IEA (2022), Advancing Decarbonisation through Clean Electricity Procurement, IEA, Paris https://www.iea.org/reports/advancing-decarbonisation-through-clean-electricity-procurement, License: CC BY 4.0
An increasing number of companies are looking to ensure – and show – that they are trying to help mitigate climate change and contribute to clean energy transitions. At the same time, more and more consumers want to choose products and services compatible with sustainable development. In this context, almost 1 000 companies across different activity sectors have pledged some form of emissions reduction or climate neutrality goals. To achieve these goals, many companies have started defining targets to reduce or eliminate emissions arising from their electricity consumption by procuring electricity from clean sources.
This report aims to support consumers of all sizes in choosing impactful ways to procure clean electricity. To this end, it provides guidance not only to companies but also to key stakeholder groups – policy makers, regulators, and system and network operators.
Our analysis shows that the way clean electricity goals are specified influences how clean energy procurement impacts power systems and actual emissions reduction. At present, most corporate clean electricity procurement is guided by accounting practices set out in the Greenhouse Gas Protocol. This guidance allows companies to apply an emissions factor of zero to their electricity consumption in their greenhouse gas (GHG) emissions accounting by matching their demand with the purchase of clean generation on an annual basis, e.g. under the Renewable Energy 100 (RE100) initiative.
Emissions reduction goals based on annual electricity matching have underpinned the large rise in procurement activity in the last decade and can continue to drive increasing deployment of clean generation, particularly solar and wind, for power systems in earlier phases of renewables integration. More recently, strategies that focus directly on emissions impacts and prioritise the most cost-effective emissions abatement are also gaining attention.
However, goals based on annual matching of electricity or only targeting emissions do not deliver all the technologies that will be needed as power systems decarbonise and reach higher renewables integration phases. Thus, companies seeking to lead net zero transitions are developing other strategies. One alternative aims to match the corporate demand profile on an hourly basis (or less) with demand and generation both located within the same grid. This approach delivers more robust emissions reduction in high-renewables systems and drives deployment of a more diverse and flexible portfolio of clean technologies and solutions.
The type of procurement that corporates undertake to meet their goals also influences emissions reduction outcomes. Depending on the market, a number of options for clean electricity procurement are available:
- On-site or “behind-the-meter” (BTM) generation, in which corporates invest in clean electricity generation to meet their own demand.
- Energy attribute certificates (EACs), which are tradeable credits that can include attributes such as type and time of generation. Examples include Renewable Energy Certificates (RECs) in the United States and Guarantees of Origin (GOs) in Europe, or the emerging, more granular, time-dependent energy attribute certificates (T-EACs).
- Power purchase agreements (PPAs), which are long-term contracts between a consumer and an electricity producer. The contracts can be physical (including actual delivery of electricity to the consumer) or financial (as a price hedging instrument).
- Green power products or green tariffs through which the corporate procures clean electricity from a utility or a clean electricity supplier.
This portfolio of clean electricity procurement options gives corporates flexibility to choose one that fits their needs and capabilities. However, there is a need to consider whether clean electricity procurement directly contributes to increased clean generation beyond what would be achieved through existing public policy targets and measures. This is referred to as “additionality”, and is easier to demonstrate for some forms of procurement, such as BTM generation or a PPA for a new plant.
To date, EAC schemes have been the dominant option for corporate procurement. The uptake of PPAs has risen sharply in the last decade as corporates seek to maximise the visibility and additionality of their procurement efforts.
The extent of electricity industry liberalisation has an important influence on the possibilities for clean electricity procurement. Some power market structures allow for a great diversity of procurement options; others are more restricted. Green power products, for example, are technically possible within most electricity market structures while PPAs between generators and consumers typically require a greater degree of liberalisation.
Across all types of power markets, whether fully integrated or fully liberalised, policy makers can take specific actions to foster the development of clean energy procurement. Introducing a licensing process that grants access to the electricity network and specifies which actors can interact with the incumbent utility can be important first steps (as shown in India, Indonesia and South Africa). In parallel, policy makers and regulators need to establish clear and transparent processes for cost calculations and allocate responsibilities to ensure developers and consumers are able to place trust in the market.
While the available mechanisms to enable clean electricity offerings to customers will vary from one power system to the next, policy makers, regulators and utilities should take action to maximise the accessibility of clean electricity procurement options. For large consumers, liberalisation of generation and allowing consumers to choose their electricity provider can stimulate the emergence of corporate PPAs, EAC schemes and green tariffs through retailers. For small consumers, policy makers can enable procurement by requiring utilities to develop green power products and letting consumers choose among clean energy suppliers.
As noted above, ensuring that corporate procurement makes a real contribution to deploying more clean generation (also referred to as additionality) is vital – from both policy and corporate perspectives. To truly accelerate clean energy transitions, the most critical requirement is that voluntary procurement actually goes beyond existing government mandates and initiatives. If this criterion is met, all corporate clean electricity goals and all types of procurement can contribute to accelerating energy transitions. This can also add robustness to corporate claims of decarbonisation.
For certificate schemes, this requires careful design to ensure that accounting and reporting mechanisms are compatible with government clean electricity targets and mandates. This implies the need for clear guidelines as to what should be reported as part of the country’s own policy-driven process and what is driven by individual corporate initiatives, as well as mechanisms to avoid different types of double counting. This applies within clean electricity tracking and to the interaction between certificates and carbon credits. It is critical to avoid, for example, double issuance in which both a clean electricity certificate and a carbon credit are created for the same unit of generation and subsequently claimed by two separate actors.
Annual matching goals, which focus on electricity and tend to be satisfied by variable renewable technologies, create a set of specific challenges. Companies using these strategies still rely on services that other generators provide – e.g. supplying capacity adequacy, balancing and stability, as well as use of the grid. This may imply costs for other actors providing them, such as generators and system and network operators, which must be recovered through consumer billing structures. If such costs are not allocated explicitly, the total costs may end up, by default, being passed to other grid users in an unfair manner. Alternatively, the system operator may have no mechanism to recover them and face solvency issues.
Regulators play a major role in ensuring a clear allocation of costs that support system operations and decarbonisation, and should therefore develop clear mechanisms to evaluate and allocate them. In systems where renewables deployment requires policy support, regulators should design remuneration mechanisms in a way that ensures that all parties contribute to reducing the impact on overall system costs and allow system operators to cover additional costs efficiently. A key consideration is that such mechanisms ensure support for clean electricity deployment without inadvertently passing costs to vulnerable consumers. Mechanisms should also recognise the contribution that flexible technologies provide to the system.
We illustrate this in an IEA modelling case study for India and Indonesia in 2030 in which we evaluate system impacts for corporate generation based on different clean electricity goals. The modelling evaluates system costs and value in relation to impacts on fuel costs, operating costs (including startups and ramping), and estimated peak contribution. We find that the system value of annual matching portfolios is substantially below the cost to serve the corporate load with standard grid supply. In contrast, hourly matching portfolios bring a much higher value, which may even exceed the costs for serving the corporate load.
Clean electricity goals based on matching clean generation to corporate demand on an annual basis have played an important role so far, driving procurement of clean electricity mainly from solar and wind. These goals continue to provide value across the world in systems where the priority is adding clean electricity, particularly from variable renewables.
Achieving net zero power sector transitions, however, will ultimately require a broader range of clean, flexible electricity supply and service options. Corporates can take the lead in accelerating decarbonisation by setting more ambitious goals that can stimulate deployment for the full portfolio of clean dispatchable technologies. IEA modelling for India and Indonesia shows that hourly matching strategies (as compared to annual) lead to a more diverse technology portfolio, including clean dispatchable generation and storage.
Hourly matching strategies imply corporate generation closely matching corporate demand profiles. In principle, this does not consider the overall demand profile of the entire system. Such an approach could lead to investment decisions that overlook the fact that large, interconnected power systems benefit from increased efficiency by aggregating load and sharing generation resources.
To avoid the risk of inefficient investment, all procurement strategies should allow for interaction between the corporate generation and the power system, which includes exporting surplus generation to the rest of the system and utilising system services. One option to achieve this for hourly strategies is targeting hourly matching at less than 100% in each hour. Relative to annual matching strategies, this approach stimulates a much more diverse and flexible portfolio and provides a greater contribution to system services. In this case, the corporate remains dependent on the main system for peaking requirements and some balancing services, which helps to avoid inefficient overbuilding of the system.
Trading of time-based certificates (T-EACs) can also allow corporates to pursue hourly matching in a more cost-effective manner. Certificate trading allows corporates to trade surplus clean generation in specific hours, which effectively allows for aggregation of generation to meet different demand profiles. In this case, it is essential to assess additionality and ensure the certificates for meeting 24/7 goals do not come from existing generation without increasing flexible supply. IEA modelling for India and Indonesia shows that, relative to an isolated dispatch matched to the company load profile, optimised dispatch of hourly matching portfolios reduces both system costs and emissions.
While reducing carbon emissions is an important objective of clean electricity procurement strategies, existing frameworks fail to fully consider all aspects that affect emissions. In particular, accounting frameworks based on matching electricity demand and supply on an annual basis create a risk of discrepancies between attributed and actual emissions reduction. While relatively fit-for-purpose in many power systems today, as power systems reach higher phases of renewables integration, these approaches will increasingly fall short. IEA modelling for India shows that corporate procurement based on annual electricity matching reduces company emissions by 96% in 2020. However, as the share of renewables in the electricity mix increases, the same approach delivers only 89% emissions reduction by 2030 in the Sustainable Development Scenario. In a case with the share of variable renewables reaching 50%, the emissions reduction value falls to around 50%, reflecting increased curtailment of renewables in the rest of the system and the corporate generation mostly displacing gas (rather than coal) during hours of surplus.
Current accounting practices for average annual emissions do not account for these effects. As such, under an annual average approach, all of these cases would appear to achieve 100% emissions reduction, while the actual impact of the interventions may be much lower. Such approaches may remain the most appropriate for attributing emissions across the entire system; however, they do not provide good guidance for the most impactful procurement decisions.
Hourly average approaches can provide better information about the time at which demand response and clean generation bring the most value to the system. Even so, they do not accurately capture how changes in load and generation actually impact emissions. Marginal impact methodologies that include a long-term perspective provide the most accurate way to understand the actual impacts of various interventions on the power sector. Such approaches are challenging to adopt as they require greater availability of data; power system modelling is required to determine most accurately the most effective deployment of clean electricity and demand response. Nonetheless, use of such methodologies should be increased wherever possible. Policy makers can support this by ensuring increased data availability and including guidance on optimal pathways for system development within planning studies.