Fearing a potential shortage of reactive power, PJM last week won stakeholder support for an initiative to consider requiring that renewable resources add technology capable of providing grid support.
The Planning Committee meeting gave near unanimous approval to a problem statement and issue charge to explore whether to require renewables such as solar PV to install enhanced or “smart” inverters that can produce and absorb reactive power in addition to inverting DC power to AC. Reactive power (vars) is required to maintain the voltage to deliver active power (watts) through transmission lines.
With the increasing amount of renewables, which do not provide reactive support, and the retirement of large traditional generators that do, “there’s a need for additional reactive support to avoid voltage problems,” said PJM’s Frank Koza.
“This is not a here-and-now problem for PJM, but something we should look at to see what the cost and benefit is,” he said.
Koza told the committee that running additional conventional generators for reactive support is not cost effective and could cause negative Locational Marginal Prices. Adding static VAR compensators is cost prohibitive. Neither address frequency issues, he said.
smart inverter with reactive power ability (Source: SMA Solar Technology AG)
Renewable power generators in Great Britain and Germany are already using smart inverters to improve grid reliability. Smart inverters can allow renewable generators to stay on line despite low voltages and fluctuating frequencies and reduce the “flicker” that can occur with solar generators on days of mixed sun and clouds, Koza said.
One question to be addressed in the inquiry will be whether smart inverters should be installed on existing equipment, or only required on future installations. (Currently installed smart inverters have their reactive capabilities disabled.)
The Planning Committee plans to develop technical standards for inverters along with related Tariff, Operating Agreement and manual changes. Koza said he hoped work could be completed in time for a FERC filing in August.
Below is a summary of 11 new recommendations resulting from PJM’s final report on the September 2013 heat wave. This is in addition to 11 recommendations made immediately after the events of Sept. 9-11. (See Big To-Do List from September Heat Wave.)
Update PJM’s documentation for modeling process and practices to include Transmission Owners’ input to PJM modeling process and a plan for implementing more modeling and telemetry across the transmission and sub-transmission system.
Identify behind–the-meter generators and incorporate them into emergency operations.
Develop rules for logging local shed events into the Emergency Procedures application and conduct training to reinforce usage.
Review and modify how EMS handles nonconvergences; automate cascading outage analysis; provide filtering on Emergency Procedure application.
Define more DR subzones proactively and map DR resources to nearest substation to improve the reliability of using DR to relieve transmission constraints.
Develop tools to aid dispatchers in visualization of the location and MW relief from DR.
Improve processes during hot and cold weather alerts; review process of handling notification of load forecast errors; create documentation and training that better explains to the Master Coordinators what information to look at when these days are forecasted.
Reconsider current methods for sampling and weighting of weather data throughout the RTO footprint; consider developing load forecasts on a sub zonal basis.
Develop a process for validating generator performance data (EcoMax, emergency max, spin max, etc.).
Improve the generation sorting functionality in the Dispatcher Management Tool. Available and max emergency units should be included on the normal sort. Max Emergency units should be flagged for easy identification.
Provide reinforcement training for operators on contingency management (contingency trending, PCLLRW, load shed, etc.) in the control room simulator. Use this training to look for EMS enhancements for managing constraints.
PJM overcame the loss of nearly 40,000 MW of generation yesterday, keeping the lights on in the second day of an arctic blast that set a new winter demand record.
The new winter record – 141,500 MW — came during Tuesday evening’s peak as PJM operators scrambled to overcome 38,000 MW in generation outages. The new record exceeded the Feb. 5, 2007 mark of 136,675 MW by nearly 5,000 MW.
“We really exhausted every megawatt we had on the system” Tuesday, Adam Keech, director of wholesale market operations, told the Market Implementation Committee in a briefing yesterday.
Generator outages peaked at 39,520 MW at 8 a.m. Wednesday, as load fell to 134,500. As of 8 p.m. last night, about 27,000 MW of generation was idled as demand peaked at about 125,600.
PJM operators also overcame gas pipeline curtailments that idled up to 9,046 MW of generation yesterday.
“The pipelines came through pretty well,” Gary Helm, lead market strategist, told the MIC. “We only saw two compressor outages.”
Keech said operators’ ability to forecast load was hamstrung by a lack of comparable temperature data.
“We couldn’t find a temperature set [with extreme cold throughout the RTO] for the last decade. And if you go back that far the [RTO] footprint was so different it’s probably not even useful.” Keech said.
PJM resorted to a 5% voltage reduction when reserves grew short about 8 p.m. Monday, triggering scarcity pricing — sending prices briefly above $1,000/MWh. “It hasn’t been this cold in 20 years,” Keech said. “It’s an outlier. That’s why we have scarcity pricing.”
Prices were above $200/MWh for most of the period from Monday evening through Tuesday evening, peaking at more than $1,800/MWh during Tuesday’s morning and evening peaks.
Officials also rescinded outage requests and implored customers to reduce consumption. And they benefited from an unexpected influx of more than 8,000 MW of imports Tuesday morning — more than half from MISO — that allowed them to cancel an emergency deployment of demand response.
Had the steps not been sufficient, officials said they might have had to resort to rolling blackouts to prevent more widespread outages.
“How close were you to a bigger problem? One unit away?” one stakeholder asked Keech.
Weary from lack of sleep, Keech smiled uneasily. “It depends on the size of the unit,” he said.
UPDATE: AS OF 5 P.M. TUESDAY, PJM SAID 36,000 MW OF GENERATION, 20% OF INSTALLED CAPACITY, WAS UNAVAILABLE DUE TO FORCED OUTAGES.
PJM operators dispatched demand response this morning after cutting voltages and calling on spinning reserves last night as frigid temperatures stressed generators and created record loads across the RTO.
Officials said they would likely call on DR again to meet tonight’s projected evening peak of 142,000 MW. That would break the RTO’s all-time winter peak of 138,600 — set this morning.
Officials were forced to take action last night after losing more than 2,000 MW of generation as peak loads hit 132,000 MW, 5,000 MW above PJM’s forecast.
RTO officials called on spinning reserve from about 6:30 p.m. to 7:30 p.m., then issued a 5% RTO-wide voltage reduction from 7:50 to 8:50 p.m. “We were able to recover,” Adam Keech, director of wholesale market operations, told the Operating Committee in a briefing this morning.
Today’s morning peak, which broke the previous 2007 record, led officials to call on about 1,900 MW of demand response about 6 a.m. and to purchase 1,100 MW of emergency power from NYISO and MISO between 6 and 11 a.m.
The dispatch of DR pushed prices from $1,000/MWh to $1,800/MWh – over $2,000, including congestion, in some locations.
Officials said they could be forced to issue a second voltage reduction or brief rolling blackouts if conservation efforts and imports fail to make up any shortfalls this evening. “We do not expect to take that [load shed] action,” Executive Vice President for Operations Mike Kormos said during a media call today.
PJM and state regulators urged consumers to reduce energy use during the emergency. “Every little bit helps,” Kormos said. “There’s 60 million people in our footprint. If everyone does their part, that could easily add up to one nuclear plant, which is 1,000 MWs.”
“We’re very close [to generation limits],” Kormos added. “The last couple hundred megawatts could allow us to not have to take any forced interruptions.”
Officials did not immediately have details on the number of generators out of service due to the cold. Kormos said some plants suffered mechanical problems and tube leaks or were unable to convert to backup fuel. “We’ve seen everything,” he said.
PJM received a waiver from the Federal Energy Regulatory Commission under Order 787, allowing RTO officials to share information with natural gas pipelines serving the region. PJM held conference calls with pipelines Friday and Monday and individually validated gas nominations for the RTO’s gas generators.Keech said there were no natural gas curtailments.
A critical part of the years-long Zion nuclear plant decommissioning is set to begin in January with removal of the spent-fuel rods. The work is vital to EnergySolutions, the company that obtained the Nuclear Regulatory Commission license from plant owner Exelon in order to undertake the decommissioning. Also next month, a court is scheduled to hear an appeal of a federal district court ruling that dismissed a citizen suit over handling of the $800 million decommissioning fund.
The Illinois Commerce Commission approved a distribution rate increase for Commonwealth Edison that will mean a 5.5% rise in an average bill. The increase is to cover $340 million the utility spent to upgrade its facilities with infrastructure improvements and smart grid components.
Residents near LG&E’s Cane Run Generating Station have filed suit against the utility and its parent, PPL, for relief from blowing coal ash. The company plans to replace the 645 MW plant with a natural gas generator in 2015. The suit, which seeks class-action status, asks for damages, civil penalties and action to cap the ash disposal site.
The Interior Department announced it will lease 80,000 acres off the Maryland coast for wind development. An auction could be held next year and turbines built as soon as 2018, the director of the Maryland Energy Administration said, although she allowed that schedule might be optimistic. According to a study, the sale area could generate from 850 to 1,450 MW.
A bill in the state Assembly (A-4538) would have electric utilities finance offshore wind projects, with cost recovery from customers and 2.75% extra as a commission. The measure’s sponsor, Deputy Speaker John Burzichelli, is among lawmakers who say they are frustrated by the Board of Public Utilities’ failure to adopt financing regulations that could help get wind development going.
Four former governors announced their opposition to South Jersey Gas’s proposed pipeline through the Pinelands National Reserve. Meanwhile, a member of the Pinelands Commission who spoke against the project was ordered by the state attorney general’s office to stay out of the proceedings because of what the office said was a conflict of interest.
At a Dec. 4 meeting, members of a commission committee erupted against the proposal and the pressure they felt to grant the waiver required for it. The commission may vote on the project — intended to repower the BL England generating plant — on Jan. 10.
State law required New Jersey auto dealers to sell more electric vehicles in the next several years, but it’s not clear that customers will buy the cars, in part because inadequate charging infrastructure is creating “range anxiety” in potential buyers.
Meanwhile, lawmakers are trying to address the absence of a task force that was supposed to have figured out how to implement the 2003 law setting zero-emission vehicle goals.
Solar City opened an 8,500-square-foot operations center in Camden County to serve its growing market in the area. The company, which installs residential solar systems, says it has about 1,800 customers in the state. It said the location allows crews to travel to sites and install systems often in less than a day, a big improvement over projects that used to take up to three days.
The state Senate followed the Assembly in approving a measure authorizing the Board of Public Utilities to create a website for customers to compare competitive retail electricity prices. The bill (A-2132) allows the BPU to require retailers to submit information.
Demolition specialists imploded twin 300-foot-tall smokestacks last week at Duke Energy Progress’s H.F. Lee Steam Plant in Goldsboro. The coal-fired plant was opened in 1950. It was replaced a year ago by a 920 MW natural gas plant. More implosions are planned next spring to demolish the coal plant’s boilers.
The Utilities Commission approved a Duke Energy Carolinas experimental program that will allow energy-intensive customers to power new load — such as a new or expanded facility — from renewable sources.
Green Source Rider customers will ask for an annual amount of energy and renewable energy certificates to be produced or procured over a specific term. Duke will match the supply source and contract term request with generation from a Duke source or through a power purchase agreement with another supplier.
“We designed a program that responds to certain customer requests for more renewable energy, but that does not adversely affect other customers,” a company official said.
Rejecting citizens’ objections, the state Supreme Court upheld the Ohio Power Siting Board’s approval of Black Fork Wind Energy’s application to build an up-to-200 MW wind project in Crawford and Richland counties. Black Fork’s parent, Element Power, of Portland, Ore., expects construction to begin in 2015, after it secures power purchase contracts and reapplies for tax credits.
Appalachian Power sought State Corporation Commission permission for a $36 million improvement project on the company’s 36-mile portion of the Cloverdale-Lexington 500-kV line, a line it shares with Dominion Virginia Power. The project, to address reliability and market issues, is the utility’s alternative to a more extensive proposal that was rejected. APCO wants to put the improved facility in service in June 2016. At the same time, APCO asked for a $49.9 million distribution rate increase.
Senate Finance Committee Chairman Max Baucus released a discussion draft of legislation that would consolidate 42 energy tax incentives into two technology-neutral incentives for lower-emission electricity and transportation fuel.
But news that President Obama would appoint Baucus ambassador to China made the outlook for the proposal even more uncertain than it was already. Sen. Ron Wyden (D., OR), Baucus’ expected successor as chair, has not committed to support of Baucus’ package, but has been exploring technology-neutral options himself.
The Baucus draft would keep existing tax credits in place through the end of 2016. Facilities placed in service after then would receive a technology-neutral tax incentive based on greenhouse gas emission levels. While wind power’s credits would remain at about current levels, solar projects, which use the investment tax credit more than the production tax credit, could lose.
The Sierra Club filed suit over the federal government’s beleaguered FutureGen project, possibly adding to the years of delay the carbon capture and sequestration project has already had. The suit targets Ameren Energy Resources, which owns a plant in Meredosia, Ill., that is to be retrofitted for the government-supported project. Environmental permits for the project do not ensure sufficient controls, the Sierra Club said.
Delaware, Illinois and Maryland were among 15 states that urged the Environmental Protection Agency to let states use flexible approaches to cutting greenhouse gas emissions instead of requiring individual power plants to install emission controls. In a letter, the states — which also included Washington, California and Minnesota — said their flexible approaches have succeeded in reducing emissions, and argued their methods could be templates for others as EPA writes rules for existing power plants.
A bipartisan group of senators introduced legislation to loosen Dodd-Frank restrictions that have restricted public power utilities’ ability to engage in swap deals for risk management. The Public Power Risk Management Act (S.1802) is similar to a bill that passed the House unanimously.
The change would put municipal utilities on the same footing as other utilities, raising the limit on transactions for which a muni’s counterparty has to register as a swap dealer. The current low limit makes counterparties reluctant to engage in the transactions.
Natural gas will exceed coal as the largest single power generation source around 2035, the Energy Information Administration said. By 2040, EIA said in its preliminary annual energy outlook, gas will supply 35% of U.S. power and coal 32%. The agency sees average electricity use growing at about 0.9% a year.
The Department of Energy outlined near- and long-term performance targets for power grid storage, including an AC storage system with a capital cost of less than $250/kWh able to run for more than 4,000 cycles. The report was prepared for Senate Energy and Natural Resources Committee Chair Ron Wyden. “The expansion of the electricity system can be accelerated by the widespread deployment of energy storage, since storage can be a critical component of grid stability and resiliency,” DOE said.
Cooperatives in North Carolina, Pennsylvania, Kentucky and Virginia are among co-ops in 25 states that got Rural Utilities Service loans for power projects in the latest round of government awards. The total of $1.8 billion is mostly for power line upgrades and generation, but includes about $45 million for smart grid technology. On RUS’ latest list are EnergyUnited Electric Membership Corp. in North Carolina; Bedford Rural Electric Co-op in Pennsylvania; Cumberland Electric Membership in Tennessee and Kentucky; and BARC Electric Co-op in Virginia.
As USEC’s Megatons to Megawatts program ends, Dominion Resources noted its own role in burning up uranium from Russian nuclear warheads. According to the company, Dominion’s nuclear stations in Virginia, Connecticut and Wisconsin used the equivalent of 429 warheads. Dominion Virginia Power’s two North Anna reactors used the equivalent of 99 warheads and the two Surry reactors the equivalent of 136.
James Pearson, senior vice president and CFO, will begin reporting to President and CEO Anthony Alexander with the Jan. 1 retirement of Pearson’s boss, Mark Clark. Clark, executive vice president for finance and strategy served 37 years with the company.
John Judge, vice president and chief risk officer, will report to Pearson. The moves are among a number of changes the company said will expand the responsibilities of key executives and reflect its focus on its regulated businesses.
PJM last week began offering new ways to download Locational Marginal Price data from the PJM website with the introduction of a “data miner” application.
PJM Vice President for Market Operations Stu Bresler said the application was developed in response to stakeholder requests for a more efficient ways to download large amounts of data.
Data Miner Screen Shot (Source: PJM Interconnection, LLC)
The application allows querying and filtering by date range, pnodes and “topic,” with choices of xml of csv outputs. The data can be obtained through a user interface or scheduled for regular retrievals through a “rest-based” web service.
Four sets of data will initially be available, with others added later: DA LMP (daily LMP, energy prices); RT LMP (daily LMP, energy prices, Ancillary Services Optimizer); DA monthly aggregates (monthly LMP, monthly energy prices); RT monthly aggregates (monthly LMP, monthly energy prices, ASO).
Members will be able to continue using any code they developed to “scrape” the data previously.
Impacts: Defines times when interconnection request information will be exchanged and studied; Reinforces JOA requirements to impose the applicable study criteria; Describes Transmission Service Request studies to be performed.
Impacts: Changes section 6.3 to increase penalties for resources that fail to provide assigned amounts of Tier 2 Synchronized Reserve. Changes section 5.2.6 to clarify the requirements that must be satisfied in order for wind resources to be eligible to receive Lost Opportunity Cost (LOC) credits.
Members voted last week to expand the scope of the Energy Market Uplift Senior Task Force to incorporate reactive cost issues originally assigned to a separate panel.
The Markets and Reliability Committee approved a revised charter for the EMUSTF, which it created May 30 to minimize energy market up-lift charges and develop methodologies for allocating make-whole payments (see MRC Approvals 5/30/13.)
The changes incorporate into the charter the scope originally assigned to a subgroup on Day-Ahead Reliability and Reactive Cost Allocation (DARRCA). The DARRCA group met nine times from December 2012 through October 2013 and was attempting to create solution packages when the process “stalled,” PJM’s Dave Anders told the MRC.
“The consensus was that the issue would be better dealt with in the context of all uplift,” Anders said.
The task force continued its work under the expanded scope with a meeting Dec. 20.
