With two new types of demand response about to be introduced, members last week took steps to clarify rules on substitutions and maintenance outages for the products.
Extended Summer DR (7 days a week between May-Oct.) and Annual DR (12 months) will be available for the first time in the 2014/15 delivery year, joining the existing Limited DR (available for 10 dispatches annually on weekdays during June-Sept.).
Manual Change OKd for DR Substitution
Members last week approved changes to Manual 18: PJM Capacity Market governing how demand response providers may substitute for underperforming resources when called to dispatch.
Under the changes endorsed by the Market Implementation Committee Wednesday, the substitute and under-performing registration must:
Be located in the same dispatch area;
Have comparable capacity commitments (defined as the within ±25% or ±0.5 MW); and
Have the same designated lead time (e.g., long lead or short lead)
Under the rules, providers may use Limited DR to replace Annual DR but the substitution will not count against Limited’s 10 dispatch-per-year cap, said PJM’s Pete Langbein. Annual DR has no limits on the number of dispatches.
Maintenance Outages
The MIC also agreed to develop rules for approving maintenance outages for Annual DR.
The Tariff allows Annual DR to take maintenance outages between October and April, but members asked for rules to specify the application and approval procedures.
Under an Issue Charge approved by the MIC, the Demand Response Subcommittee will seek to develop manual changes that clarify what is eligible for a maintenance outage and how Curtailment Service Providers can apply for one. Members hope to complete the proposed changes for MIC endorsement by March.
PJM is adding more items to the to-do list resulting from the September heat wave, during which officials ordered limited load sheds to prevent a wider system collapse.
A 104-page analysis of the operational events and market impacts resulted in 22 recommendations, including 11 not previously announced (see sidebar). RTO officials briefed members on the report last week — ironically amidst the arctic blast that set a new winter demand record.
The analysis reads a bit like a thriller, documenting PJM dispatchers’ minute-by-minute decision-making — and identifying mistakes and missed opportunities for reducing or eliminating some of the five load sheds Sept. 9 and 10.
The city of Sturgis, Mich., emerges as a hero in the drama, as the city’s behind-the-meter generator and conservation measures by residents combined to provide 8 MW of relief, preventing a third day of load shedding on Sept. 11.
The report attributed the load sheds in part to inaccurate transmission, weather and load forecast models and also cited errors in synchronized reserve estimates. Load sheds did not significantly affect prices, the report concludes. But the dispatch of demand response caused both price increases and decreases and shortfalls in Financial Transmission Rights funding.
The report also illustrates the limits of demand response in relieving transmission constraints and identified operator errors and communication lapses.
Among the previously undisclosed details in the report:
Closing the South Akron-Clay 138 kV line might have prevented the Sept. 10 load shed in FirstEnergy’s Tod area near Warren, Ohio.
PJM might have avoided the load shed in the AEP Summit area Sept. 10 by dispatching 395 MW of combustion turbines that were off line. It did not do so because of a modeling error and because it was not monitoring a 138 kV line not under RTO control.
The Sept. 9 and 10 load sheds in AEP’s Pigeon River area in southern Michigan might have been avoided had a scheduled rebuilding of a 69-kV line been complete. PJM is working with AEP to “fast-track” the project, which is currently scheduled for completion in June 2017 under the Regional Transmission Expansion Plan.
PJM should have ordered the Sept. 10 load shed in Erie South area of Penelec 40 minutes earlier than it did, immediately after an analysis indicated it was the only solution to prevent a potential cascading outage. The load shed was preceded by the unplanned outage of two hydropower units (Seneca #1 and #2) that were scheduled to run at full output, a combined 421 MW.
The Environmental Protection Agency’s Mercury and Air Toxics Standards (MATS) indirectly contributed to one load shed. The planned outage of the South Canton 765 kV/345 kV transformer — required to support an upgrade needed prior to the retirement of five New Castle generators —contributed to less than 1 MW of the 16 MW FirstEnergy (ATSI) Tod area load shed.
Access to recently retired generation would not have eliminated the load sheds, although the five Bay Shore and East Lake generators retired in September 2012 could have reduced the Tod load shed by 75% and the AEP Summit outage by almost half.
Modeling
Many of the report’s findings and recommendations deal with PJM’s transmission modeling:
PJM’s contingency analysis of the Pigeon River area failed to include both a planned outage on the 69-kV Moore Park Tap-Industrial Park line and a relay limitation on the Lagrange-Howe (NIPSCO) section of the line. Because of the relay limitation, the most severe real-time contingency would automatically relay the Lagrange-Howe 69-kV line out of service. The Moore Park Tap-Industrial Park line was not modeled by PJM because it is below the 100-kV level; current PJM rules do not require reporting of outages below 100-kV.
Ratings on the Summit-Industrial 138 kV line, which figured in the 25 MW load shed in the AEP Summit area, were incorrectly listed as 251 MVA for normal (24 hours), emergency (four hours), and maximum (15 minute) conditions. “The reason for having different ratings is to give the dispatcher time to trend and validate the flows as well as take action to reduce the flows on the line,” the report said. “The impact of all the ratings being the same is there is no time for the dispatcher to perform anything but the most extreme action that must be taken once the load dump rating is reached. In this case, it was to issue the PCLLRW [Post Contingency Local Load Relief] and ultimately shed load.”
PJM incorrectly modeled a 138 kV series device, resulting in a 20 MVA difference between PJM and AEP’s state estimator solutions. PJM correctly compensated for the difference in real-time by conducting a cascading outage analysis at AEP’s lower threshold.
Because of the modeling error and because the Industrial-Summit 138 kV line is classified as a monitored priority 2 (MP 2) facility — which is above the 100 kV NERC Bulk Electric System (BES) level but not turned over to PJM for control — PJM did not dispatch 395 MW of combustion turbines that were off line, “which may have eliminated the need for the load shed.”
Synchronized Reserve
The heat wave also exposed problems with PJM’s estimates of synchronized reserves.
PJM issued a call for synchronized reserves Sept. 10, believing it had 1,665 MW available. It never got more than 400 MW of relief, with only 200 MW showing up in the first 10 minutes. As a result, the spinning event — which normally last only 10 minutes — ran for more than an hour.
The report concluded that some generation operators do not respond to PJM requests to confirm their synchronized reserves — called an Instantaneous Reserve Check (IRC) — or “provide stale or unreliable data.”
It also cited errors by operators who manually reduced output from some generating units to relieve transmission constraints Sept. 10. Because they failed to log the units as “Manual Dispatch,” PJM’s Security Constrained Economic Dispatch (SCED) software returned the units to a higher output and calculated available Tier 1 reserves from some units on the sending end of transmission constraints, although those units could not increase their output.
Heat Wave Forecasting Errors
RTO Temperatures During Sept. 13 Heat Wave (Source: PJM Interconnection LLC Technical Analysis of Operational Events and Market Impacts during the Sept. 13 Heat Wave)
Forecasting temperatures also proved problematic. Temperature forecasts for 10 PJM zones missed actual conditions by an average of 2 to 3 degrees over the three days, with errors as high as 10 degrees.
These contributed to load forecasts that fell up to 3.6% short. “Backcasting” — rerunning the load forecast using actual temperatures to separate the effect of the weather forecast errors — still produced average errors of 2% to 4.5%.
PJM said this is because its “Neural Net” forecasting tool relies on the previous day’s temperature and load trends. “When temperatures change significantly from one day to the next, it takes time for the Neural Net to catch up. Therefore the model inherently does not handle this first day of change well.”
Communications
The report also raises questions about how PJM operators communicated their actions to others on the grid and within PJM headquarters.
It noted that operations management chose not to call a System Operations Subcommittee Transmission (SOS-T) conference call on Sept. 10, because although “temperatures were higher than normal there were no forecasted events that would adversely impact the bulk electric system.” The calls are scheduled on an as-needed basis during emergency events to share information.
After the five load sheds, on Sept. 9 and 10, a conference call was held on Sept. 11. “While most SOS-Transmission members agreed that the communications of the conference call were adequate, some conference call participants stated that they would have liked more detailed information provided for the operations issues being discussed.”
Generic Logging
Dispatch staff logged the load sheds as generic transmission events because they were unaware of a category in the Emergency Procedures application for a “Local Load Relief Action.” Officials said dispatchers were unaware of the category because it had rarely if ever been used before and because its name did not exactly match the “Post Contingency Local Load Relief Action” instructions in PJM Manual 13: Emergency Operations. “As a result, those parties who depended on the Emergency Procedures application for notification were not notified of the load shed events.”
Many PJM officials, including the State Government Policy, Member Relations, Federal Government Affairs, and Corporate Communications departments were not informed about the load sheds, delaying their ability to communicate with stakeholders. “Dispatch has no formal notification checklist to follow except for certain emergency procedures steps requiring specific notifications pursuant to DOE, FERC, NERC, or PJM Manual requirements.”
Demand Response
The September heat wave illustrated that demand response — which proved a valuable tool during capacity shortages during the July heat wave — is less useful in relieving transmission constraints.
PJM dispatched DR on Sept. 10 and 11 after load forecasts fell 4,000 to 5,000 MW short of actual load. Of 740 MW called in ATSI and the South Canton subzone, 695 MW responded (94%).
Curtailment service providers provide street addresses for their resources but this information is not mapped electrically to the nearest substation. “When using these resources for transmission constraints, it is important for the dispatchers to know precisely where the curtailment will occur so that they can better understand the impact on the observed constraint,” the report said. “Too many DR resources on the wrong side of a constraint can make a constraint worse.”
The report identified 11 MW of demand response in the Summit area, which it said could have reduced, but not eliminated, that Sept. 10 load shed. The exact impact of the DR is unknown because of the lack of electrical mapping.
In addition, the long lead time of most of the DR resources does not lend itself well to addressing transmission constraints, which often need controlling actions within 30 minutes.
Starting in delivery year 2014/15, DR is required to respond on a subzonal basis if PJM establishes subzone the day before issuing a dispatch order. Only seven subzones are currently defined.
In December, members approved changes that will allow PJM operators more flexibility in dispatching demand response, including a reduction in the lead time to 30 minutes. (See Members OK DR Dispatch Rules after Late Amendments.)
Price Impact
The load sheds “did not have significant impacts on market outcomes,” the report concluded. Demand response, however, set prices in the ATSI zone at about $1,800 for hours ending 15 through 20 on Sept. 11 while causing prices to crash from more than $200 to less than $70 in some other regions in HE 16.
PJM said such a price drop usually results from a sudden influx of imports coming into PJM as price-takers. In this instance, it resulted from operators calling for more DR than was ultimately needed.
The DR deployment was called based on an expected peak load of 153,000 MW — nearly 6,600 MW above the actual peak. “Since PJM does not account for these MW as additional reserves, LMP is set by the marginal resource and demand response did not … set price when dispatched because this volume of demand response was not ultimately required,” the report explained.
After dropping below $70 in HE 16, prices rebounded to more than $200/MWh in HE 17.
FTR Funding Shortfalls
The dispatch of DR contributed to large differences between day-ahead and real-time prices in the ATSI zone, increasing FTR funding shortfalls for the month.
September 10 and 11 showed $29.3 million in FTR underfunding, more than half of the $56.3 million shortfall for the month. “Under the current market rules, FTR holders can be adversely impacted significantly by such emergency procedures taken to maintain system reliability when they have no impact to the Real-Time Market or system operations. PJM believes that this is a flaw in the market design that needs to be addressed.”
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.
