Power sector planning exercises help steer investments in the power system, while also promoting affordability and reliability. 

In recent years, the shift to decarbonized, decentralised, and digitalized power systems has increased exposure to cybersecurity risks and extreme weather events, naturally raising concerns about energy security. The lack of system flexibility in particular has become a more prominent concern with the rising share of VRE and distributed energy resources, simultaneous with a phase-out of thermal plants. Long-term energy planning should be supported by proper adequacy assessments to highlight anticipated shortages of flexibility, and find market-based instruments to address these.

Historically, system adequacy was assessed by reviewing a reserve margin in supply capacity (installed supply capacity minus peak load). With the advent of VRE and other flexible sources, this reserve margin has had to be reviewed.

For example, in many countries installed PV capacity has not been considered (as it provides no contribution to evening peak load), wind is considered to have a low contribution factor (about 10% of installed capacity), and simple corrections needed to be made for load reduction and interconnection capacity. With higher shares of VRE, and when systems become more interconnected, new adequacy assessments are needed based on detailed system modelling to identify loss-of-load expectations. European mid-term adequacy forecasts of recent years based on probabilistic analyses provide good practice methodologies for other regions.

Taking issues associated with VRE into consideration in long-term energy planning allows for appropriate investment decisions to be made on flexible resources in respect of both generation and grid infrastructure.

Increasingly, power system planning exercises are incorporating assessments of flexibility requirements and integrating across power market segments (e.g. considering both generation and transmission investment together) and economic sectors (e.g. distribution network and transportation plans to deploy charging infrastructure). Such integrated approaches can help to uncover smart solutions, but policy makers may need to intervene to encourage these kinds of approaches in an unbundled system.

In some countries and regions, such as India and Texas, mitigating electricity network connection risk has been identified as a priority to drive down both VRE contract prices and reduce flexibility requirements resulting from new VRE installations.

For example, India’s Ministry of New and Renewable Energy has introduced a solar park policy which will contribute to achieving the target of installing 100 GW of additional solar generation by 2022. Rate payer-funded transmission lines are being built to connect these solar parks, providing connection infrastructure for new VRE projects. The policy has attracted investors by removing obstacles to transmission connection, including risks related to permitting and rights of way. By looking at the weighted average tariffs awarded for projects within different solar parks under the policy between 2015 and 2017, it’s clear that costs have been trending down over time.

The deployment of renewable resources can often outpace network development. Network development will need to anticipate where renewables are likely to be built, while policy makers and regulators will need to explicitly link incentives for new transmission lines to other policies that support investment in renewables.

For example, Competitive Renewable Energy Zones were created in Texas as a proactive means of alleviating grid congestion by designating renewable sources in suitable areas of the grid. This responds to the fact that the lead time for transmission infrastructure expansion is substantially longer than construction time for wind parks. By taking a proactive role in coordinating infrastructure and generation projects, policy makers can accelerate VRE integration while reducing overall costs.

Sector coupling can promote economy-wide decarbonisation and broader macro-economic efficiency. It is defined as the intelligent linkage between the power sector and other energy-consuming sectors (e.g. industry, mobility and buildings), often through advanced sensing, communication and control technologies, that can flexibly use demand to integrate VRE and lower power system operational costs.

Sector coupling can significantly reduce primary energy demand, through efficiencies and fuel switching, and enable flexibility in the demand-side of the power system, while also supporting power sector revenue sufficiency through electrification efforts.

To ensure proper co-ordination of all components in the power system, a set of rules and specifications – a “grid code” – should be developed and adhered to by all stakeholders in the power sector. Grid codes cover many aspects, including connection codes, operating codes, planning codes and market codes.

Grid codes are particularly relevant for wind and solar PV plants because they are technically very different from traditional generators. During the initial phases of VRE, its impact on the system is minimal and its influence on grid stability could easily be managed.

As the share of VRE displacing conventional generation increases, so the need grows for VRE to contribute to providing grid support services, such as frequency regulation and active power control, reactive power and voltage control, and operating reserves. As a result, more stringent and precise technical requirements are required from VRE plants connected to the grid.

A number of jurisdictions around the world have already enabled the provision of system services from new system resources through technical and operational requirements embedded in grid codes.

In some cases, accommodating new power flows arising from increased deployment of VRE and increased loads may require the reinforcement of the distribution network. Such investments can be substituted or deferred through the strategic deployment of distributed energy resources.

The deployment of aggregated distributed energy resources to provide localised flexibility services, however, would generally be classified as an operational expenditure (OPEX) – not typically considered in determining the revenue allowance of regulated utilities. This may lead utilities to prioritise traditional network investments, even in scenarios where the procurement of flexibility services from distributed energy resources could help to defer or avoid investments in networks.

In this case, specific regulatory measures may be introduced to reorient utility incentives. One approach to addressing this issue is to remove the distinction between CAPEX and OPEX when examining utilities. For example, the UK regulator, Ofgem, has mandated a transition toward a total expenditure framework (TOTEX), which grants utilities a single expenditure allowance for maintaining network infrastructure.

Another approach is for policy makers to mandate consideration of innovative distributed energy resource solutions during utility planning exercises as an alternative to traditional network investment, as is happening increasingly in Australia and the United States, among others.

For example, New York’s Public Service Commission introduced a shared savings provision to encourage the deployment of so-called “non-wire alternatives”, requiring distribution utilities to consider distributed energy resource solutions as alternatives to traditional network upgrades.

One emerging tool for network operators is the introduction of “flexible connections”, which provide financial incentives for the ability to curtail output or demand to prevent network constraints. Flexible connections can be used for both large-scale VRE as well as to manage the loads of distributed energy resources.

For example, in 2018 distribution networks in Great Britain’s power system relied on close to 7.5GW of flexible connections through both Active Network Management and Operational tripping schemes.