Members agreed Thursday to consider new rules to allow batteries, flywheels and other advanced storage technologies to bid in the capacity market.
The Market and Reliability Committee approved a problem statement and issue charge with only two no votes despite some wariness from some members.
The proposal was sponsored by Demansys Energy LLC, which aggregates commercial and industrial customers for participation in the regulation market.
Janette Kessler Dudley, vice president of business development and regulatory affairs, noted that PJM currently has no rules allowing batteries or other advanced storage resources to participate in the Reliability Pricing Model. “What my company is interested in is parity,” she said.
Steve Lieberman, of Old Dominion Electric Cooperative, said he was not convinced storage is compatible with other capacity resources.
He said the issue should receive a lower priority than those currently before the Capacity Senior Task Force. “We should proceed carefully as far as expectations go,” he said.
Members ultimately decided the move the issue from the CSTF to the Planning Committee.
Gloria Godson, of Pepco, said she supported the inquiry but that PJM shouldn’t approve new rules until it fully understands the technologies. She noted the amount of “retooling” the RTO has done to address problems with the integration of demand response.
Raghu Sudhakara, of Rockland Electric Co., noted that NYISO already allows four hour resources to participate in its capacity market. “There’s no reason PJM, being as sophisticated as it is, can’t accommodate new technologies,” he said.
PJM currently has about 56 MW of non-pump storage.
PJM should be able to absorb the more than 7,400 MW of imports that cleared in May’s capacity auction for 2016-17, officials told a special meeting of the Planning Committee Friday.
Officials said that their initial review found PJM can import 11,000 to 12,000 MW. “We may have gotten close to what our limit would be, but we haven’t gotten to it yet,” said Stu Bresler, PJM vice president of market operations.
Officials cautioned that their results were preliminary and subject to change with further analysis.
Friday’s meeting was prompted by a problem statement approved by the Planning Committee Sept. 12.
The committee will seek to adopt a methodology for determining an RTO import limit that can be applied in the PJM planning process as well as included in next year’s Base Residual Auction. “It would function much like a CETL (Capacity Emergency Transfer Limit) for the entire RTO,” Bresler told the Markets and Reliability Committee in a brief discussion Thursday.
In addition to ensuring space for capacity, PJM must account for long term transmission contracts and 3,500 MW for the RTO’s Capacity Benefit Margin, which is reserved for importing capacity from external areas in emergencies.
Officials said their initial review identified a 500/230 kV transformer in the Duke Energy Carolinas zone as the limiting facility.
Bresler said PJM likely will propose a combination of path-specific limits with an overall RTO import cap. “The sum of the path-by-path limits could exceed what an overall limit would be,” he said.
Officials were unable to say Friday how much of the RTO’s total import capacity is to PJM’s west, the source of most of the imports that cleared in the May auction.
Market Monitor Joseph Bowring last week released an analysis that he said proves his contention that up-to congestion (UTC) transactions are increasing shortfalls in Financial Transmission Rights funding.
“There’s no reason to believe up-to congestion transactions help price convergence,” Bowring said in presenting his monthly report to the Members Committee webinar. “But they do increase day-ahead congestion.”
The monitor’s analysis was based on a simulation of market results with and without UTC bids for a five-day sample in May.
The analysis found that UTCs affect unit commitment and dispatch in the day-ahead market, increasing the number of binding constraints and negative balancing congestion.
For the five days examined, the FTR funding deficit was $4.4 million with UTCs versus a surplus of $22,000 with UTCs removed — a difference of $4.6 million.
In its 2012 State of the Market report, the monitor called for eliminating UTC transactions or making them responsible for day-ahead and balancing operating reserve charges.
The monitor said the RTO deviation rate for 2012 would have been reduced by 59% percent if UTC transactions had been included in the calculation of operating reserve charges.
The average cleared volume of UTC trades increased 73% between 2011 and 2012.
A 2010 white paper by the Electric Power Research Institute (EPRI) identified 10 applications for energy storage across the entire electricity supply chain, including end-users. Below are some of the most promising:
Frequency Response: While large scale use is a long term ambition for storage, “frequency response is the wedge into actual utility application in the field,” says Imre Gyuk, manager of the Department of Energy’s energy storage research program. Storage can provide much quicker performance than fossil fuel plants, which can take five minutes to respond. “In these five minutes the need may already be in the opposite direction,” Gyuk noted. Beacon Power, for example, says its flywheels can respond nearly instantaneously to operator control signals — up to 100 times faster than traditional generators. Beacon cited a recent study for the California Energy Commission which found that a 30-50 MW fast-response storage device could provide as much or more regulation capability as a 100 MW combustion turbine.
Back-up Power: Researchers see large end users purchasing storage for backup power during grid interruptions. EPRI reports that diesel generators have a failure rate of more than 20%. A White House report released in August recommended that energy storage systems be a top priority for new investments to modernize the grid and improve reliability.
Support for Intermittent Resources: Wind power produces only 10% of nameplate capacity in peak hours. “That alone is practically a mandate for storage,” said Gyuk. A 2010 study estimated a need of 0.8 to 1.5 MW of intra-hour balancing for every 10 MW of wind.
Delaying Transmission and Distribution Upgrades: Storage can provide alternatives to grid upgrades in locations with slow load growth and infrequent maximum load days. These benefits could range from $150,000 – $1,000,000/MW-year, according to EPRI.
WASHINGTON — The coal industry has been advertising the notion of “Clean Coal” for years. Now that the EPA has issued rules limiting carbon emissions from new coal generators, however, the industry says “Clean Coal” is neither feasible nor economical.
And they’re right.
In announcing the new greenhouse gas rules at the National Press Club here Friday, EPA Administrator Gina McCarthy was effusive in her enthusiasm for carbon capture and sequestration (CCS) — the technology coal will need to build new plants.
“It’s been demonstrated to be effective,” McCarthy said. “It’s being constructed on real facilities today.”
That’s true. But McCarthy will be long gone from EPA by the time CCS becomes inexpensive enough to make coal a viable alternative to natural gas. And it may never happen.
This matters. The Clean Air Act requires the EPA base its pollution standards on the “best system of emission reduction” with technology that has been “adequately demonstrated.”
How those terms are decided will determine whether the GHG rules survive the certain court challenge to come.
EPA’s proposal limits new large natural gas-fired turbines to 1,000 pounds of CO2 per MWh, easily achievable with current technology. New coal-fired units would need to meet a limit of 1,100 pounds per MWh, far below the emission levels of the most efficient coal plants without CCS, which range from 1,700 to 1,900 lbs./MWh.
The American Public Power Association, which represents 2,000 not-for-profit electric utilities, said EPA’s identification of CCS as the technology required for new coal generation is “unrealistic” and does not comply with the New Source Performance Standard (NSPS) requirements under the Clean Air Act.
The group said neither of the two CCS demonstration projects cited by EPA — Plant Ratcliffe in Kemper County, Miss., and the SaskPower plant in Canada — has demonstrated the commercially viability of the technology.
Both sites plan to inject CO2 into nearby oil fields, and both received government subsidies. “For a project to become commercially viable, it must be financed on its own and given the high risk of financing such unproven technology, it is extremely unclear where the funding would come from,” the group said in a statement.
A recently-released report funded by the Department of Energy concluded that, even if CCS becomes economical, the higher capital costs of coal generators means CCS “may be first deployed on natural gas plants before coal-fired plants, if natural gas prices remain low.”
“… Incentives to support coal mining and encourage the use of coal face an uphill battle in contending with these challenges,” the report said. (See DOE Study: Carbon Capture No Salvation for Coal )
Joseph Stanko, head of government relations for law firm Hunton & Williams, said the standard should be overturned by the appellate courts because EPA’s reliance on the two projects “doesn’t ‘adequately demonstrate’ technology for normal use.”
“NASA sent men to the moon with federal funds,” he told The Washington Post. “That doesn’t mean municipalities and companies can do it.”
McCarthy insisted in Friday’s briefing that the rule was “clearly not” an effective ban on new coal plants. “CCS is a technology that is feasible and it’s available today,” she insisted. “I believe this proposal sets out a certain path forward … Over time, you’ll be able to see there’s a reasonable, cost-effective strategy to keep coal in the energy mix.”
Below is a summary of the issues scheduled to be brought to a vote at the Markets and Reliability and Members committees Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.
RTO Insider will be in Wilmington covering the discussions and votes. See next Tuesday’s newsletter for a full report.
Markets and Reliability Committee
2. PJM MANUALS (9:10-9:20)
A. Members will be asked to endorse manual changes implementing PJM’s revised black start procedures (see FERC Docket ER13-1911). The changes affect M27 Section 7 and M12 Section 4.6.
B. Members will be asked to endorse changes to Manual 01: Control Center and Data Exchange Requirements to incorporate updated telemetry and EOP requirements.
3. COORDINATED TRANSACTION SCHEDULING (9:20-9:50)
Members will be asked to approve a new scheduling product intended to reduce uneconomic power flows between PJM and NYISO.
The Market Implementation Committee on Sept. 11 approved the Coordinated Transaction Scheduling product after amending it to address member concerns about the reliability of PJM’s price projection algorithm — on which CTS trades will be based.
The revised proposal would allow CTS to begin no sooner than September 2014 — later if MRC is not satisfied with the accuracy of the forecasts generated by PJM’s Intermediate Term Security Constrained Economic Dispatch (IT SCED) application.
MRC will be asked to approve increased penalties for under-performing Tier 2 synchronized reserve providers.
At a special Operating Committee meeting yesterday, members rejected a proposal from PJM and the Market Monitor (Package A) in favor of one introduced by Dave Pratzon, of GT Power Group, who represents generation owners (Package B).
Pratzon said his proposal was tougher than the current penalty but less severe than the PJM-Market Monitor proposal, which he called overly punitive.
The current penalty is to take away revenue for the hour when the resource did not perform and also require the resource to provide Tier 2 reserves without compensation when needed for three days. If a resource fails to perform in one hour it doesn’t affect its credit for performing in another hour during the same day.
Because Tier 2 SR calls have declined to about once every 10 days from one in every three days, the three-day penalty has lost its bite.
The proposal to be considered by the MRC Thursday removes the “contiguous” hours statement from the same-day penalty and creates a retroactive obligation to refund the shortfall for all of the hours the resource was assigned over the immediate past interval (i.e., 10 days currently). It also increases the penalty by eliminating the conversion of shortfall MW to MWh.
Package B was supported by almost three-quarters of those voting yesterday, with heavy backing from generator representatives. Package A won only 18% support. Package C, which would have added a 25% additional penalty to Pratzon’s proposal, won less than 27% support.
5. CAPACITY CREDIT CALCULATION FOR WIND RESOURCES (10:20-10:45)
Members will be asked to choose one of two alternatives to protect wind generators from being assigned artificially depressed capacity values due to curtailments ordered by PJM.
Under current policy, when wind generators are curtailed by PJM for any portion of a peak summer hour (2-6 p.m.), the entire hour is excluded from the generator’s capacity calculation.
The Planning Committee last month recommended a proposal (Alternative 2) under which state estimator data would be used to interpolate output for each five-minute period with curtailments. MRC also may consider a second option (Alternative 3), which was approved more narrowly by the PC. It would substitute forecast data from PJM operations — which is currently used for lost opportunity cost calculations — for curtailment periods.
6. EFFICIENCY OF DEMAND RESPONSE REGISTRATION PROCESS (10:45-11:00)
Members will vote on two proposals approved this month by the Market Implementation Committee to streamline the demand response registration process.
Current rules require curtailment service providers to submit customer names to both the electric distribution company and load serving entity.
The MIC approved the following changes:
Emergency Registration: The LSE will be removed from the review and notification process; EDCs will continue to do reviews under “Relevant Electric Retail Regulatory Authority” rules.
Economic Registration: The LSE will remain involved but PJM will make administrative changes to simplify the review process. The EDC and LSE review process will be separated to eliminate unnecessary reviews.
The changes are motivated in part by FERC Order 745, which reduced the LSE’s role in the registration process.
7. ENERGY MARKET UP-LIFT SENIOR TASK FORCE (EMUSTF) Charter (11:00-11:10)
Members will be asked to approve the charter for the Energy Market Uplift Senior Task Force (EMUSTF). The MRC approved the creation of the task force in May to take a broad review of its method of providing Operating Reserve payments.
PJM said the changes were needed to reduce growing uplift costs resulting from Operating Reserves, “make whole” payments that ensure generators dispatched out of merit for system reliability don’t operate at a loss.
Members will be asked to approve a proposed problem statement allowing batteries, flywheels and other advanced energy storage technologies to participate in its capacity market.
Constraints that can be quickly and cheaply resolved would be included in the Regional Transmission Expansion Plan (RTEP) under a proposal the MC will be asked to endorse. The proposal was approved by the MRC in August.
The new rules require PJM staff to identify — before posting the planning parameters for each Base Residual Auction — Locational Deliverability Areas in which the Capacity Emergency Transfer Limit is less than 1.15 times the Capacity Emergency Transfer Objective.
Upgrades that raise the ratio above 1.15 would be added to the RTEP if they cost less than $5 million and can be completed within 36 months or prior to June 1 of the Delivery Year. Projects that duplicate upgrades whose cost is already assigned to an interconnection customer would be excluded.
PJM will add new processes for generators seeking exemptions from operating parameters under Tariff changes the MC will be asked to endorse.
The parameters are defaults for different types and sizes of generators, covering minimum run and down times, maximum daily and weekly starts and turn down ratios (Eco Max/Eco Min). They were initiated in 2008 to ensure lower make whole payments for generators whose entire offers were not covered by Locational Marginal Pricing revenues. The changes were approved by the MRC in August.
Retail marketer Direct Energy will attempt to win Members Committee approval for Tariff revisions that would allow network load customers more frequent opportunities to switch to nodal pricing.
The Market Implementation Committee in August rejected the company’s proposals after utility representatives said the changes would create administrative problems for their electric distribution companies (EDCs).
The company said the changes would allow retail marketers to offer more innovative products but would not have significant impact on EDCs or other market participants because it would cap switches at 5% of the EDC network service peak load.
More conservative reserve calculations, quicker and more granular demand response and optimizing trades with neighboring regions: These are some of the changes PJM is considering in the wake of September’s unexpected heat wave, officials told the Members Committee webinar yesterday.
PJM gave a detailed presentation on the events of Sept. 9-11, when PJM was forced to shed load during unseasonably high temperatures at a time when large numbers of transmission and generation resources were out of service for planned maintenance.
Yesterday’s briefing lasted about two hours, and the lessons learned will likely consume many more hours of stakeholder meetings.
Seeking a Nimbler DR
Stu Bresler, PJM vice president of market operations, told the committee that the September episode illustrated the need to give operators the ability to make quicker and more targeted use of demand response.
The Capacity Senior Task Force, which is meeting today, is considering reducing DR’s minimum lead and run times. Also under discussion will be changes to rules limiting operators’ ability to target DR calls geographically.
Almost 6,000 MW of demand response was dispatched on Sept. 11 — an all-time record that underscored its increasing importance to the RTO. “We’re going to have to get used to DR as an operational tool being used outside of the June-July-August period,” Bresler said.
Conservative Reserve Estimates
The CSTF isn’t the only stakeholder group that will be discussing the fallout from the heat spike. The Operating Committee will be discussing improving generator data to more accurately calculate reserve quantities after a poor synchronized reserve response led to an unusually long spinning event Sept. 10.
Adam Keech, director of wholesale market operations, said operators will likely be using “more conservative” RTO reserve calculations in the future.
The newly-formed Energy Market Uplift Senior Task Force will be discussing changes to rules allowing emergency DR to set prices, as it did in some areas during both the July and September events.
Officials are having second thoughts about the price cap on demand response — now effectively $1,800 per MWh but scheduled to increase to $2,700. “Are we comfortable with $2,700?” asked PJM’s Becky Carroll.
In addition, PJM may seek to create a product to reduce interchange volatility along its seam with MISO similar to the Coordinated Transaction Scheduling product with NYISO. Members will vote on CTS Thursday (see MRC/MC Preview).
Load Sheds Hit 44,000
In addition to the presentation, PJM yesterday also released a 21-page report providing officials’ preliminary analysis of the events of Sept. 9-11.
PJM cut power to 44,000 customers in southern Michigan, northern Ohio and northwest Pennsylvania Sept. 9 and 10 as temperatures unexpectedly hit the mid-90s and the RTO found itself without enough transmission or generation.
Although the cuts were relatively small — the 154 MW in total load shed was less than 0.1% of Sept. 10’s peak load — the situation could have been far worse.
When a 345/138 kV transformer in AEP’s South Canton area tripped Sept. 9, four 345 kV lines were lost, leading PJM operators to fear it could worsen to a cascading outage.
There were also concerns of a widespread blackout Sept. 10, when a 345 kV line near Erie, Pa., was lost. PJM ordered FirstEnergy to drop 70 MW of load at 17:41. When that did not alleviate concerns, PJM ordered the cut of an additional 35 MW.
Conditions were exacerbated by weather forecasts that missed peak temperatures by up to 5 degrees — leading PJM to under-forecast loads. Balancing congestion, which results when day-ahead loads differ from real-time, totaled $23.1 million in the ATSI zone over Sept. 10 and 11.
The Cavalry Fails to Arrive
(Source: PJM Interconnection, LLC)
One major concern was the failure of generating resources to provide Tier 1 synchronized reserves as loads steadily climbed on Sept. 10. When PJM called a spinning event at 15:48, it showed reserves of about 2,000 MW. Yet only 130 MW of additional generation responded within 10 minutes, leading PJM to call on 800 MW from NPCC as the RTO’s area control error (ACE) fell to a deficit of 1,600 MW.
At the peak, synchronized reserve response totaled only 350 MW. The spinning event lasted an unusually long 68 minutes. “The [synchronized reserve] response clearly was not there,” said PJM’s Chris Pilong.
As a result, Pilong said, operators felt they had to dispatch demand response for support the following day. PJM called on a record of almost 6,000 MW of demand response in the AEP, ATSI, Dominion and Duquesne zones on Sept. 11. “The operators didn’t have a lot of confidence in the numbers reported” as reserves, he said.
Operators also declared a Transmission Loading Relief 5 on Sept. 11, cutting 100 MW of firm transactions on the Neptune DC tie to New York.
Next Steps
Officials said they will produce a “Frequently Asked Questions” document in response to members’ inquiries, as they did after the July event. Stu Bresler, Adam Keech, and Dave Anders will be receiving queries.
Washington, D.C., is the most energy-efficient major city in PJM, followed by Philadelphia and Chicago, according to the American Council for an Energy-Efficient Economy. Boston took the top spot in ACEEE’s inaugural City Energy Efficiency Scorecard, receiving 77 of a possible 100 score.
Washington, D.C. (#7 nationally), Chicago (9) and Philadelphia (10) ranked in the second tier, receiving more than half of possible points. Philadelphia was among the top-scoring cities on community-wide initiatives, with efficiency targets, systems to track progress, strategies for mitigating urban heat islands, and use of distributed-energy systems. Philadelphia also scored high for transportation policies, along with Washington.
(Source: Environment America Research Policy Center)
The 100 most-polluting U.S. power plants are responsible for about half of all power-sector carbon dioxide emissions, according to a new study. Forty-four of the worst 100 polluters are in PJM states, nearly three-quarters of them in West Virginia, Pennsylvania, Ohio, Indiana and Kentucky.
Nearly 40% of U.S. households had smart meters as of July, up from about 33% a year earlier. “The era of pilots is a distant memory,” the Edison Foundation’s Institute for Electric Efficiency concludes in a new report. “The current focus is … on integrating and optimizing information gathered by smart meters and other investments that form the digital grid.”
Bipartisan energy efficiency legislation that has stalled in the Senate may be shoved aside completely this week by debate on a funding bill, leaving the fate of the energy measure highly uncertain. The bill has become ensnared in battles over ObamaCare and other topics.
Methane emissions from fracking well completions are lower than previously estimated while emissions from pneumatic controllers and equipment leaks are higher than Environmental Protection Agency projections, according to a new study. The study, funded by industry and the Environmental Defense Fund, concluded that total emissions from natural gas production are about what EPA has estimated.
Researchers took measurements at 489 wells nationwide, about one-tenth of 1% of all the natural gas wells in the U.S. Some observers said the study may understate total emissions because high-emitting sites, although rare, can cause disproportionate releases.
The Federal Energy Regulatory Commission last week approved a final rule extending reliability standards to generator tie-lines and a Notice of Proposed Rulemaking on standards regarding generator verification.
Generator Requirements at the Transmission Interface (RM12-16)
In a final rule, the commission approved Reliability Standards FAC-001-1 (Facility Connection Requirements), FAC-003-3 (Transmission Vegetation Management), PRC-004-2.1a (Analysis and Mitigation of Transmission and Generation Protection System Misoperations), and PRC-005-1.1b (Transmission and Generation Protection System Maintenance and Testing).
Reason for change: The North American Electric Reliability Corp. (NERC) proposed the standards to close a reliability gap for generator interconnection facilities without requiring generators to register as transmission operators.
Impact: The FAC-001 and FAC-003 standards currently in effect are applicable only to transmission owners and operators; the change will extend their applicability to certain generator interconnection facilities.
The current versions of PRC-004 and PRC-005 do apply to generator owners as well as transmission owners. NERC proposed modifications to clarify that their requirements extend not only to protection systems associated with the generator, but also to any protection systems associated with the generator interconnection.
The standards define “generator interconnection facility” as referring to “generator interconnection tie-lines and their associated facilities extending from the secondary (high) side of a generator owner’s step-up transformer(s) to the point of interconnection with the host transmission owner.”
FERC Contacts:
Technical Information — Susan Morris, Office of Electric Reliability, (202) 502-6803, susan.morris@ferc.gov
Legal Information — Julie Greenisen, Office of the General Counsel, (202) 502-6362, julie.greenisen@ferc.gov
The commission approved a Notice of Proposed Rulemaking (NOPR) endorsing NERC’s proposed standards MOD-025-2 (Verification and Data Reporting of Generator Real and Reactive Power Capability and Synchronous Condenser Reactive Power Capability), MOD-026-1 (Verification of Models and Data for Generator Excitation Control System or Plant Volt/Var Control Functions), MOD-027-1(Verification of Models and Data for Turbine/Governor and Load Control or Active Power/Frequency Control Functions), PRC-019-1 (Coordination of Generating Unit or Plant Capabilities, Voltage Regulating Controls, and Protection), and PRC-024-1 (Generator Frequency and Voltage Protective Relay Settings).
Reason for change: The standards are designed to reduce the risk of generator trips and provide more accurate models for transmission planners and planning coordinators to develop system models and simulations. Portions of the standards were proposed to comply with FERC Order 693.
Impact: The standards should ensure that generator models accurately reflect generator capabilities and equipment performance.
Standards MOD-026-1, MOD-027-1, PRC-019-1 and PRC-024-1 are new.
MOD-025-2 consolidates two existing standards, MOD-024-1 (Verification of Generator Gross and Net Real Power Capability) and MOD-025-1 (Verification of Generator Gross and Net Reactive Power Capability), which will be retired.
Standards MOD-026-1 and MOD-027-1 would exclude units rated below 100 MVA (Eastern and Quebec Interconnections), 75 MVA (Western Interconnection) and 50 MVA (ERCOT Interconnection), potentially excluding about 20% of registered generators from compliance.
MOD-026-1 would allow transmission planners to compel the compliance of generators below the threshold if the generator is deemed to have “technically justified” units.
The commission is seeking comment on whether the higher thresholds limit the effectiveness of the proposed standards and on the exception regarding “technically justified” units.
FERC contacts:
Technical Information — Syed Ahmad, Office of Electric Reliability, (202) 502-8718, syed.ahmad@ferc.gov
Legal Information — Mark Bennett, Office of General Counsel, (202) 502-8524, mark.bennett@ferc.gov
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.
Beacon Power flywheels in Hazleton, Pa. (Source: Beacon Power)
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.
(Source: California PUC)
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.
