higher rate above it
Compensation mechanism
Citizen's Account monthly means-tested cash transfer, paid outside the tariff
Most recent review
2024 adjustments to power and desalination fuel prices and parts of the tariff schedule

Who gains and who pays

  • Residential and commercial consumers (costs): Higher bills at the margin, partially offset for eligible households by the Citizen's Account.
  • Saudi Electricity Company and the supply business (mixed): Higher revenue per unit but also a higher fuel bill; margin depends on the two decisions moving together.
  • Renewable developers (gains): Higher administered fuel prices raise the value of the thermal generation their output displaces.
  • Energy-efficiency, district cooling and rooftop solar providers (gains): Payback periods shortened materially after the tariff step.
  • Energy-intensive industry (costs): Higher ethane, methane and electricity prices erode the historical feedstock advantage.
  • The state budget (gains): Converts forgone export revenue into either fiscal revenue or exportable volume.

Implementation

Tariffs are implemented through Saudi Electricity Company's published schedule and billing systems, and fuel prices through the supply contracts between Saudi Aramco and the generators and desalination operators. Because the Council of Ministers sets both, the announcement is the implementation: there is no consultation, no regulatory docket and no appeal, and the market usually learns of a change through the official news agency and the utility's tariff page a short time before it takes effect. WERA's role is limited to the cost-of-service work that informs the proposal and to monitoring licensee compliance. The practical guidance for a forecaster is to treat further steps as a policy event with no published timetable, to watch the Citizen's Account budget as the leading indicator of appetite for another increase, and to check the current schedule directly. The specific 2018 rates per kilowatt-hour, the consumption threshold between blocks and the content of the 2024 decisions were not verifiable from this environment and must be confirmed before use.

Concerns

  • Tariffs remain administered rather than cost-reflective, so a residual subsidy persists
  • Price changes arrive without a published timetable, which makes long-dated demand forecasting hard
  • Higher feedstock and power prices erode the competitiveness of energy-intensive Saudi industry
  • Citizen's Account compensation is a fiscal cost that rises with each tariff step
  • Political sensitivity of household bills can stall the next increase indefinitely
  • The split between the Council of Ministers setting tariffs and WERA regulating networks blurs accountability

Dates to watch

  • 2027: Possible next step in the tariff or fuel-price schedule as cost-reflectivity is pursued
  • 2030: Vision 2030 horizon for efficiency and demand-growth targets that the tariff underpins

Sources

Checked against sources on .

Saudi civil nuclear programme · regulator, research reactor and the large-reactor tender

Saudi Arabia · Ministry of Energy, King Abdullah City for Atomic and Renewable Energy and the Nuclear and Radiological Regulatory Commission · plan · 2018

Where it stands: Institutions and regulator in place and a research reactor under construction, but the large-reactor tender remains unawarded pending safeguards and cooperation-agreement decisions

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

The problem

Saudi Arabia's generation mix is gas and liquids, its demand peaks hard in summer and its desalination fleet is one of the largest electricity consumers in the world. Nuclear offers exactly what a mid-day-solar-plus-evening-peak system lacks: firm, carbon-free baseload that also pairs with thermal desalination, and that does not consume exportable hydrocarbons. Vision 2030 therefore includes an atomic energy component alongside renewables. But nuclear is the one technology where the constraint is diplomatic rather than commercial. Vendors from the United States cannot export reactor technology without a section 123 nuclear cooperation agreement, and other vendors' financing and insurance depend on the same safeguards architecture. Saudi Arabia's historical position on enrichment, and its use of the IAEA Small Quantities Protocol, which suspends most routine inspection obligations for states with negligible nuclear material, have been the sticking point with Washington and with non-proliferation constituencies, and have repeatedly stalled a tender that has technically been ready for years.

What it does

The government created the institutional scaffolding first. The National Atomic Energy Project sets policy, King Abdullah City for Atomic and Renewable Energy (K.A.CARE) developed the programme and the siting work, and the Nuclear and Radiological Regulatory Commission was established as the independent regulator with authority to license facilities, issue regulations on siting, design, radiation protection, transport and waste, and inspect. A low-power research reactor has been under construction at the King Abdulaziz City for Science and Technology campus in Riyadh as the training and licensing pathfinder, and Saudi Arabia has built the supporting legal instruments including a nuclear law, radiation protection regulations and safeguards arrangements with the International Atomic Energy Agency. On the build side, the programme has been framed around an initial two large reactors of roughly 1.2 to 1.4 GW each at a coastal site, with vendors from Korea, China, France, Russia and the United States all having been engaged at various points. In parallel Saudi Arabia has moved to rescind the Small Quantities Protocol and adopt the full safeguards agreement reporting obligations, which is the technical precondition that unlocks supplier-state approvals, and negotiations on a nuclear cooperation agreement with the United States have continued through 2025 and 2026 alongside the broader bilateral package.

Market effect

For a power-market participant the programme matters mainly as an option on the 2030s rather than as capacity in this decade. Two 1.4 GW units would be roughly 2.8 GW of must-run baseload in a system whose midday hours are already being flooded by tendered solar, which would push the residual load curve further into a deep daytime trough and a sharp evening ramp, increasing the value of storage and flexible gas and reducing the energy value of new solar at the margin. That is the opposite of what the renewable programme wants, so the two policies interact: the more nuclear is built, the narrower the economic space for additional daytime solar without storage. For suppliers and lenders, the commercial prize is large (a first-of-a-kind two-unit order plus a follow-on fleet, plus fuel, services and local content over sixty years) and is the reason vendor governments have engaged diplomatically. But the timeline is long even after an award: licensing, site works and construction put first concrete years ahead of first power. The practical signal to watch is not a procurement announcement but a safeguards or cooperation-agreement announcement, because that is the gate that has actually been binding.

Key numbers

Initial build concept
Two large reactors of roughly 1.2 to 1.4 GW each at a coastal site
Pathfinder facility
A low-power research reactor under construction in Riyadh for training and licensing experience
Regulator
Nuclear and Radiological Regulatory Commission, the independent licensing and inspection authority
Binding gate
Safeguards framework: moving off the IAEA Small Quantities Protocol and concluding a supplier-state cooperation agreement

Who gains and who pays

  • Reactor vendors and their export-credit agencies (gains): A first two-unit order with fleet follow-on and decades of fuel and services.
  • Nuclear and Radiological Regulatory Commission (obligation): Must license, inspect and regulate a first-of-a-kind programme with a new workforce.
  • Solar developers and SPPC's renewable pipeline (costs): Must-run baseload deepens the midday trough and erodes the marginal value of new solar.
  • Storage and flexible gas providers (gains): A steeper evening ramp with more inflexible baseload raises the value of flexibility.
  • Desalination operators (gains): Firm low-carbon heat and power is a natural pairing with large-scale water production.
  • Non-proliferation stakeholders and supplier governments (mixed): Safeguards terms, including enrichment and the Small Quantities Protocol, gate the whole programme.

Implementation

Nothing in the programme moves until the safeguards and cooperation-agreement questions are settled, because vendor export licences depend on them. After that, the sequence is a vendor selection and intergovernmental agreement, a construction licence from the Nuclear and Radiological Regulatory Commission covering the chosen site, then roughly six to ten years of construction for a first-of-a-kind two-unit project, plus commissioning. The offtake structure is not settled publicly either: under the restructured sector SPPC would be the natural counterparty for a nuclear power purchase agreement, but a state-owned build-own-operate vehicle is equally plausible. Watch three things in order: an IAEA announcement on Saudi Arabia's safeguards status, a United States or other supplier-state cooperation agreement, and only then a vendor award. Because Saudi government and regulator websites were not reachable for this review, the establishment instrument and date of the regulator, the status of the research reactor and the current state of the safeguards question should all be confirmed before use.

Concerns

  • Safeguards and enrichment policy remain the binding constraint on any vendor award
  • A first-of-a-kind two-unit project carries severe cost and schedule risk
  • Must-run baseload conflicts with the economics of the solar procurement programme
  • Regulatory capacity and a trained workforce must be built from a very low base
  • Spent fuel and waste arrangements are not publicly settled
  • Vendor selection is entangled with wider geopolitical negotiations rather than price

Dates to watch

  • 2027: Possible vendor selection for the first two large units if the safeguards framework is settled
  • 2030: Earliest realistic first-concrete-to-operation horizon slips beyond this date on any current schedule

Sources

Checked against sources on .

National Renewable Energy Program · procurement rounds and the 50 percent renewables target for 2030

Saudi Arabia · Ministry of Energy and the Saudi Power Procurement Company · plan · 2017

Where it stands: Programme running: successive SPPC competitive rounds and PIF negotiated projects awarding solar, wind and storage capacity each year

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

The problem

Saudi Arabia burns crude oil, heavy fuel oil, diesel and gas to make electricity, and summer air-conditioning load makes the peak enormous relative to the population. Every barrel burned domestically at subsidised prices is a barrel not exported, so domestic power demand was a direct claim on export revenue, and demand was growing faster than gas supply. The country has some of the best solar resource and cheapest land in the world, but in 2016 it had almost no utility-scale renewable capacity, no procurement machinery, no grid code provisions for variable generation and no track record that would let developers price country risk. Vision 2030 therefore needed a programme that could do three things at once: displace liquids burning, create a domestic renewable supply chain and local content, and prove to international lenders that Saudi offtake was bankable.

What it does

The Ministry of Energy launched the National Renewable Energy Program in 2017 through the Renewable Energy Project Development Office, which ran the first competitive rounds: the 300 MW Sakaka solar plant in Al Jouf was the first award and the first utility-scale plant to reach commercial operation, and the 400 MW Dumat Al Jandal wind project followed as the Kingdom's first wind farm. In 2019 the government split delivery between two tracks: roughly 70 percent of the programme is developed on a negotiated basis by the Public Investment Fund with its partners (the Sudair, Shuaibah, Ar Rass, Saad and similar multi-hundred-megawatt to gigawatt-scale plants), and roughly 30 percent is tendered competitively. Since the 2020 restructuring the competitive rounds have been run by SPPC as principal buyer: it issues a request for qualification, shortlists, issues the request for proposals with a standard 20 to 25 year power purchase agreement, names a preferred bidder on levelised tariff and signs the PPA, with financial close following. Rounds have been issued at roughly annual cadence and have grown from hundreds of megawatts to several gigawatts per round across solar PV and onshore wind, supported by local-content requirements and by domestic module and tower manufacturing. The headline policy anchor is the Ministry of Energy's target of about a 50 percent renewable share of the generation mix by 2030, with the balance from gas, and an associated build programme measured in tens of gigawatts.

Market effect

The programme has repriced Saudi power. Competitively tendered solar tariffs have repeatedly set or approached world-record lows, well under US$20 per MWh at the best sites, because the combination of irradiance, flat cheap land, a single-buyer PPA, low-cost local debt and PIF equity strips most of the risk premium out. That does two things to the system. It puts a hard ceiling on what any new thermal plant can charge for daytime energy, so new gas capacity is being justified on flexibility and firm capacity rather than energy, and it accelerates the displacement of liquids burning, freeing crude and products for export at a direct fiscal gain. For the grid it creates a transmission problem rather than a generation problem: the best sites are in the north, north-west and Empty Quarter fringe, while load is in Riyadh, the Eastern Province and Jeddah, so National Grid SA's reinforcement programme is now the binding constraint on how fast the pipeline can connect. For developers, the 70/30 split matters commercially: the majority of volume is negotiated with PIF-affiliated vehicles, so international independents compete for the smaller tendered share, usually as minority partners or EPC and O&M contractors. Storage is the next tranche, because a mid-day solar surplus with an evening air-conditioning peak is exactly the shape that pays batteries.

Key numbers

2030 target
About 50 percent of the generation mix from renewables, the balance mainly gas
Programme launch
2017, Renewable Energy Project Development Office; competitive rounds moved to SPPC after 2020
First projects
Sakaka 300 MW solar (first utility-scale plant) and Dumat Al Jandal 400 MW wind (first wind farm)
Delivery split
About 70 percent negotiated through the Public Investment Fund, about 30 percent competitively tendered

Who gains and who pays

  • Solar and wind developers and EPC contractors (gains): Multi-gigawatt annual pipeline with a single creditworthy offtaker.
  • Public Investment Fund and its partners (gains): Roughly 70 percent of programme volume on a negotiated basis.
  • Saudi Aramco and the export balance (gains): Liquids and gas displaced from the power sector are freed for export or petrochemicals.
  • Existing thermal generators (costs): Daytime energy value collapses; plants are pushed toward flexibility and reserve roles.
  • National Grid SA (obligation): Must build the transmission that connects remote gigawatt-scale sites to coastal and central load.
  • International independent power producers (mixed): Only the competitive tranche is genuinely open; margins are thin at record-low tariffs.

Implementation

Delivery now runs almost entirely through SPPC's procurement cycle and PIF's negotiated projects. A competitive round takes roughly 12 to 24 months from request for qualification to signed PPA and a further two to three years to commercial operation, so awards made in 2025 and 2026 are 2028 to 2029 capacity. The gating items are grid connection dates from National Grid SA, local-content compliance, and land allocation. Storage procurement has been added alongside solar, and the Ministry of Energy has signalled that battery volumes will scale with the solar pipeline. Because moenergy.gov.sa, spc.sa and wera.gov.sa were not reachable for this review, the specific round numbers, awarded capacities, winning tariffs and the cumulative installed total should be confirmed on SPPC's projects page and the Ministry of Energy site before being used in a model or a term sheet.

Concerns

  • Transmission build-out is the binding constraint on connecting remote gigawatt-scale sites
  • Record-low tariffs leave little margin for construction cost or interest-rate shocks
  • Concentration of volume in PIF-affiliated vehicles narrows genuine competition
  • Evening peak still needs firm capacity, so gas and storage costs offset the cheap solar energy
  • Local-content rules raise delivered cost and can slow procurement
  • The 2030 target implies a build rate that has to be sustained for several more years

Dates to watch

  • 2027: Commercial operation of capacity awarded in the 2024-2025 rounds
  • 2030: Target year for an approximately 50 percent renewable generation mix

Sources

Checked against sources on .