On Laurel Mountain, W.V., AES Corp. installed 32 MW of battery storage to support its 98 MW wind farm. The project provides PJM with regulation service and allows AES to smooth minute-to-minute fluctuations in output from its turbines.

In Hazle Township, Pa., Beacon Power is installing 200 flywheels that will provide PJM 20 MW of frequency response. The company put 4 MW into commercial operation on September 11 and expects the full 20 MW plant operational next year.

In Lyon Station, Pa., batteries housed in what look like large storage sheds are providing 3 MW of frequency regulation to PJM and peak demand management services to Met-Ed.

These are the vanguard of energy storage applications that will change both the economics and operations of the grid — providing quicker, more accurate frequency regulation, aiding in the integration of variable resources, eliminating the need for some grid upgrades, and providing alternatives to natural gas-fired peakers.

PJM members will be asked Thursday to approve an initiative to draft market rules to allow batteries, flywheels and other advanced energy storage devices to participate in the RTO’s capacity market.

This raises the question: Is advanced storage ready to move beyond pilot projects and into day-today operations?

Pumped hydro, a decades-old technology, currently provides virtually all of the grid’s storage capability, with more than 127,000 MW installed worldwide. Compressed air energy storage installations are second, followed by sodium-sulfur batteries. Other technologies total less than 85 MW combined.

Experts say some of the most promising storage applications, such as hydrogen-powered fuel cells that could provide bulk storage, are a decade or more from commercial deployment. But some more mature technologies could take significant roles in the next several years.

“The future is already here — at least the beginning of the future,” said Imre Gyuk, manager of the Department of Energy’s energy storage research program, at a briefing earlier this month in Washington.

Costs

For storage to reach its potential, its costs must come down at the same time that its capability improves.

Storage can provide benefits in regulation, voltage support and power quality and reliability as well as deferring transmission and distribution upgrades and reducing the need for peaking generators. But “even with all those benefits, it’s difficult to make it add up” to exceed costs, Haresh Kamath, energy storage program manager for the Electric Power Research Institute (EPRI), told the briefing.

Most energy storage technologies have higher capital costs than natural gas-fired peakers. Flywheel capital costs are similar to a combined-cycle plants. Sodium sulfur (NaS) batteries, the most economical battery for utility-scale applications, have been estimated at 1.8 to 3.5 times the cost of a combined cycle plant.

The two crucial of measures of storage capability are cycle life (the number of complete charge-discharge cycles before becoming unusable) and round-trip efficiency (the system’s energy output relative to input). Improving these measures will boost storage in comparisons against generation.

Market Rules

In addition to the cost and technology challenges, market rules are also an obstacle to widespread deployment.

Storage can provide several benefits simultaneously to the wholesale system, electric distribution companies, and end-use customers. “These characteristics, plus the difficulty in monetizing multiple stakeholder benefits, often act as barriers to the widespread deployment of energy storage systems, whose multi-functional characteristics also complicate rules for ownership and operation among various stakeholders,” EPRI said in a 2010 white paper. It concluded policy changes would be needed “to realize the true potential of storage assets.”

Rule Changes Could Quadruple Revenues

Researchers at Energy and Environmental Economics reported in a 2009 paper that storage revenues could be increased by as much as four-fold by reducing minimum size requirements for market participation and permitting bi-directional bidding for regulation.

The study looked at potential revenues for a theoretical storage resource located in Allentown, Pa., based on 2007 market clearing prices ($41/MW-day for capacity, $14/MWh for regulation and $34/MWh for energy). It found a system with 1 MW of charge and 2 MWh of energy storage would generate revenues of more than $250,000, most of it from regulation, with additional revenue from capacity and energy arbitrage — storing energy overnight when prices are low and selling during peak hours.

As of the time of the study, PJM capacity rules required a minimum of 12 hours of capacity and a minimum resource size of 0.1 MW.

One key to increasing revenues, the analysis found, was permitting asymmetric bidding in the regulation market — allowing the battery to earn regulation revenue when charging and discharging — in recognition that regulation dispatches over an hour can be energy neutral.

Changing market rules to permit asymmetric bidding and to allow energy storage to offer one hour of regulation with less than one hour of energy storage would increase the net present value of energy storage in PJM from about $1,000 per kWh of energy storage to nearly $3,500.

FERC Order, Stimulus Funding

Storage received a boost from the Federal Energy Regulatory Commission in July with Order 755, which requires PJM and other transmission providers to consider speed and accuracy in acquiring regulation resources. (See FERC Rule Boosts Storage, Renewables.)

Storage also was a prime beneficiary of federal stimulus money under the 2009 American Recovery and Reinvestment Act (ARRA). About $185 million in ARRA funds leveraged $585 million from industry for 16 energy storage projects, not including eight smart grid projects with storage. The goal of the federal spending is to demonstrate the technologies’ technical feasibility, document costs, stimulate regulatory changes and generate follow-on projects. Four of the 16 projects have been completed to date.

Proposed Legislation

To provide additional incentives, Sen. Ron Wyden (D-OR), chairman of Senate Energy and Natural Resources Committee, and Sen. Susan Collins (R-ME) reintroduced legislation in May to create an investment tax credit for energy storage.

California Storage Mandate

With or without federal incentives, a lot more storage will be added over the next few years. On Sept. 3, the California Public Utilities Commission issued a proposed order requiring the California grid to obtain 1.3 GW of storage by 2020, a target that will require utilities to increase their storage by 30% annually.

The order was prompted by Assembly Bill 2514, which barred pump storage projects larger than 50 MW from eligibility in order to enable a “market transformation” for new technologies.

The order would prohibit utilities from owning more than 50% of the storage resources to be procured across the three “grid domains” of transmission, distribution, and customer-located storage.

To address utilities’ concerns that the 2020 goal is too ambitious, it would allow utilities to defer up to 80% of their targets if they can show they can’t procure enough “viable projects to meet the targets.”

EPRI’s Kamath said California’s mandate could do for storage what Germany’s world-leading commitment to solar power did to reduce solar’s “soft” costs, including permitting, inspection, interconnection, financing and customer acquisition.

“It’s going to have effects all across the industry,” said Klamath.

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Resources for Additional Research:

• DOE/EPRI 2013 Electricity Storage Handbook
• DOE International Energy Storage Database
• Electricity Storage Technology Options (EPRI, December 2010)
• Impact of Market Rules on Energy Storage Economics (United States Association for Energy Economics)
• Market and Policy Barriers to Deployment of Energy Storage (Ohio State University)