Increased penetration of renewable resources, the retirement of coal and nuclear power plants, and other factors have resulted in a substantial shift in the location and capabilities of energy resources in many markets. At the same time, states with renewable energy portfolios or other policies encouraging renewables, such as net metering, have seen a substantial increase in the penetration of renewable resources. When combined, these factors have focused attention on grid stability and the need for not just energy and capacity but ancillary services.
Energy storage has been identified as one means of responding to the factors identified above. To date, storage has been available through pumped storage facilities and storage of natural gas (for a combustion turbine) or water (behind a hydroelectric plant), but the development and deployment of stand-alone storage has been relatively slow. The speed of development and deployment of energy storage has been thwarted by at least two factors: (1) the cost of storage technologies and (2) the lack of a well-understood and acceptable commercial model (i.e., how owners of storage facilities should be compensated for the capital and operating costs of constructing, owning and operating storage facilities and supplying storage services).
However, today, there is increased optimism that the age of storage has arrived. This is demonstrated not only by an increase in the number of storage projects being built and the number of storage technologies being implemented, but also by a growing number of state policies designed to encourage research, development and investment in energy storage.
Much has been written about California’s first-in-the-nation energy storage mandates. While no other states have established energy storage requirements as ambitious as California, several other states have taken more limited steps to encourage energy storage procurement and development. This article describes a few of those initiatives, but is by no means exhaustive. Other states not covered by this article, such as Texas (with its vast intermittent wind resources), Arizona (with abundant solar) and Washington (think hydro) are also exploring storage programs and, in some cases, legislation.
Oregon
The law applies to “electric companies”—entities engaged in the business of distributing electricity to retail customers, other than consumer-owned utilities—that sell energy to 25,000 or more retail customers in Oregon. The two utilities that currently meet this definition are Portland General Electric and PacifiCorp. The law permits the utilities to recover, through their retail rates, all costs “prudently incurred” in procuring the storage systems, including any above-market costs associated with procurement.The law also caps the total capacity of energy storage systems that any one utility may procure at 1% of the utility’s 2014 peak load. The PUC may waive this cap if it determines, in consultation with the Oregon Department of Energy, that a particular storage system is of statewide significance and one or more “electric utilities” (which includes consumer-owned utilities) participates in procuring the storage system and shares the costs and benefits associated with the system.
The Oregon PUC is required to report on the implementation of the law to the interim committees of the Legislative Assembly related to energy on or before September 15, 2016.
The law also requires the Oregon PUC to adopt, by January 1, 2017, guidelines for utilities to submit their procurement proposals. The PUC has opened a docket (No. UM 1751) to comply with this requirement. By January 1, 2018, each utility must submit to the PUC a proposal to procure one or more energy storage systems. Each proposal must specify the relevant technical specifications, the project’s estimated cost, the anticipated benefits to the grid and an evaluation of the project’s cost-effectiveness. The PUC will review projects on an individual basis and determine whether a proposed project is consistent with the PUC’s guidelines, reasonably balances the value for ratepayers and utility operations, and is in the public interest.
In June, 2015, Oregon’s governor signed into law House Bill 2193-B, which requires certain electric utilities in Oregon to procure at least 5 MWh of qualifying energy storage systems by January 1, 2020. Utilities can satisfy this requirement by directly owning qualifying systems or by contracting for the capacity from qualifying energy storage systems. The law does not distinguish between types of storage technologies (e.g., batteries, pumped storage, etc.), rather a system qualifies as long as it is included in a project that the Oregon Public Utility Commission has authorized for development.
Massachusetts
Massachusetts has announced a $10 million Energy Storage Initiative (ESI) to analyze opportunities to support Massachusetts storage companies and develop policy options to encourage energy storage deployment. The ESI will be administered by the Massachusetts Department of Energy Resources (DOER).
The ESI includes three primary components: (1) a two-party study with the Massachusetts Clean Energy Center (MassCEC), (2) a Market Signals Assessment, the purpose of which will be to identify and evaluate the appropriate value of services energy storage can provide to ratepayers and the grid, and (3) direct support for demonstration projects.The Market Signals Assessment will be conducted by DOER and will include engaging stakeholders such as ISO New England (ISO-NE), utilities, the U.S. Department of Energy (DOE) national laboratories, and other interested parties. This assessment will build on the policy options identified in the two-party study, evaluate impacts on rate payers, the grid and emissions, and incorporate concepts from grid modernization plans.
The demonstration projects will cover a range of applications, including utility, distribution system and behind-the-meter. In furtherance of this goal, DOER proposes to establish strategic partnerships with key market players, including Massachusetts-based storage and clean energy companies, DOE national labs, ISO-NE, Massachusetts distribution utilities and municipal light plants, and within existing DOER and MassCEC programs.
The first part of the two-part study will analyze the industry landscape, economic development and market opportunities for energy storage, and examine potential policies and programs that could better support energy storage deployment in Massachusetts. The second part of the study will provide policy and regulatory recommendations for state policy makers, along with cost-benefit analyses. The study will be conducted by a consultant team led by Customized Energy Solutions, Ltd. and is expected to be completed by February, 2016.
The Market Signals Assessment will be conducted by DOER and will include engaging stakeholders such as ISO New England (ISO-NE), utilities, the U.S. Department of Energy (DOE) national laboratories, and other interested parties. This assessment will build on the policy options identified in the two-party study, evaluate impacts on rate payers, the grid and emissions, and incorporate concepts from grid modernization plans.
The demonstration projects will cover a range of applications, including utility, distribution system and behind-the-meter. In furtherance of this goal, DOER proposes to establish strategic partnerships with key market players, including Massachusetts-based storage and clean energy companies, DOE national labs, ISO-NE, Massachusetts distribution utilities and municipal light plants, and within existing DOER and MassCEC programs.
Hawaii
The first option is a “self-supply” tariff which permits expedited approval of solar systems, but allows utility customers to send only a limited amount of energy to the grid and does not compensate customers at all for that energy. This tariff is designed for customers that primarily intend to consume all of the energy produced by their system and encourages the use of energy management and storage systems to balance onsite generation with demand.Both new tariffs would require customers to pay a $25 fixed monthly fee to the utility (and a $50 fixed monthly fee for small commercial customers) to ensure the utility receives some compensation for supplying grid infrastructure. The HECO companies did not request a minimum fee for large commercial customers because those customers are already subject to demand charges that compensate the utility for such costs.
A second phase of this proceeding will focus on further developing competitive markets for distributed energy resources, including storage. A schedule for Phase 2 has not yet been established.
The second option is a “grid-supply” tariff that allows customers to send energy back to the grid in exchange for energy credits on their monthly bills, similar to existing net metering rules. Unlike existing net metering rules, however, the amount of energy credits will not be tied to retail electricity rates, but rather will be set at a rate that approximates the relative value of the exported energy to the grid. For the first two years of the tariff, these rates will range between 15 to 27 cents per kWh, varying by island. With Hawaiian retail rates around 30 cents per kWh, this spread in pricing creates an incentive for customers to store their energy rather than selling it back to the grid, thereby enabling the customer to draw on the stored energy later and avoid the higher retail rate. The grid-supply tariff is initially capped at 25 MW for the HECO service territory and 5 MW each for the HELCO and MECO service territories.
On October 12, 2015, the Hawaii Public Utilities Commission recently issued a decision that may have the effect of bolstering the economic incentives for energy storage in Hawaii. The decision (Docket No. 2014-0192, Decision and Order No. 33258) caps Hawaii’s net energy metering program at existing levels and creates new options for customers wishing to invest in rooftop solar and other distributed energy resources (up to 100 kW in size).
On the utility-scale front, HECO announced last year its intention to procure one or more large scale storage systems on Oahu capable of storing 60 to 200 MW for up to 30 minutes. After receiving 60 responses to its initial request for proposals, HECO entered into negotiations with three developer finalists, but the identity of those finalists has not been publicly disclosed. HECO has stated that it intends to have the storage systems in service by 2018.
New York
To qualify for a payment, projects must be installed and operating by June 1, 2016 and provide peak demand reduction of at least 50 kW. Peak demand reduction is defined as reduced demand for electricity between 2 p.m. and 6 p.m., Monday through Friday, from June 1 through September 30, excluding legal holidays. Projects are eligible for additional payments if they reduce load by 500 kW or more (an additional 10% of the base incentive) or 1 MW or more (an additional 15% of the base incentive). Incentives are capped at 50% of the project cost (plus any applicable large project bonus). The payment incentives are available on a first-come, first-served basis until program funds are exhausted.Separately, New York’s Public Service Commission is approximately 18 months into its “Reforming the Energy Vision” proceeding. The aim of the proceeding is to reorient New York’s electric industry and utility ratemaking paradigm toward a more consumer-oriented approach that harnesses and supports distributed energy resources, including storage.
Through the second quarter of 2015, NYSERDA and ConEd had approved 78.1 MW in energy efficiency and demand reduction applications, representing nearly $96 million in incentives. The committed projects included approximately 3.4 MW of thermal storage and 6.7 MW of battery storage.
The future of the Indian Point nuclear facility in Buchanan, NY has been the subject of debate for some time, with many groups and certain state leaders strongly advocating for its closure. Currently, the facility provides approximately 20% of New York City’s base load. To help reduce electricity demand in the event the facility is closed, the New York State Energy Research and Development Authority (NYSERDA) and ConEdison have created an energy storage incentive program that provides utility customers with a one-time payment of $2,100/kW for battery storage and $2,600/kW for thermal storage. The incentive structure is part of an overall framework to reduce demand in the area by 100 MW.
Conclusion
The policies and proceedings described illustrate an increased focus on stand-alone storage and that a single, commercial and technical model has yet to surface. Nonetheless, given the potential for increased penetration of renewables and the decrease in operating central station coal plants, legislatures, public utility commissions and utilities will remain focused on storage and the importance it has to the continued safe and reliable operation of the transmission grid. While not all of the approaches already being followed (and those that are likely to be suggested in the future), will succeed, the surge of policy experimentation in this area lends hope that at least a few will.