The volume of data generated by the smart grid threatens to drown utilities, who have yet to figure out what to do with the information or how to store it, according to industry experts. “It’s generating terabytes of data,” said a representative of the Electric Power Research Institute at a panel discussion at the Illinois Institute of Technology.
NorthWestern Energy will buy 11 hydroelectric plants from PPL Montana – the same power-producing dams that NorthWestern’s predecessor, Montana Power Co., sold in the wake of deregulation almost 15 years ago. NorthWestern said it agreed to buy the 11 dams along five separate Montana rivers for $900 million, subject to approval by state and federal regulators.
FirstEnergy Corp. plans to spend several hundred million dollars to replace the steam generator and reactor vessel head at its Beaver Valley Unit 2 reactor, in Pennsylvania, in 2017. It also plans to replace the two steam generators at its Davis-Besse plant in Ohio in February during a longer-than-normal refueling outage.
Pepco Holdings Inc. named former Dayton Power and Light Co. CEO Paul M. Barbas to its board of directors. Barbas is also a former chief operating officer of Chesapeake Utilities Corp. and executive vice president of Allegheny Power.
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, 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.
Ron Binz’ nomination to the FERC chairmanship was hanging by a thread late last week after coal-state lawmakers took the former Colorado regulator to task at his confirmation hearing and Sen. Joe Manchin (D., W.V.) announced he would oppose the nominee.
Binz testifies
Binz will need the backing of one Republican and all of the remaining 11 Democrats to win the recommendation of the 22-member Senate Energy and Natural Resources Committee. That will be tough for Democrats to pull off.
Ranking member Lisa Murkowski (R-Alaska) has already stated her opposition and no Republicans spoke in favor of Binz at his confirmation hearing Tuesday. Also in doubt is Sen. Mary Landrieu (D., La.), who has not indicated she will support the nominee.
`War on Coal’ Target
If Binz’ nomination fails, it will be because he became the target for those angry over the Obama administration’s so-called “war on coal.”
Binz would have limited influence over coal’s life or death as FERC chairman: Although FERC policies ensuring transmission access for renewables impacts coal indirectly, the agency has no role in the setting of climate or pollution policy.
But the timing of his confirmation hearing was inauspicious. The War-on-Coal blowback reached a crescendo last week as the EPA issued its long-awaited greenhouse gas limits on new power plants.
Manchin complained at Tuesday’s hearing that Obama’s environmental policies were beating the “living crap” out of his state. On Wednesday, he announced his opposition to Binz, criticizing him for prioritizing “renewables over reliability.
“His approach of demonizing coal and gas has increased electricity costs for consumers,” Manchin said.
Colorado PUC
Binz served as chairman of the Colorado Public Utilities Commission from 2007 through 2011, during which he drew praise from renewable energy advocates and opposition from the coal industry.
Binz participated in the drafting of Colorado’s Clean Air-Clean Jobs Act, which offered utilities incentives for replacing coal-fired power plants with natural gas. The bill, which was opposed by the coal industry, led to the retirement of six coal-fired generators, the addition of pollution controls at two others and the construction of new gas generation at a cost of about $1 billion. See: Who is Ron Binz, And What Will He Do at FERC?
Binz told last week’s hearing he would be “source neutral” and emphasize reliability as FERC chair. He noted that coal provides 40% of Colorado’s electricity, more than any other source. He also acknowledged he had spoken “inartfully” at a forum when he called natural gas a “dead end” fuel.
Norris Allegation
Adding to Binz’ woes last week were comments from FERC Commissioner John Norris, who reported that Senate Majority Leader Harry Reid persuaded President Obama to reject him as FERC chairman because he was too “pro-coal.”
Norris, a Democrat, told TransmissionHub that Reid’s chief of staff cited a vote he made as a member of the Iowa Utilities Board. Reid’s office denied Norris’ account.
Senate Minority Leader Mitch McConnell (R-Ky.) said Thursday that he would actively work against the nomination of what he called the Senate Majority Leader’s “foot soldier in his and this Administration’s War on Coal.”
Duke Energy Corp. is the latest company to end a long-standing practice of insuring its retirees, a cost-saving approach already embraced by IBM, Time Warner, Caterpillar, General Electric and DuPont.
About 14,500 retirees of were informed that the company will no longer provide insurance to supplement Medicare coverage. Instead, Duke will pay retirees an annual stipend toward the cost of insurance.
Almost 75% of the nation’s publicly traded companies are ignoring a three-year-old Securities and Exchange Commission requirement that they inform investors of the risks that climate change may pose to their bottom lines.
The data, culled from the annual reports of 3,895 U.S. public companies listed on major stock exchanges, found that only 27% mentioned “climate change” or “global warming” in their most recent filing. Nearly all of the 179 energy companies reviewed mentioned climate change.
The number of electric generation units at commercial and industrial sites has more than quadrupled since 2006, leading utilities such as AEP to consider getting into the on-site power business.
On-site generation still accounts for less than 5% of U.S. electricity production. But it is gaining momentum because of falling prices for solar panels and natural gas, as well as a fear that power outages caused by major storms will become more common. Wal-Mart, which produces about 4% of the electricity it uses, plans to boost that to 20% by 2020 and expects to be paying as little for solar power as utility power in less than three years.
Exelon Corp. boosted the stock awards for CEO Christopher Crane to $4.2 million in 2012, 25% above his target, thanks to his work lobbying state and federal officials. The company’s board of directors credited Crane for winning approval of the Constellation merger and for influencing new Environmental Protection Agency regulations and deregulation measures in Ohio.
FirstEnergy Corp. announced the election Luis A. Reyes, former administrator of the Nuclear Regulatory Commission’s Atlanta-based Region II, to its board of directors. His term will run until the company’s 2014 annual meeting. Reyes will serve on the board’s Corporate Governance and Nuclear Committees.
NorthWestern Energy will buy 11 hydroelectric plants from PPL Montana – the same power-producing dams that NorthWestern’s predecessor, Montana Power Co., sold in the wake of deregulation almost 15 years ago. NorthWestern said it agreed to buy the 11 dams along five separate Montana rivers for $900 million, subject to approval by state and federal regulators.
FirstEnergy Corp. plans to spend several hundred million dollars to replace the steam generator and reactor vessel head at its Beaver Valley Unit 2 reactor, in Pennsylvania, in 2017. It also plans to replace the two steam generators at its Davis-Besse plant in Ohio in February during a longer-than-normal refueling outage.
