LESS CARBON MEANS MORE FLEXIBILITY: RECOGNIZING THE RISE OF NEW RESOURCES IN THE ELECTRICITY MIX

Renewables such as wind and solar now account for the majority share of new electricity generation capacity being built globally. Though still dwarfed in the generating fleet by more traditional generation options such as coal, gas, and nuclear power, intermittent resources have risen dramatically, first aided by supportive policies, technology advances, and consumer preferences but now driven more by economics. This has resulted in a growth of the contribution of renewable generation in the United States. As of year-end 2017, approximately 17 % of electricity in the United States was generated by renewables (including hydropower). Through March 2018, renewables accounted for about 21 % of all electric generating capacity. The European Union is even farther ahead of the United States: in 2017, approximately 30 % of the EU’s electricity was generated by renewable energy sources.

The rise of renewables is expected to continue, at least for the next few years. Policy makers in the European Union have set high and aspirational decarbonization goals: by 2030, cut greenhouse-gas emissions by 40 % compared to a 1990 baseline. Germany’s coalition government agreement set a new 65 % target for renewable penetration by 2030. France is aiming for a 40 % share of renewables in electricity production.

Renewable

Beyond policy goals, the growth of renewables is supported by their improving cost outlook. According to Lazard’s year-end 2017 estimate, leveled cost of energy (LCOE) for utility-scale renewable electricity continues to fall, averaging $45 per megawatt-hour (MWh) for unsubsidized wind power and $45 to $50 per MWh for utility-scale solar, compared to approximately $60 per MWh for combined-cycle natural gas.

In several geographies, solar and wind are already competitive with other sources of generation based on LCOE, even without tax or production subsidies. In LCOE terms, these resources are expected to be the cheapest source of electricity within the next decade.

However, LCOE metrics ignore one important consideration. Renewable generation is intermittent and frequently unpredictable. Furthermore, the uneven geographic distribution of wind and solar potential is likely to stress the grid in some locations, leading to transmission and distribution constraints.

These low-cost, renewable kilowatt-hours come with intermittency, volatility, and grid-integration costs, creating new grid-planning requirements for backup capacity and ramping. New types of electricity services, beyond the traditional energy and four-to-six-hour capacity requirements, can be fostered to manage these intrinsic characteristics of clean-generation technologies. Those services are flexibility and resiliency.

Some electricity markets, such as the California Independent System Operator (CAISO), Germany, and the United Kingdom, have started to recognize, to varying degrees, flexible and resilient electric resources. And policy makers at the Federal Energy Regulatory Commission (FERC) and the PJM Interconnection are shifting focus, in the United States at least, to the role that battery energy storage and flexible resources like distributed resource aggregators (DRA) could play as electricity markets evolve.

We believe significant steps can be taken toward decarbonizing the electricity supply through thoughtful, concerted action, as we discuss below.

High renewable penetration can cause several issues in the operation of the grid that can vary by geography, depending on, among other things, the mix of renewable-energy sources (solar versus wind), the availability of transmission and distribution (T&D) capacity, the fleet of nonrenewable generating stations, and the shape of electricity demand. There is no universal, one-size-fits-all solution to integrating ever-greater amounts of renewable generation into the grid. What works in Philadelphia may not work in Portland or Phoenix.

Heading off current and future challenges is not simply a matter of tinkering at the margins with market rules or mandating a set level of electricity-storage projects. Holistic solutions that encompass supply, demand, regulation, and market structure are needed. Storage could be part of the solution, as could supply-side resources, customer programs, and regulatory leadership. The solutions could also recognize that different resources provide different services and thus a differentiated set of market products and customer programs will likely deliver a lower cost solution.

Operating electric grids with high penetration of intermittent resources poses unique challenges for utilities and grid operators. While not limited to California, that state’s much discussed “duck curve” illustrates one of the difficulties managing a grid with a high percentage of renewable generation, which sometimes is dispatched at zero or even negative variable cost, resulting in displacement of other resources which may be needed to manage flexibility.

Enter the age of new resources

New challenges require new thinking. The market has a set of traditional options for responding to the ramp-down of intermittent resources, but in a decarbonized future, those traditional options are increasingly misaligned with overarching policy goals.

For example, one traditional response to falling output from intermittent generation is to ramp up gas-fired generators. But that practice comes with a cost to customers and to the policy goal of decarbonizing.

Today, at prices of $320 to $410 per installed kilowatt-hour for a five-hour lithium-ion battery, energy storage is currently significantly more expensive than curtailing renewables. However, with projected cost declines in the approximately 70 % range by 2030; lithium-ion battery storage has the potential to be a competitive option for avoiding curtailments through time shifting.

The role of storage already is being recognized by policy makers in jurisdictions with high penetration of renewable generation. Following the California Public Utility Commission’s 1.3 gigawatt (GW) storage target in 2013 (supplemented with an additional 0.5 GW target in 2017), several states set aggressive storage goals: Massachusetts has a 200 MW target by 2020, New Jersey recently announced a 600 MW goal by 2021 (and 2,000 MW by 2030), and New York has defined a road map to 1,500 MW by 2025. Responses to recent requests for proposal for renewable projects often come bundled with storage. Even conventional generation is looking at co-located storage to optimize dispatch to improve economics and performance of traditional natural gas, coal, and nuclear units.

Battery storage is new and interesting for the same reason other advanced technologies driving change in the electricity business cloud computing, big data analytics, and two way digital meters are exciting: they uncover new value-creation opportunities. Value stacking, the ability to combine multiple use cases for storage, is beginning to pencil out. Storage is being used to defer investments in the T&D systems of some utilities. Storage also can be used to get around system constraints: battery storage projects kept the lights on in Southern California when the Alison Canyon gas-storage facility was closed.

Distributed energy resources (DERs) have made their mark on utility integrated resource plans (IRPs). Coming right behind DERs are DRAs, an emerging resource category too often overlooked in the United States. Aggregation pilots are taking place across the country, with companies like Stem and Advanced Microgrid Solutions working on DER aggregation projects. Distributed energy resource management systems (DERMS) are being adopted from leading utilities across the world, as tools to monitor, oversee, and even help control DERs offering services to the grid. As the landscape of DERMS providers matures, the capabilities of these systems will extend to active, real time dispatch and measurement of DER assets, further facilitating the role of DRAs.

Though DRAs are still early in the adoption cycle, regulators are starting to realize the value this category of resources could bring as the electricity business evolves into a decentralized basis from a centralized, generation centric basis.

We see a future where DRAs operate in energy and capacity markets in regional transmission organizations (RTOs) and independent system operators (ISOs). As customer charges evolve to include the cost of flexibility, a new class of services emerges for energy assets that can respond at the right time and the right location in the grid.

The role of the customer also is evolving as large commercial and industrial enterprises explore ways to use their energy assets beyond offsetting volumetric charges and toward providing grid-flexibility services. Automated control of customer load, inclusive of customer incentives and customer acquisition, can be a cost-competitive source of load-shifting flexibility even today, frequently cheaper than the generation alternative.