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California RE Grid Integration Initiatives: Focuses on DER and power rate designs [free access]

August 10, 2016

California is among the most active states in the US in promoting the development of renewable energy (RE) resources. As of May 2016, RE comprised a more than 25 per cent share in the state’s total energy mix. A key contributor is solar energy, with a 43 per cent share, followed by wind with a 33 per cent share, and small hydro and biofuels with a 7 per cent share each. So far, battery storage devices account for a negligible share of 0.22 per cent. The share of RE in the US’ total generation is targeted to increase to 33 per cent by 2020 and to 50 per cent by 2030, to help the country reduce its carbon emissions.

 

As the share of RE increases, several technical, economic and market- and policy-related issues associated with its grid integration are expected to arise. Integration of a larger number of RE sources introduces several changes to the grid including a portfolio of utility-scale generation, daily pattern of energy use (load) and its generation, and quantity and role of distributed energy resources (DER).

 

As per the California Public Utility Commission (CPUC), due to the adoption of various regulatory and market mechanisms, the state is currently not experiencing any reliability issues with the rising share of renewables. However, in future, issues related to ramping ability, over-generation and the need for ancillary services are likely to arise. In terms of ramping ability, an extreme daily net-load peak of 13 GW in the evening over a period of 3 hours is expected by 2020 (as depicted by the Duck Curve in Figure 1). Considering this, the state is amending existing and introducing new mechanisms for the reliable grid integration of RE projects. For this, CPUC is concentrating on various market mechanisms such as demand side management (DSM), more advanced energy storage systems, flexible DER and innovative power rate designs, instead of on more expensive options like renewable curtailment, pumped storage and transmission system strengthening.

 

RE grid integration mechanisms

California has developed several innovative mechanisms and frameworks to ensure the reliability of its power system as variable generation from RE resources increases in the state. It is also improving existing mechanisms and introducing new ones to accommodate the rising share of RE projects. These include:

 

Flexibility and grid integration in Long-Term Procurement Planning (LTPP): The LTPP framework examines grid reliability in the context of ensuring resource sufficiency for the overall system, along with examining transmission constrained (local) areas. Analysis in the LTPP incorporates several variables including forecasts of load, distributed generation, storage systems, energy efficiency, demand response, combined heat and power systems, resource retirements, as well as the flexibility of generation. Through the LTPP, the CPUC determines whether existing resources are sufficient to meet future reliability needs and thereafter approves utility plans for procuring or building new capacity over the next 10 years. To incorporate issues related to over-generation and determine power curtailment costs, a new phase of the LTPP was introduced in 2015. Under this phase, the focus is on validating the parties’ modelling results and investigating efficient solutions to maintain operational flexibility during over-generation. It is also focused on validating and improving modelling methods and standardising modelling output formats.

 

Supply-side flexibility for grid integration: Initiatives and programmes in the state aimed at providing greater supply-side flexibility are underway to ensure adequate flexible capacity, market mechanisms, regionalisation of energy markets, renewables procurement and valuation, and energy storage.

 

Flexible resource adequacy plays an important role in maintaining grid stability while dealing with fluctuating demand. Considering this, and given the rising share of RE, the state in 2014 introduced amendments to the flexible resource evaluation. Now, flexible capacity data is being collected under three categories—base flexibility, peak flexibility and super-peak flexibility. In addition, calculation of effective flexible capacity based on the ability of a resource to meet and sustain a 3-hour ramp, with various other caveats, has also been defined. The specific amount of flexible capacity to be allocated among the load serving entities (LSEs) is determined through an annual flexible capacity needs assessment conducted by CAISO and is based on the largest 3-hour ramp predicted for each month of the year.

 

In addition, CAISO has also filed a proposal with the Federal Energy Regulatory Commission (FERC) to implement the Flexible Resource Adequacy Criteria and Must-Offer Obligation (FRAC-MOO). FRAC-MOO requires that generators designated as having flexible resource adequacy should offer their flexible capacity under one of three types of must-offer obligations for flexible capacity data collection categories in the day-ahead and real-time energy market. This initiative is likely to be implemented by 2017.

 

To maintain power demand and supply balance, CAISO has implemented a regional Energy Imbalance Market (EIM) that allows the participation of other neighbouring balancing authorities in the real-time (15- and 5-minute) market as a way to share reserves and integrate renewable resources across a larger geographic region. Currently, PacifiCorp is participating in the EIM for all of its service territory. CAISO is in the planning stage to expand EIM to NV Energy, Arizona Public Service and Puget Sound Energy. However, many governance and political hurdles will need to be overcome before this integration can become a reality, and CAISO will conduct a full stakeholder and regulatory process before further implementation.

 

To maintain adequate flexibility of power supply in the short-term markets, the renewable portfolio standard (RPS) proceedings have established a least-cost best-fit (LCBF) evaluation framework to define criteria to compare the value of different renewable resources in the procurement process for investor-owned utilities (IOUs). The framework was designed to balance ratepayers’ interests in minimising the nominal cost of a renewable energy contract (least-cost) with the value that the resource can provide within the context of the system in which it will be operating (best-fit). Currently, the least-cost methodologies used by IOUs, which determine a resource’s net market value, do not fully account for the relative impact that different renewable resources may have on grid reliability. For example, it does not include grid integration costs related to the need for additional system flexibility and ancillary services at high renewables penetration. The CPUC recently began LCBF reform by adopting generic renewable integration cost adders for wind and solar resources in the utilities’ 2014 RPS Procurement Plans. Cost adders include those elements that are additional to the initial cost of the project and arise during project implementation. The integration adders reduce the net market value of wind and solar resources relative to non-variable renewable resources.

 

The methodology for determining the capacity value of a renewable resource for resource adequacy and RPS is also changing. CPUC recently released an initial proposal for the adoption of an effective load carrying capability (ELCC) methodology in the resource adequacy proceeding. Pursuant to a statutory requirement, the current method of valuing the capacity value of wind and solar resources will be replaced by an ELCC method. ELCC considers both system reliability needs and facility performance, and reflects not just the output capabilities of a facility but also the usefulness of this output in meeting overall electric system reliability needs. This will change the way that RPS resources are valued in meeting resource adequacy obligations and will help in meeting future energy needs more efficiently.

 

CPUC has also issued a proposal in the RPS proceeding recommending that the IOUs develop and standardise an ELCC methodology for their long-term resource adequacy evaluations. This will require the development of marginal ELCC values with a long-term outlook for 20 years. The proposal includes guidelines for identifying and developing common methodologies, inputs and assumptions that can be used across ELCC value calculations.

 

Storage procurement and roadmap: Assembly Bill 2514 directed CPUC to determine appropriate storage procurement targets for each LSE and to consider policies to encourage deployment of energy storage. CPUC decisions implementing this bill created a storage framework and established a target for each LSE to procure viable and cost-effective thermal energy storage. These targets total 1.33 GW across three grid domains: transmission, distribution and customer-side, during four biennial procurement periods or cycles, staring from December 2014. Currently, the first storage procurement cycle (2014-2016) is underway, which includes 16 MW of storage capacity to be procured by San Diego Gas & Electric Company (SDG&E), 80.5 MW by Pacific Gas and Electric Company (PG&E) and 16.3 MW by Southern California Edison (SCE). Under the storage procurement cycle, the participants procure cost-effective power storage capacity. Through active proceedings, storage policies are being refined and programme details are being developed to consider how storage can contribute to flexible needs for grid integration.

 

Recently, CAISO, in collaboration with CPUC and California Energy Commission (CEC), announced its Vehicle-Grid Integration (VGI) Roadmap for mapping a way to develop solutions that enable electric vehicles to provide grid services while meeting consumer driving needs. Under this, they plan to determine the value of VGI in terms of its cost and other benefits, and the regulatory and technological support required for its widespread adoption.

 

Distributed Energy Resources (DERs): This is part of CAISO’s efforts to integrate, optimise and interconnect DERs. CAISO recently created the DER Provider (DERP) participants’ category in the wholesale market. This category allows for aggregation of DER sub-resources and streamlined metering and telemetry requirements. It was created in part because CAISO’s current tariff does not offer a clear platform for smaller (i.e. < 0.5 MW) resources to participate in CAISO energy and ancillary services markets.

 

This move also helps the small- and medium-sized solar rooftop projects, developing rapidly under the California Solar Initiative (CSI). As a result of the initiative, small- and medium-sized solar projects grew at a compound annual growth rate (CAGR) of 39 per cent during 2007-15. This increase is expected in the coming years as well, due to the project’s cost effectiveness for the customer and third-party solar lease providers. Nearly all of this rooftop solar is considered by the CPUC, CEC and CAISO for load modification while a smaller percentage of solar rooftop is considered to demonstrate RPS compliance via the issuance of renewable energy credits. The CEC demand forecast predicts that customer-side demand distributed generation will reduce peak load by more than 4,400 MW by 2024 (nearly triple the capacity installed in 2012). This is significant, but the actual expected rate of continued growth in this sector is difficult to predict, as it is dependent upon many factors, such as tax policies set by the federal government and the future of net energy metering.

 

DER flexibility for grid integration: Various statewide proceedings, initiatives and programmes are in place to support energy resource measures at the distribution level (i.e. not directly interconnected to the transmission grid). These include time-of-use (ToU) and dynamic rates, which play an important role in assisting grid integration due to their ability to effectively align power loads with RE generation. As per CPUC analysis, dynamic rates, which involve smaller time intervals along with properly grid-aligned ToU periods, can help in shifting peak load demand, incentivising energy consumption during low-demand periods to minimise over-generation, and reducing the need for flexible capacity resources. Cost-based ToU rates may also be a factor in incentivising solar customers to co-install storage. The existing commercial ToU rates are not designed around integrating renewables. In July 2015, CPUC adopted a residential ToU pricing, mainly for rooftop or decentralised renewable energy projects. CPUC plans to roll out default residential ToU rates by 2019. For the successful implementation of these mechanisms, CPCU has planned to adopt a net energy metering system by July 2017.

 

 

Power system dispatch and control: Several innovations and processes introduced in power system dispatch and control have increased the ability of California’s power system to integrate variable renewables. Two of them are day-ahead renewables output forecasting, and grid reliability calculations and dispatch process. California’s power control and market operations have also evolved an advanced system for balance management and grid reliability. CAISO’s power control centre makes an updated forecast every 5 minutes for the upcoming 5-minute period.                                                                                                                                                                                                                                                                                                                                

Figure 1: CAISO’s Duck Curve: Net load prediction through 2020

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Note: The Duck Curve shows the drop in net load with high solar generation during the afternoon and the steep rise in net load with the reduction in solar energy.

Source: CAISO, 2013, ‘What the Duck Curve Tells Us about Managing a Green Grid’.

 

Towards a long-term vision

Recently, CPUC published a white paper to create a long-term action plan for RE grid integration. Developing a long-term vision for grid integration policy will depend upon the experience and findings from the short-term approaches adopted by CPUC and CAISO. A balanced mix of DERs and supply-side resources are required to create responsive power loads. Along with demand response products, programmes, rules and appropriate accounting mechanisms, energy efficiency goals should be re-designed to focus on reducing load during new net peaks based on the future solar supply and net load curves to save power during specific times of day and seasons.

 

There is a need to enhance CPUC policies and CAISO market structures to deal with the issues affecting the development of demand response systems. CPUC should also take other near-term steps to enhance demand response programmes, including accounting for locational values that could contribute to grid integration; providing policy guidance to the IOUs for demand response portfolios; and developing flexible demand response resources that can integrate into wholesale markets.

 

Further, incentives should be developed to promote energy storage mechanisms. For instance, technical characteristics, and the scheduling, dispatch and control system of distributed generation and storage systems should be aligned with grid needs. This alignment happens through a combination of incentives, rate design (including ToU, dynamic rates and net energy metering) and new contractual arrangements between generation and storage owners, IOUs, aggregators and local market participants.

 

So far, energy storage has been considered to be a reliable source to provide energy whenever needed. However, CPUC should holistically consider whether storage procurement would be a cost-effective way to procure flexibility, relative to other identified solutions, and which types of storage can provide needed flexibility characteristics.

 

CPUC should continue to review data provided by CAISO and produce analyses of negative pricing events and economic curtailments. The agencies should work together to create a common understanding of the ways to enhance the reliability and effectiveness of their initiatives.

 

Net net, the state is working continuously to maintain grid stability while increasing the share of RE resources in California’s total energy mix. As the majority of the above-mentioned mechanisms are in the very early stages of development, it will take time to determine their actual impact and effectiveness. Going forward, all stakeholders will be required to work closely to ensure the effective implementation and functioning of these mechanisms.