Future of Power Systems

Innovation Playbook for Future Power Systems

In collaboration with Accenture

A practical resource for decision-makers as power systems evolve under increasing demand.
Scroll to explore innovative solutions and read the report for global insights. 

Explore the solutions

Discover 30+ new case studies added to our growing library of 130+ real-world examples, showcasing how 110 innovative solutions are delivering value across power systems today.  

Long-term community benefit sharing embeds a durable economic stake for the people and communities that host new energy infrastructure. Rather than relying primarily on one-off compensation for land access or project impacts, these models distribute benefits over the operating life of an asset through mechanisms such as recurring landholder payments, community funds, revenue sharing or local equity ownership. The approach can be established through government policy, procurement requirements or agreements between project developers, network operators and host communities. Payments can be linked to the infrastructure hosted, while ownership models can allow communities to participate directly in project returns through trusts or other investment structures. By connecting local benefits to the long-term operation and performance of infrastructure, these models can create a more enduring alignment between project delivery and local economic interests. This matters as expanding transmission, renewable generation and other power infrastructure increasingly requires development in communities that may bear concentrated land-use, visual or construction impacts while the wider system receives the benefits. Well-designed benefit-sharing arrangements can make those local benefits more tangible and sustained, complementing engagement and compensation while supporting community acceptance and infrastructure deployment.Main Outcomes of the SolutionSocioeconomic Impact: Directs long-term economic value to communities and landholders hosting power infrastructure through recurring payments, community funds or participation in project ownership. Institutional Efficiency & Transparency: Establishes clearer and more predictable frameworks for determining, distributing and reporting benefits to host communities and landholders. Business Value: Better alignment of project and community interests can reduce stakeholder-related development risk and support the long-term deliverability of infrastructure investment.Key implementation and scaling factorsDefine upfront which communities or landholders qualify, which infrastructure is covered and how benefits are calculated and distributed.Structure benefits over the asset life, rather than relying solely on one-off compensation, with payments or returns designed to provide meaningful and proportionate local value.Embed benefit sharing in licenses, procurement requirements, project agreements or ownership structures to support consistent delivery.Establish clear payment schedules, reporting requirements and dispute-resolution mechanisms to maintain trust over long project lifetimes.Use accessible and transparent ownership structures, such as community trusts, with appropriate governance and community participation to aggregate ownership and distribute project returns.Case studiesNSW Government & EnergyCo (2024), AustraliaNew South Wales (NSW), Australia, introduced the Strategic Benefit Payments (SBP) Scheme to provide long-term financial benefits to eligible landholders hosting major transmission infrastructure. Under the scheme, network operators make payments to eligible landholders in addition to compensation for transmission easements. Eligible landholders receive the equivalent of A$200,000 (USD 143,000 as of Sep 2026) in 2022 dollars per kilometre of eligible transmission infrastructure hosted on their property, paid in annual instalments over 20 years and adjusted for inflation. Payments begin after the infrastructure is energized. First announced in 2022, the scheme is now implemented through conditions on network operator licenses, with detailed guidelines effective from July 2025. This embeds long-term benefit sharing within the regulatory framework rather than relying solely on voluntary project-level arrangements. By extending payments over 20 years, the scheme provides an ongoing economic benefit to landholders hosting infrastructure required for power-system expansion.Ørsted (2016-present), United Kingdom Ørsted operates a portfolio of Community Benefit Funds linked to its offshore wind farms in the United Kingdom, providing long-term funding to coastal communities hosting or affected by associated infrastructure. Its East Coast Community Fund, established in 2016 alongside the Hornsea and Race Bank offshore wind projects, provides £465,000 annually for a 20 year period, including dedicated funding for skills development, and so far has awarded almost £4.5 million to over 328 community and environmental projects across Yorkshire, Lincolnshire and North Norfolk. Ørsted has subsequently extended the model to other projects, including the Hornsea 3 Community Fund, which will provide £7 million over a minimum ten-year period, split between community, skills and legacy funding. The funds are administered independently by GrantScape, with local advisory groups contributing to funding decisions. Across Ørsted's four UK Community Benefit Funds, more than £15 million has been awarded to over 1000 local projects, demonstrating how recurring project-linked funding can provide sustained benefits throughout renewable infrastructure development and operation.Department of Electricity and Energy (2011-present), South AfricaSouth Africa's Renewable Energy Independent Power Producer Procurement Program (REIPPPP) integrates community participation into the competitive procurement of grid-connected renewable generation. Under the program, economic-development requirements complement the technical and commercial elements of procurement, including local community ownership of renewable energy projects. Community ownership has typically been structured through community trusts, allowing qualifying communities around projects to hold equity and participate in project returns. In 2019, the government reported that projects procured at that stage represented R209.4 billion (USD 13.0 billion as of Sep 2026) in committed private-sector investment and projected that qualifying communities would receive R27.1 billion (USD 1.68 billion as of Sep 2026) in net dividend income from their shareholdings over the 20-year operating lives of those projects. The program has continued through subsequent procurement rounds. For projects reaching financial close in Bid Windows 1-6, the government reported in 2025 that black local communities held an average 8% ownership, compared with a 5% target average. The programme demonstrates how long-term community participation can be embedded within large-scale competitive power procurement, linking renewable-energy investment with local economic participation through project ownership.References:Strategic Benefit Payments Scheme explained | EnergyCoRenewable energy programme attracts R209.4 billion to SA economy | SAnewsOur Community Benefit Funds | Ørsted Ørsted Launches Largest Annual Community Benefit Fund | Ørsted Over £2 Million Awarded from Ørsted’s East Coast Community Fund | Ørsted
Long-term community benefit sharing
Ørsted, EnergyCo, Department of Electricity and Energy of South Africa
Flexible and bankable connection agreements allow large electricity users to connect under terms that better align their demand with available system capacity while reducing the risk of cost shifting to other customers. Instead of requiring every new load to receive a fully firm connection from the outset, agreements can make part of the connection conditional on the customer reducing or shifting demand when the system is constrained. Modeling of six potential data center sites in the United States found that combining flexible grid connections with customer-provided capacity could enable full operation three to five years earlier than conventional connection pathways, while maintaining grid power availability for more than 99% of annual hours and requiring on-site resources for approximately 40–70 hours per year. The same framework can determine which network costs should be recovered directly from the connecting customer and which should be shared where upgrades provide wider system benefits. Long-term contracts, minimum payment obligations, collateral and exit provisions can give utilities greater confidence that investments made to serve the load will be recovered even if demand develops more slowly than expected. Together, these mechanisms can enable earlier connections, make better use of existing infrastructure and reduce the risk of stranded network investment. Their effectiveness depends on clear curtailment rules, transparent cost allocation and contractual terms that remain sufficiently predictable for utilities, customers and financiers to make long-term investment decisions.  Main Outcomes of the Solution Affordability: More direct cost allocation and improved asset utilization can reduce the risk of existing customers funding underused or customer-specific network investment.  Reliability & Flexibility: Curtailment and demand-response provisions allow large users to reduce or shift consumption during constrained periods, providing operators with additional flexibility to manage load growth.  Business Value: Long-term commitments, minimum payments and financial security can increase revenue certainty and improve the bankability of infrastructure required for large-load connections. Key implementation and scaling factors Establish clear curtailment rules, including triggering conditions, duration, notice requirements and operational responsibilities. Define transparent cost-allocation rules that distinguish customer-specific infrastructure from investments providing wider system benefits. Align long-term contractual commitments with the scale and timing of infrastructure investment and expected load ramp-up. Set proportionate minimum-payment, collateral and exit provisions based on customer creditworthiness and investment exposure. Establish regulatory approval and cost-recovery frameworks for connection, tariff and network-investment arrangements. Ensure adequate metering, telemetry, communications and integration with operational systems where connections depend on real-time load flexibility. Case studiesGoogle (2026), United States of America  In March 2026, Google reported that it had integrated 1 GW of data-center demand-response capacity into long-term energy contracts with five U.S. utility partners: Indiana Michigan Power, Tennessee Valley Authority, Entergy Arkansas, Minnesota Power and DTE Energy. Under these arrangements, Google can temporarily reduce or shift portions of machine-learning workloads running in its data centers during specified periods, allowing participating utilities to treat part of the load as flexible rather than assuming that all demand must be served continuously. Google notes that the degree of flexibility varies by location and workload.  Google states that incorporating demand response into these agreements can support faster connection of new data centers by allowing utilities to manage periods of high demand using existing system resources while additional generation and network capacity is developed. The arrangements illustrate how large-load customers can leverage operational flexibility to enable faster connection arrangements that better reflect available system capacity and bring benefits to the broader grid.AEP Ohio and Public Utilities Commission of Ohio (2025), United States of America  In July 2025, the Public Utilities Commission of Ohio adopted a settlement establishing AEP Ohio's dedicated data-center tariff, which became effective on July 23. The tariff introduces stronger financial commitments for new data centers seeking service, including minimum billing requirements, collateral and financial viability requirements, and exit fees where projects are canceled or contractual obligations are not met.  Minimum billing demand is generally capped at 85% of total contract capacity, while the initial contract term comprises a load-ramp period of up to four years followed by eight years. As of February 12, 2026, AEP Ohio reported that data centers and developers had signed binding contracts covering 5,642 MW under the tariff and provided the associated collateral. The framework links infrastructure commitments more closely to contracted customer demand, reducing the risk that costs associated with unused capacity are shifted to other customers. Indiana Michigan Power (2025), United States of America In February 2025, the Indiana Utility Regulatory Commission approved modifications to Indiana Michigan Power's industrial power tariff for large-load customers. The provisions apply to customers with contract capacity of at least 70 MW at an individual site or 150 MW on an aggregated basis.  The framework includes long-term contractual commitments, minimum payment requirements, collateral and protections where customers reduce or terminate service. Collateral requirements are generally linked to 24 months of the customer's maximum monthly non-fuel bill, subject to exemptions based on creditworthiness and liquidity. These measures are designed to reduce the financial exposure associated with infrastructure investments made in anticipation of large new loads by requiring customers to make financial commitments before substantial investment is undertaken. The case illustrates how contractual and tariff design can strengthen the bankability of large-load connections while reducing the risk of costs being transferred to other electricity customers. References:A New Milestone for Smart, Affordable Electricity Growth | Google  Data Center Tariff | AEP Ohio  Flexible Data Centers: A Faster, More Affordable Path to Power | Camus Energy, encoord & Princeton ZERO Lab Indiana Michigan Power Receives Order in Large Load Settlement | Indiana Michigan Power  Large-Load Framework | Indiana Michigan Power   
Flexible large-load connection agreements
Google, AEP Ohio, Indiana Michigan Power
Alternative and non-firm grid connections provide new or existing users with routes to connect without relying solely on a conventional fully firm connection delivered by the network operator. Users may accept time-dependent or conditional access to shared network capacity, build or own elements of their own connection infrastructure, or combine a reduced firm grid allocation with dedicated generation and storage. Under non-firm arrangements, access rights can vary by time or network conditions, requiring users to reduce or shift grid use when capacity is constrained. Other models shift responsibility for connection infrastructure or part of the required supply to the connecting customer, reducing dependence on network-led construction or additional firm capacity. These approaches can make better use of existing network headroom, enable projects to connect before conventional reinforcement is completed and give flexible users additional routes to power where firm capacity is unavailable. They can also reduce or defer network investment where customers can economically provide flexibility, infrastructure or supply themselves. Effective implementation requires clear rules governing access rights, curtailment, ownership, network charges, backup capacity and operational responsibilities, alongside sufficient network visibility and users capable of operating within the agreed connection conditions. Main Outcomes of the Solution Reliability & Flexibility: Conditional access allows operators to restrict or reduce grid use during constrained periods, while customer-provided generation and storage can reduce reliance on firm network capacity and support the integration of additional demand.  Affordability: Alternative and non-firm connections can improve utilization of existing network capacity and reduce or defer reinforcement, while customer-led infrastructure can shift appropriate connection costs towards the users creating new demand.  Business Value: Greater control over connection infrastructure and flexible capacity arrangements can shorten time to power and provide large users with additional connection options. Key Deployment and Scaling Factors Define firm, time-dependent and conditional access rights, including when and how network use may be restricted.  Establish clear licensing, ownership and transfer rules for customer- or developer-built connection infrastructure.  Ensure network charges reflect the level of access to shared infrastructure, contracted backup capacity and responsibilities assumed by connecting users.  Maintain sufficient network visibility to determine when conditional capacity can be offered or restricted without compromising secure operation.  Define technical interfaces, curtailment procedures and operating responsibilities between users, generation providers and network or system operators.  Ensure participating users have sufficient operational flexibility or reliable customer-provided resources to comply with their connection conditions. Case study Ofgem (2026), Great Britain  In June 2026, Ofgem set out proposals to expand alternative connection routes for large electricity users in Great Britain, including development of an independent transmission owner license and wider opportunities to self-build high-voltage connection assets. Under the proposed approach, connecting customers could take greater responsibility for constructing and potentially owning infrastructure between their site and the existing transmission network, rather than relying solely on the incumbent transmission owner to deliver it. Ofgem is also developing arrangements that would allow customers to construct high-voltage assets and subsequently transfer them to the network company.  Ofgem cited more than 20 years of experience in Ireland, where self-build and transfer is used by the majority of connecting customers. Irish case studies cited by Ofgem found that some contestably built connections were delivered around 20% cheaper and 11 months faster. Ofgem noted, however, that whether similar benefits could be achieved in Great Britain would depend on the individual project and on constraints in the existing transmission network. National Development and Reform Commission / National Energy Administration (2026), China In May 2026, China expanded its green power direct-connection framework to allow renewable generation to supply multiple electricity users through dedicated lines and associated infrastructure. Led by the National Development and Reform Commission and National Energy Administration, the framework covers industrial parks, zero-carbon parks and other large electricity users, with priority given to emerging industries including computing facilities. Grid-connected projects retain a clearly defined physical and operational interface with the public grid, while project participants take responsibility for dedicated infrastructure, internal operating arrangements, balancing and settlement.  By June 2026, 100 green power direct-connection projects had completed approval nationwide, representing approximately 34.1 GW of renewable generation capacity. The framework illustrates an alternative connection model in which generation developers and electricity users take greater responsibility for dedicated infrastructure and internal balancing, while supporting local consumption of renewable electricity and reducing reliance on the public grid for balancing. TenneT and the Authority for Consumers and Markets (ACM) (2025), Netherlands In the Netherlands, TenneT and the Authority for Consumers and Markets (ACM) have introduced time-dependent transport rights to connect flexible users where sufficient firm grid capacity is unavailable. Under the framework approved by ACM, users connected to TenneT's national high-voltage network can use their full contracted transport right for at least 85% of the hours in a year. During the remaining hours, TenneT can restrict transport to manage network constraints. Users accepting these reduced access rights pay lower network tariffs, creating an incentive for flexible assets and loads to adapt their operation to available grid capacity. In April 2025, TenneT made 9 GW of additional capacity available for time dependent transport rights on the Dutch high-voltage grid. The regulatory framework entered into force in 2025 and has subsequently been refined based on initial implementation experience. References: Time-dependent transport rights (TDTR) | TenneTMore-affordable transmission agreements for off-peak hours promote more efficient utilization of the grid | ACM Connect Update: Demand Connections Reform | Ofgem  Demand Connections Reform – Connect Update | Ofgem  Multi-User Green Power Direct Connection | National Energy Administration of China  
Alternative large-load connection models
Office of the Gas and Electricity Markets (OFGEM), National Development and Reform Commission, TenneT, Netherlands Authority for Consumers and Markets (ACM)
Grid reinforcement options assessment embeds systematic comparison of conventional network expansion with options that can increase the capability of existing infrastructure within the planning process. Rather than treating a new line or substation as the default response to an emerging constraint, network planners assess options such as reconductoring, dynamic line ratings, power-flow control, storage, switching and other technologies alongside conventional reinforcement.  Options are evaluated using consistent criteria such as cost, reliability, transmission losses, right-of-way requirements and operational impacts. In some cases, upgrading or operating existing assets differently can increase network capacity faster or at lower cost than constructing new infrastructure.  Embedding this comparison within formal planning processes makes consideration of reinforcement options systematic rather than discretionary and provides regulators and stakeholders with greater transparency over investment decisions. The approach does not eliminate the need for new infrastructure, but helps ensure that network investment decisions reflect a consistent assessment of credible options.  Main Outcomes of the Solution Reliability & Flexibility: Enables greater use of existing network capacity and more options for managing changing power flows while maintaining reliability standards.  Affordability: Identifies opportunities to defer or avoid higher-cost infrastructure investment through better use of existing assets.  Institutional Efficiency & Transparency: Creates a systematic and transparent process for comparing reinforcement options and supporting investment decisions. Key Deployment and Scaling Factors Require credible reinforcement options to be considered systematically within network planning processes. Establish comparable cost, reliability and operational methodologies to evaluate different options on a consistent basis. Ensure sufficient network data and modeling capability to quantify the capacity, reliability and operational impacts of each option. Define transparent selection criteria so regulators and stakeholders can understand why an investment was chosen. Ensure telemetry, communications, control-system integration and cybersecurity requirements are addressed where solutions depend on real-time monitoring or active network control. Periodically reassess options as demand, generation patterns, system conditions and technology costs change. Case study Federal Energy Regulatory Commission (2024), Unites States of America In May 2024, the Federal Energy Regulatory Commission (FERC) issued Order No. 1920, reforming long-term regional transmission planning and cost allocation in the United States. The rule requires transmission providers to develop at least three distinct long-term scenarios using a planning horizon of no less than 20 years and to reassess those scenarios at least every five years. FERC subsequently issued Orders No. 1920-A in November 2024 and 1920-B in April 2025, modifying and clarifying certain requirements while retaining the long-term planning framework.  The framework requires transmission providers to consider whether four specified alternative transmission technologies – dynamic line ratings, advanced power-flow control devices, advanced conductors and transmission switching – could address regional transmission needs more efficiently or cost-effectively. This includes considering their incorporation into existing transmission facilities as an alternative to other potential transmission facilities and their incorporation into proposed regional transmission facilities. Transmission providers must also explain how these technologies are considered, increasing transparency for stakeholders.  The reform therefore embeds consideration of technologies that can increase the capability of existing infrastructure within regional transmission planning alongside conventional transmission investment. Central Electricity Authority (2024), India India’s Central Electricity Authority (CEA) incorporates different reinforcement options within its transmission planning criteria. For transmission network strengthening, the Manual on Transmission Planning Criteria requires planners to study cost, reliability, right-of-way requirements, transmission losses and downtime, including when considering upgrading and reconductoring existing lines. Where necessary, new transmission lines or substations, including adoption of a higher voltage level, may also be explored.  This framework places upgrading and reconductoring within the assessment of transmission strengthening options rather than assuming that new infrastructure is the only response to network constraints. The CEA published the Manual on Transmission Planning Criteria (with Amendment-I) 2025 in January 2025, maintaining this framework as part of India’s transmission planning criteria. References:Transmission Planning and Cost Allocation Final Rule | Federal Energy Regulatory Commission   Order No. 1920 Fact Sheet | Federal Energy Regulatory Commission  Manual on Transmission Planning Criteria (with Amendment-I) 2025 | Central Electricity Authority  
Grid reinforcement options assessment
Central Electricity Authority, Federal Energy Regulatory Commission
Performance-based utility incentives change how network companies are rewarded so that improving the use of existing infrastructure can generate financial value alongside conventional capital investment. Under traditional cost-of-service regulation, utilities can earn returns from approved network assets, which may weaken the commercial incentive to choose flexibility or other lower-capital solutions even when they reduce total system costs. Performance-based regulation addresses this by linking part of utility revenue to defined outcomes, such as efficient network operation, use of flexibility, avoided or deferred reinforcement, or measurable savings.  Regulators establish the performance measures, baseline expectations and reward or penalty mechanisms, while network companies demonstrate the outcomes they deliver. In some models, utilities retain a share of the savings created when flexibility costs less than the network investment it replaces; in others, broader performance assessments determine financial rewards for how effectively distribution companies plan and operate their networks. The approach aligns utility financial incentives more closely with system outcomes, giving network companies a commercial reason to consider flexibility and asset optimization alongside traditional reinforcement.  Main Outcomes of the Solution Reliability & Flexibility: Incentives encourage network companies to integrate flexible resources into planning and operations, increasing the range of tools available to manage constraints and changing demand while maintaining secure network operation.  Institutional Efficiency & Transparency: Defined performance measures, baselines and reporting requirements improve visibility of utility performance and support more efficient use of existing network assets. Business Value: Financial rewards for flexibility, efficient network operation and avoided investment can strengthen the utility business case for alternatives to conventional capital investment. Key Deployment and Scaling Factors Rewards need to be material and appropriately calibrated relative to the financial incentives associated with traditional capital investment. Performance measures must be measurable and attributable so regulators can verify delivered outcomes and avoid double counting. Baseline expectations, counterfactual investment assumptions and calculation methodologies need to be clear before rewards or penalties are determined. Regulatory reporting, data availability and independent assessment support transparency and accountability. Savings-sharing mechanisms can align network company and consumer interests when flexibility avoids or defers investment. Regulatory frameworks should define how performance incentives interact with cost recovery and existing revenue mechanisms to avoid unintended incentives. Case StudiesOfgem (2023-2028), Great Britain Under the Revenue = Incentives + Innovation + Outputs (RIIO) framework, Ofgem’s RIIO-ED2 electricity distribution price control for 2023–2028 includes a Distribution System Operation Output Delivery Incentive. The incentive encourages Great Britain’s distribution network operators to develop and use their networks more efficiently, including by considering flexible alternatives to network reinforcement. Performance is assessed through a stakeholder satisfaction survey and an expert performance panel, with financial rewards or penalties linked to performance.  Across the first two years of RIIO-ED2, distribution network operator groups received approximately £58.1 million (~ USD 78.3 million as of September 2026) in rewards under the incentive – £18.48 million ( ~USD 24.9 million as of September 2026) in 2023-24 and £39.62 million (~USD 53.4 million as of September 2026) in 2024-25. Ofgem’s assessment considers areas including flexibility services, forecasting, network visibility, coordination with other system actors and stakeholder engagement. By attaching financial rewards to these aspects of distribution system operation, the mechanism gives network operators a commercial incentive to improve performance beyond conventional network investment. Commission de régulation de l’énergie / Enedis (2025), France France’s energy regulator, the Commission de régulation de l’énergie (CRE), introduced a financial incentive for distribution system operator Enedis under TURPE 7, the Tarif d’utilisation des réseaux publics d’électricité (tariff for use of the public electricity networks). TURPE is the regulatory framework through which CRE sets network tariffs and associated regulatory arrangements for France’s electricity network operators. TURPE 7 covers the 2025–2028 regulatory period, with the new tariffs entering into force in August 2025.  The incentive encourages Enedis to use local flexibility where it is economically preferable to network reinforcement. Enedis applies its CritFlex methodology to determine the value of flexibility by calculating the savings it can generate relative to network investment, taking into account investment costs, additional network losses and residual impacts on quality of supply. For network areas where flexibility allows investment to be deferred, CRE awards Enedis a bonus equal to 20% of the economic gain calculated through CritFlex after deducting the costs of reserving and activating the flexibility. The remaining 80% of the economic gain accrues to network users. The incentive is calculated and reported annually and has applied since January 2025, giving Enedis a direct financial interest in using cost-effective flexibility where it can avoid or defer conventional network investment. References: Distribution System Operation Incentive Annual Report 2024–2025 | Ofgem  Changes to the Distribution System Operation Incentive Governance Document | Ofgem  TURPE 7 Distribution Tariff Decision | Commission de régulation de l’énergie  TURPE 7 HTA-BT Decision Proposal | Commission de régulation de l’énergie 
Performance-based utility incentives
Office of the Gas and Electricity Markets (OFGEM), Commission de régulation de l'énergie (CRE)
Grid-aware siting helps large electricity users identify locations where existing or planned power system capacity can accommodate their demand with less reinforcement and potentially shorter connection timelines. Network operators can publish geographically detailed information on available supply capacity, substations, voltage levels and areas where new demand may be accommodated more readily, allowing developers to incorporate grid conditions into site selection before submitting a connection request.  Governments and system planners can go further by coordinating the location of electricity-intensive activities with regional generation, network capacity and other infrastructure, guiding new demand toward areas where the power system is better positioned to serve it. This matters because identical loads can have very different system impacts depending on where they connect: locating demand near available capacity can improve utilization of existing infrastructure, while locating it behind a constraint may trigger additional network investment. Effective implementation therefore depends on sufficiently current and granular network information, coordination between electricity and spatial or industrial planning, and clear processes for translating indicative capacity into connection decisions. As electricity demand from large loads grows, location can become an important determinant of connection cost, timing and wider network requirements.  Main Outcomes of the Solution Institutional Efficiency & Transparency: Greater visibility of locational capacity helps developers and system planners make more informed siting and infrastructure decisions.  Affordability: Improved use of existing network capacity can reduce connection and reinforcement requirements.  Sustainability: Coordinating large loads with areas of abundant low-carbon generation can support greater use of clean electricity and reduce geographic mismatches between supply and demand. Key Deployment and Scaling Factors Capacity information must be current and sufficiently granular for large-load siting decisions. Network and spatial planning need to be coordinated before developers commit to locations. Published capacity should clearly distinguish indicative information from guaranteed connection availability. Generation and network availability should be considered together when guiding electricity-intensive demand. Regular updates are needed as new connections and network developments change available capacity. Case Study Japanese Transmission and Distribution Utilities (2025), Japan Japan's electricity network operators publish Welcome Zone Maps to help large electricity users identify areas where new demand may be accommodated more readily. Japan's Seventh Strategic Energy Plan identifies these maps as a means of guiding large-scale demand, including data centers, toward locations where electricity supply can begin earlier and calls for greater coordination between network operators, local authorities and other institutions in planning for large new loads.  Individual network operators provide geographically specific information. TEPCO Power Grid, for example, publishes supply headroom for demand customers at 66 kV and 154 kV, while transmission and distribution utilities across Japan provide their own Welcome Zone Maps or information on candidate areas for large-scale demand. TEPCO notes that published headroom can change as network conditions and new demand evolve and that actual connection timelines depend on factors including required reinforcement and local construction conditions. The maps therefore provide an early locational signal rather than a guarantee of connection capacity or timing. The approach gives developers greater visibility of network conditions before selecting a site while providing a mechanism for guiding new electricity-intensive investment toward locations where the network may be better positioned to accommodate it. National Development and Reform Commission (2022), China China launched its East Data, West Computing program nationally in February 2022 to coordinate the geographic development of data centers and computing capacity across regions with different resource and infrastructure conditions. Led by the National Development and Reform Commission alongside other central government bodies, the program established eight national computing hub nodes and 10 national data center clusters.  Several hubs are in western regions, including Inner Mongolia, Guizhou, Gansu and Ningxia, where energy and other resources are comparatively abundant. The program is designed to direct suitable computing activity toward these regions while considering factors including energy supply, climate, data transmission requirements and existing infrastructure. National Development and Reform Commission materials also identify increased use of renewable electricity as one rationale for greater data center development in western China.  By the end of March 2024, the 10 clusters contained more than 1.46 million standard server racks. According to China's National Data Administration, green electricity utilization at some advanced data centers had reached approximately 80%. The program demonstrates a broader form of coordinated spatial planning in which the location of electricity-intensive computing infrastructure is considered alongside energy supply, climate, connectivity and other infrastructure rather than being determined solely by where digital demand originates. References:Strategic Energy Plan | Ministry of Economy, Trade and Industry, Japan  Welcome Zone Map | TEPCO Power Grid  East Data, West Computing Project | National Development and Reform Commission  National Data Administration High-Quality Development Briefing | State Council Information Office 
Grid-aware siting and spatial planning for large loads
National Development and Reform Commission
Grid infrastructure investment trusts are pooled investment vehicles that enable utilities and infrastructure owners to bring external capital into electricity networks by transferring grid assets, or interests in the entities that own them, into a dedicated trust. The trust raises capital by issuing units to investors, giving them exposure to the cash flows generated by the underlying infrastructure without requiring them to own or operate individual assets directly. For grid owners, this creates a mechanism to monetize operational, revenue-generating transmission or distribution assets and recycle the capital released into new network investment. For investors, the structure can provide access to long-lived infrastructure assets with regulated or otherwise predictable revenues and potential regular distributions. Investment trusts can therefore broaden the pool of capital available to grids beyond traditional utility balance sheets and debt financing, including by creating a route for institutional and other long-term investors. Their effectiveness depends on an enabling regulatory framework, transparent governance, credible asset performance and sufficiently predictable cash flows. Where these conditions exist, investment trusts can separate the financing of mature infrastructure from the capital required for new development, helping grid owners redeploy scarce capital as network investment needs grow. Main Outcomes of the Solution Business Value: Grid infrastructure investment trusts can expand the pool of capital available to network infrastructure by giving institutional and other investors access to operational, revenue-generating grid assets. By monetizing mature assets, grid owners can release capital already tied up in the network and redeploy it towards new infrastructure, supporting a more scalable investment model for grid expansion.  Affordability: Recycling capital from existing assets can reduce reliance on utility balance sheets and additional borrowing to fund successive rounds of infrastructure investment. By matching operational assets with long-term investors seeking infrastructure cash flows, investment trusts can broaden financing options for grid expansion, with the potential to improve the efficiency of capital allocation.  Institutional Efficiency & Transparency: Investment trusts require clearly defined governance, cash-flow distribution and investor-protection arrangements. When supported by stable regulation and predictable network revenues, these structures can provide greater clarity over how grid assets are owned, financed and monetized, strengthening the conditions for sustained private investment. Key Deployment and Scaling Factors A clear and stable regulatory framework for investment trusts is needed to define ownership, governance, investor rights and permitted financing structures.  Suitable portfolios require operational, revenue-generating grid assets with sufficiently predictable cash flows and established performance records.  Predictable network remuneration, payment-security mechanisms and clear allocation of counterparty and operational risks are important for attracting long-term investors.  Credible sponsors and asset managers with strong operational track records can strengthen investor confidence in the vehicle and its underlying assets.  Effective scaling depends on a sufficiently large pipeline of suitable assets that can be transferred or pooled without undermining continued network operation or investment. Case study Power Grid Corporation of India (2021), India India has used Infrastructure Investment Trusts (InvITs) to bring institutional capital into operating electricity transmission assets and recycle investment into further infrastructure. In 2021, state-owned Power Grid Corporation of India (POWERGRID) launched POWERGRID Infrastructure Investment Trust (PGInvIT) as part of the government’s asset-monetisation programme. The initial portfolio comprised five operational interstate transmission projects spanning approximately 3,700 circuit kilometres of transmission lines and three substations. By transferring revenue-generating assets into a listed trust and selling units to investors, POWERGRID created a mechanism to release capital tied up in completed infrastructure while retaining a specialized structure for asset management. The model complements IndiGrid, India’s first listed power-sector InvIT, which has attracted institutional investors including KKR and Singapore’s GIC. Together, these vehicles demonstrate how mature transmission assets with predictable revenues can be packaged into investable holdings, widening access to long-term capital and creating a pathway to recycle proceeds towards continued grid investment. References: Infrastructure Investment Trusts (InvITs) Public Private Partnership Infrastructure Investment Trusts (InvITs) - Case Studies Public Private Partnership 
Grid infrastructure investment trusts
Power Grid Corporation of India

Submit your Solutions

The Innovation Playbook is a living resource which will evolve and expand over time. Public and private stakeholders are invited to submit innovative solutions for consideration for inclusion in future editions of the Playbook. 

Selected solutions will benefit from greater visibility, demonstrate impact and scalability on a trusted global platform, and help shape dialogue on the future of power systems. 

Please follow the link to submit a solution. If you would prefer to work offline before submitting, you can download a Word version of the survey here.  

Future of Power Systems

A World Economic Forum Initiative
© 2026 All rights reserved
Privacy Policy & Terms of Service