Navigant Research Blog

The US ITC Was Reinstated for Fuel Cells: Is It Enough to Recharge the Industry?

— March 20, 2018

In an 11th hour move, the US federal Investment Tax Credit (ITC) was reinstated for certain orphaned generating technologies in February’s congressional tax bill. Among the technologies extended, fuel cells have the highest incentive: as much as 30% of the system cost can be taken as a tax credit. For stationary systems made by the likes of Bloom Energy, Fuel Cell Energy, and Doosan, the credit can be worth around $0.02/kWh on a levelized cost basis—a significant amount that can decide whether a project gets built.

Will it be enough to reignite an industry that largely treaded water in the US in 2017? That depends on whether industry players can address certain key issues.

Capital Costs Must Be Lowered

The high capital costs of fuel cells remain the biggest hurdle to mass adoption. Installed capital costs vary widely but typically range from about $4,000/kW to $8,000/kW. By contrast, turbines, microturbines, and reciprocating gensets are significantly cheaper per kilowatt—as low as $1,000 or less for certain gensets and turbines. Fuel cells make up for this with high efficiency, but that advantage is hobbled in a world of low natural gas prices. Cost declines in recent years have been promising, but more must be done. Incentive certainty should help drive investment, volume, and thus economies of scale, but more must be done with manufacturing process improvement and the use of lower cost assemblies and materials.

Flexibility and Load Following Must Be Improved

The US electrical grid is experiencing increasing volatility thanks in part to fast growth among intermittent renewables. This has led to demand for flexible, dispatchable technologies like battery storage. The higher temperature fuel cells popular in the +500 kW range tend not to follow load well. This is a disadvantage, especially for applications like microgrids that value islanding from the grid. Pairing the fuel cell with battery storage (a la Bloom Energy) can help overcome this lack of flexibility

Carbon Emissions Still Represent a Liability

Despite super-low levels of criteria pollutant emissions, fuel cells using natural gas still emit carbon dioxide. This can be a significant liability when compared with, for example, the emissions-free PV-plus-storage systems that continue to fall in price. Though fuel cell emissions per megawatt-hour tend to be lower than most electrical grids right now, those grids are focused on decarbonizing. This is of special interest among corporate buyers thinking increasingly about sustainability. Low carbon fuels like biogas are a key decarbonizing pathway. Some programs, like California’s SGIP, encourage biogas market transformation by requiring increasing amounts of biogas in covered systems. Using biogas as a fuel is a strategy for fuel cells to compete better on system carbon emissions.

Fuel Cell Technology Needs More than Just the ITC

The reinstatement of the ITC gives a welcome boost to the stationary fuel cell industry in the US. It lowers both uncertainty and costs to the end user, and enhances economies of scale. But more yet is needed to truly scale the industry. Cost cuts have been aggressive in recent years but must continue. The ITC is scheduled to phase out over 5 years, dropping to 22% before ending in 2022, giving fuel cell companies a clear timeline for hitting lower cost targets. Pairing up with other dispatchable technologies like batteries may help fill the gaps in load following capability. And to limit carbon emissions, alternative fuels like biogas and green hydrogen will become increasingly important fuels. Fuel cell technology still shows great promise, but there is much yet to be done.

 

Innovative Residential Solar PV Offering Designed to Increase Customer Retention

— March 13, 2018

In July 2017, I highlighted how innovative UK residential solar PV plus energy storage products were being brought to the residential marketplace. These kinds of new, customer-focused solutions are at the heart of Navigant Research’s new Utility Customer Solutions Research Service, which is focused on new solutions and business models for utilities and technology companies to meet new utility customer expectations.

Residential utility customers in Texas are now seeing another innovative business model being rolled out to take advantage of Electric Reliability Council of Texas’ power market rules and intense solar irradiance. This new Texas solar business model will be featured, among others, in my upcoming Navigant Research report, Maximizing the Residential Energy Customer Experience with Emerging Solutions.

The Texas model is an example of how the emergence of distributed energy resources and software innovation can come together to meet customer needs. Navigant Research envisions that these types of business model innovations will become more common to meet the needs of the utility residential customers of the future.

A New Model for Consumer Agreements

Sunrun and Think Energy, Engie’s retail choice electricity and energy services provider in the US, have partnered to offer a unique financed residential solar PV product. Due to local grid rules, there are no consistent solar PV net-metering policies to reimburse customers or solar PV asset owners for excess solar PV power provided to the grid. However, Sunrun and Think Energy created a virtual net-metering credit that residential property owners can apply toward their electricity bill for exported power. This new model allows Sunrun and Think Energy to save the customer money while engaging with a customer for a long-term, 20-year solar PPA agreement, rather than the typical short-term retail choice electricity procurement contract.

Traditional retail electricity choice sales in deregulated electricity markets has increasingly become more like non-energy e-commerce transactions. Many e-commerce transactions with high customer acquisitions have well-documented challenges to remain profitable. Think Energy is partnering to save customers money by going solar with no out of pocket expenditures while reducing its own customer acquisition by keeping the customers it has under a long-term agreement. Sounds like a winning approach across the board.

 

FERC’s New Storage Order Signals Focus on Flexibility and Resource Diversity to Improve Resiliency

— February 27, 2018

After over 1 year of speculation and uncertainty, one of the most significant regulatory developments in the energy storage industry was announced last week by the US Federal Energy Regulatory Commission (FERC). In Order 841, FERC aims to remove barriers to the participation of energy storage resources in capacity, energy, and ancillary service markets operated by the country’s regional transmission organizations (RTOs) and independent system operators (ISOs).

With this order, FERC has affirmed its agreement with much of the industry that improving the resiliency of the power grid will come from maximizing its ability to rapidly respond to changing conditions utilizing a diverse range of flexible and increasingly distributed resources. Order 841 directs RTOs and ISOs to devise new tariffs and market structures for energy storage participation.

Five Key Requirements of the Order and Likely Implications

  • Storage must be “eligible to provide all capacity, energy, and ancillary services that it is technically capable of providing.” This requirement makes clear that FERC will require technology agnostic markets without restrictions on what systems can provide which services.
  • Storage “can be dispatched and can set wholesale market clearing prices as both a wholesale seller and wholesale buyer consistent with rules that govern the conditions under which resource can set wholesale prices.” Again, FERC clarifies that equal treatment for storage alongside other technologies must occur.
  • Market structures must “account for the physical and operational characteristics of electric storage resources through bidding parameters and other means.” FERC sets the stage for storage to be considered as a unique resource that may require restrictions or market mechanisms to address its limited duration and operating parameters.
  • The “sale of electric energy from the RTO or ISO market to an electric storage resource that the resource then resells back to those markets must be at the wholesale locational marginal price” clarifies a long-standing issue in the industry. When charging for discharge, energy storage systems will not be required to purchase energy when charging at retail rates, and the value of storage will be determined based on local power market prices. The issue of how energy storage system auxiliary power is charged will remain up to the RTO/ISOs, which could affect storage with high thermal cooling loads.
  • The minimum size threshold for the market participation of an energy storage system is 100 kW, which is a major win for distributed energy storage systems that now have clarity to provide services at the wholesale level. The minimum size threshold does not distinguish between front-of-the-meter/customer-sited, or behind-the-meter storage. While behind-the-meter energy storage needs to have capacity injection rights to be compliant with the order, the minimum size threshold appears to be a positive development for distributed energy storage on both sides of the meter.

Who Has the Final Say?

The country’s ISOs and RTOs now have 9 months to file new tariffs, and another year to fully implement the new rules. However, some specifics are left to the interpretation of each system operator, such as pricing for services, and the scheduling requirements for storage systems looking to provide ancillary services alongside other services. Perhaps the most significant effect of this ruling is the FERC’s recognition of the tremendous value that energy storage can provide to the grid to improve resiliency, efficiency, and serve as a driver of innovation in the industry. As the new ruling is implemented, a key effect will be providing greater clarity on the opportunities for new projects to generate revenue through various, well-defined grid services and associated revenue streams.

 

Is Mobility Key to Unlocking the Maximum Value of Energy Storage?

— December 27, 2017

The ability of distributed energy resources, including energy storage systems (ESSs), to defer investments in new transmission and distribution (T&D) infrastructure has emerged as one of the most attractive uses of the technology. Navigant Research has covered this topic in recent reports, including Energy Storage for Transmission and Distribution Deferral and Non-Wires Alternatives. In some cases, ESSs and other technologies can be used to entirely avoid the need for infrastructure upgrades, though these situations are rare. Most energy storage projects providing these services are designed to defer infrastructure upgrades for a period of 3-6 years on average. A deferral period of this length typically results in costlier T&D projects being profitably deferred with energy storage.

ESS vendors have worked for years to develop mobile storage technologies with the aim of overcoming this barrier and opening a much larger addressable market for potential T&D deferrals. While an ESS project may only defer T&D investments for 3 years, the storage system itself will last much longer. In theory, moving an ESS from one location to another every few years will allow for numerous T&D projects to be deferred and will maximize the value of a single storage system. The challenge with this concept has traditionally been designing a hardware platform capable of being moved from one location to another with relatively low costs, while not damaging sensitive batteries and power electronics. The maturation of the storage industry over the past few years has resulted in new designs for mobile ESSs that can be efficiently moved from site to site.

ESS Solution Product Testing

Con Edison in New York was one of the first utilities in the US to launch a project testing mobile ESS solutions. The mobile systems for this pilot project are designed to optimize existing T&D assets, defer investments and upgrades, and support the grid during emergencies or in response to unanticipated events. When not needed by the utility, the ESSs will be located at the Astoria generation plant, owned by project partner NRG Energy. At this facility, the systems can participate in the New York Independent System Operator (NYISO) markets for frequency regulation, operating reserves, and day-ahead or real-time capacity.

Con Edison and NRG Deployable Storage Asset      

Source: Consolidated Edison

The concept of mobile energy storage is quickly gaining traction in the industry. New Jersey-based startup Power Edison has developed integrated ESS products designed from the ground up for mobility, which it claims can significantly lower the cost of transportable storage. The company’s products come preconfigured in shipping containers, with power ratings from a few tens of kilowatts to several megawatts. The systems are specifically engineered to handle vibrations, changing environmental conditions, and other disruptions due to transportation with a custom-built trailer that can protect sensitive hardware components and not void vendor warranties.

ESS Solutions Add Value

A growing number of utilities have expressed interest in these innovative ESS solutions; however, questions remain around the true cost to move systems from one location to another and the potential effects to system hardware. The upfront costs for mobile ESSs are typically much higher than a standard stationary system due to the need for custom-built enclosures, battery mounting hardware, and trailers. Despite these challenges, mobile ESSs present a major opportunity to enhance the value and flexibility of energy storage on the grid.

 

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