The NRC grades each reactor based on data submitted quarterly by plant operators (“performance indicators”) and inspections by resident inspectors and regional staff. Its mid-year assessment places each operating unit within one of four levels of regulatory response, with the agency’s scrutiny increasing as plant performance declines:
The top-rated plants, judged to be meeting all of the agency’s objectives, are subject to the “baseline” inspection program.
Plants with no more than two white findings — indicating problems causing minimal reductions in safety margin — fall into the second category, subjecting them to additional inspections and oversight by NRC regional officials.
Reactors with “degraded” performance, for example those receiving a yellow finding indicating a moderate reduction in safety margin are subject to higher scrutiny, including involvement of senior regional officials.
NRC headquarters officials take part in scrutiny of plants with multiple yellow findings or a red finding, indicating a significant reduction in safety margin.
Not Operating: Plants with unacceptable reductions in safety margins are not permitted to operate and may have their licenses revoked.
The Markets and Reliability Committee Thursday reviewed two alternatives to protect wind generators from being assigned artificially depressed capacity values due to curtailments ordered by PJM. The committee will be asked to approve one of the alternatives at its next meeting.
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.
Under Alternative 2, state estimator data would be used to interpolate output for each five-minute period with curtailments. Under Alternative 3, forecast data from PJM operations — which is currently used for lost opportunity cost calculations — would be used for curtailment periods.
(Source: PJM Interconnection, LLC)
Both options would use metered data for all hours without curtailments. Units with no curtailments over peak summer hours would not be affected by either option.
The Planning Committee last month approved Alternative 2 by a 101-23 margin, making it the primary option MRC will consider Sept. 26. The MRC also can select Alternative 3, which was approved more narrowly, 68-40. (See Planning Committee OKs Relief for Wind Generators.)
PJM’s Tom Falin said Alternative 2 may be more accurate for short curtailments while Alternative 3 is more accurate for long curtailments. “The most important curtailments are the long ones,” Falin said. “They’re going to impact the average more than a five-minute interruption.”
An analysis released by PJM showed that Alternative 2 would have increased ratings for 21 wind generators with 12 reduced and two unchanged. Alternative 3 increased ratings for 24 generators and reduced them for 11. (See chart)
Any new procedure approved by would be applied to summer 2013 data when capacity credit calculations are finalized in December 2013.
The following issues generated little or no discussion among members when they were brought before the Markets and Reliability Committee for first readings Thursday. The issues will be brought to a vote at the next MRC meeting Sept. 26.
Below are brief descriptions of the issues along with their agenda numbers and links to prior coverage in RTO Insider.
6. COORDINATED TRANSACTION SCHEDULING
MRC will be asked to approve a new product for scheduling trades between PJM and the New York ISO.
Under the current system, power often flows from PJM into New York even when PJM’s prices are higher. The new product, Coordinated Transaction Scheduling (CTS), is intended to reduce uneconomic power flows between the two regions. Traders would be able to submit “price differential” bids that would clear when the price differences between New York and PJM exceed a threshold set by the bidder.
PJM officials had planned to ask the Market Implementation Committee to endorse the proposal Aug. 7 but postponed a vote to provide answers to members’ questions.
Addressing one of the questions that came up before the MIC, PJM’s Rebecca Carroll told MRC Thursday that PJM does not expect the new product to have any impact on balancing congestion, which results because of a change in transmission system capability between the day-ahead and real-time markets. (Negative balancing congestion occurs when the real-time transmission system cannot accommodate all the transactions scheduled day ahead; positive balancing congestion occurs when the real-time transmission capability increases above what was available day ahead.)
Carroll said the scheduling of external interchange transactions won’t affect transmission capability.
PJM and the Market Monitor will seek a vote on a joint proposal to boost penalties for resources that fall short of their synchronized reserve commitments. The measure, intended to address concerns that the current penalty structure is insufficient to ensure compliance, stalled at the Operating Committee in August as utilities called for more details. (See Bid to Boost Synch Reserve Penalties Stalls at OC.)
9. EFFICIENCY OF DEMAND RESPONSE REGISTRATION PROCESS
MRC will be asked to choose among three proposals for streamlining 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 LSE’s role in the process has been largely eliminated as a result of FERC Order 745. (See PJM Proposes Streamlined DR Registration.)
10. ENERGY MARKET UP-LIFT SENIOR TASK FORCE (EMUSTF) CHARTER
MRC will be asked to vote next month on a charter for the Energy Market Uplift Senior Task Force. The task force was created by MRC May 30 to conduct a broad review of its method of providing operating reserve payments. PJM said changes are needed to reduce growing uplift costs. (See MRC Approvals 5/30/13; PJM Proposes Operating Reserve Changes to Cut Uplift.)
12. PJM MANUALS
A. Manual 12: Energy and Ancillary Market Operations and Manual 27: OATT Accounting.
Reason for changes: The changes conform to new policies developed by the System Restoration Strategy Task Force on black start generation, critical load and restoration plans.
PJM will lose some existing black start capacity as a result of pending coal plant retirements. The changes are intended to increase the pool of potential resources. Tariff changes reflecting the new policies were filed with FERC July 9 (ER13-1911).
Section 7 of Manual 27 allows the cost of cross-zonal black start units to be allocated to multiple zones based on transmission owners’ critical load share.
Section 4.6 of Manual 12 governs the number of critical units in a zone and the ratio of black start generation to critical load in a zone. It also eliminates a restriction on the number of black start units at a station, allows units to provide service outside their zone and changes the time in which a unit must close to a dead bus.
PJM contact: Tom Hauske
B. Manual 01: Control Center and Data Exchange Requirements.
Reason for changes: The changes are necessary to comply with NERC Standard BAL-005-0.2b — Automatic Generation Control.
Impact: Creates a new tie line cut-in process requiring telemetry be in place prior to energization. Includes major changes to Section 5.3.5 (Tie Line Telemetry Specification) to provide more detailed requirements for Tie Line Telemetry and Attachment B to remove redundant text and streamline table. EOP-005-2 and EOP-008-1 requirements are updated.
FirstEnergy Corp.’s nuclear operating company will meet with the Nuclear Regulatory Commission Sept. 5 after security forces at the company’s Beaver Valley nuclear plant apparently failed part of a routine “force-on-force” exercise in April.
An environmental group asked Montana regulators for documents that may indicate whether PPL Montana is in talks to sell several power plants to NorthWestern Energy. PPL Montana, which owns 11 hydroelectric plants and several coal-fired plants, and NorthWestern, Montana’s largest electric utility, have refused to comment on rumors of a possible sale.
NRG Energy Inc., the largest independent U.S. electricity generator, may further expand its clean-energy portfolio after its purchase of Energy Curtailment Specialists Inc., an analyst said. NRG announced the purchase of Energy Curtailment in a statement without giving a price. Energy Curtailment manages more than 2 GW of demand response for at least 5,000 customers.
“We see the transaction as among a series of other potential moves for NRG,” an UBS Securities LLC analyst said. “Other potential ‘alternative energy’ investments to complement NRG’s retail offerings could include distributed solar generation.”
Duke Energy chief executive Lynn Good, who began work July 1, discussed her priorities, the coal ash pollution that has prompted state lawsuits and the future of electric service in an interview with The Charlotte Observer.
In an interview, Brad Davids, vice president of utility solutions with EnerNOC Inc., talked about the company’s evolving business model, big data and renewable energy.
“The future is not always 10 years away,” Energy Secretary Ernest Moniz warned in his first major policy address. Speaking at Columbia University’s Center on Global Energy, Moniz discussed President Obama’s climate action plan and said industry change will be driven by extreme weather, distributed generation, electric vehicles and pollution concerns.
After a wait of nearly two years, the Energy Department proposed energy efficiency rules for new commercial refrigeration equipment and walk-in coolers and freezers. The rules represent one of the Obama administration’s first steps to address climate change through executive authority since the president announced his climate action plan in June.
U.S. solar power capacity will exceed wind power generation in about a decade, outgoing FERC Chairman Jon Wellinghoff told Greentech Media. Wellinghoff predicted rooftop solar prices will drop from more than $4 per watt to $1 or $2. “It is going to be the dominant player,” Wellinghoff said. “Everybody’s roof is out there.”
Some analysts predict the U.S. will double its capacity of distributed solar within three years.
The U.S. Senate Permanent Subcommittee on Investigations asked the Federal Energy Regulatory Commission to turn over “key documents” from FERC’s probe of JPMorgan Chase & Co.
Democrat Carl Levin, who leads the panel, and John McCain, its ranking Republican, asked FERC to include a 70-page document outlining investigators’ findings, which was cited in articles by The New York Times. The regulator kept that document private when announcing a $410 million accord with JPMorgan last month.
Most people find it tough to get excited about regulators. But President Obama’s nomination of Ron Binz to head the Federal Energy Regulatory Commission is reason to sit up and take notice.
Energy companies are manipulating costs and other data to deny private and government landholders billions in oil and natural gas royalties, ProPublica alleges. Thousands of landowners are receiving far less money than they were promised by energy companies, with some receiving virtually nothing.
Federal law requires that royalty payments to landowners be no less than 12.5% of the oil and gas sales from their leases.
Coal boosters who hope carbon capture technology will ensure the fuel’s future will find little support in a new report conducted for planners in the Eastern Interconnection.
EPA’s proposed New Source Performance Standards for greenhouse gases will likely make it impossible to permit new coal-fired generation that doesn’t include Carbon Capture and Storage (CCS) technology.
But the report notes that the Department of Energy’s flagship CCS project, FutureGen in Illinois, “has experienced multiple delays and changes of scope and design [and] its prospects remain uncertain.”
Even if CCS becomes economical, the report concludes, 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.”
“… Any state-level incentives to support coal mining and encourage the use of coal face an uphill battle in contending with these challenges.”
(Source: EPA)
The report also predicts the retirement of more than 50 GW of current plants between 2013 and 2016, in addition to the approximately 12 GW retired during 2010 through 2012. Of the 269 GW of coal capacity in the Eastern Interconnection, about one-third is located in five states that fall all or partly within PJM: Ohio, Indiana, Pennsylvania, Illinois and West Virginia. The average age of coal units in these states will be nearly 50 years by 2015.
The study, “Current State and Future Direction of Coal-fired Power in the Eastern Interconnection,” was conducted by ICF International for the Eastern Interconnection States’ Planning Council and the National Association of Regulatory Utility Commissioners (NARUC) with funding from DOE.
The Markets and Reliability Committee approved agenda items 2, 4 and 5 unanimously Thursday. Details are below:
2. PJM MANUALS
A. Manual 28: Operating Agreement Accounting
Reason for change: Revises the manual to reflect Tariff changes regarding lost opportunity cost compensation, as approved by FERC in docket ER13-1200.
The changes regard the amount of lost opportunity costs that a generator receives when PJM ordered it to reduce its output to maintain system reliability.
PJM made the changes to ensure that generators were not rewarded for operating units above the Maximum Facility Output specified in their interconnection agreements.
PJM told FERC the change was needed to prevent generators from causing constraints by operating above their Maximum Facility Output and then being rewarded with lost opportunity cost payments when PJM orders them to reduce output.
The new rules limit lost opportunity cost compensation to the lesser of the Maximum Facility Output or Economic Maximum (the highest incremental megawatt output level the unit can achieve while following economic dispatch).
Impacts:
Changes sections 5.2.6 and 5.2.8 (Operating Reserve & Reactive Services Lost Opportunity Cost Credits) to limit lost opportunity cost compensation.
Section 7.2 (Shortage Pricing) amended to incorporate calculation details for non-synchronized reserve market lost opportunity costs.
Modifies section 5.3 (Operating Reserve) to correct errors and provide clarifications on exempting deviations during shortage conditions; adds revisions for associating interfaces to the East or West BOR regions.
Modifies sections: 5.2.3 to incorporate details of Lost Opportunity Cost Credit for Synchronous Condensing; 5.2.6 (Wind Lost Opportunity Cost) to align language with Tariff; 17.3 (Allocation of Annual and Monthly FTR Auction Revenues) to correct section reference.
PJM contact: Stan Williams
B. Manual 14B: PJM Region Transmission Planning Process
Reason for changes:Updates to reflect changes from FERC Order 1000, switch to two-year planning cycle and revised benefit/cost test for Market Efficiency projects.
Impact:
Separates Reliability and Market Efficiency into subsections
Adds a new section (2.1.2) to explain two-year planning cycle on Market Efficiency projects.
Changes to reflect Order 1000.
Changes energy market benefit calculation component of benefit/cost ratio for Market Efficiency projects eligible for regional cost allocation. The change in total energy production cost and change in load energy payments (previously weighted .70/.30) will be equally weighted.
PJM contact: Tim Horger
4. PARAMETER LIMITED SCHEDULES (PLS) REVISIONS
PJM will add new processes for generators seeking exemptions from operating parameters under changes endorsed by the MRC.
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.
Reason for change: The change will reduce administrative burdens on members.
Impact: The proposed change would create three types of exemptions:
Temporary Exception: A one-time exception of 30 days or less;
Period Exception: An exception lasting for at least 31 days but no more than one year during the 12 months between June 1 and May 31; and
Persistent Exception: An exception lasting for at least one year.
The changes will require revisions to Attachment K of the OATT, Schedule 1 of the Operating Agreement and section 2.3.4 of Manual 11: Energy & Ancillary Services Market Operations.
Assuming FERC approval, the changes will be effective Oct. 1.
PJM contact: Jacqui Hugee
5. STAKEHOLDER PROCESS ON TRIENNIAL CONE REVIEW
Members will consider changes to the Cost of New Entry (CONE) triennial review process under a problem statement and issue charge approved by the MRC. CONE values are used in PJM’s Reliability Price Model (RPM) to obtain capacity resources.
Reason for problem statement: PJM and members agreed to explore changes in the review process in a settlement approved by the Federal Energy Regulatory Commission in January (Docket No. ER12-513).
Impact: The inquiry will assess the use of the Handy-Whitman Index of public utility construction costs for adjusting CONE and consider other potential changes.
PJM is required to file Tariff changes with FERC in time for the 2014 triennial review or a status report if stakeholders are unable to reach consensus on changes.
Duke Energy agreed to quit burning coal at its share of the Wabash River Station power plant in western Indiana by June 2018 under a settlement with environmental and citizens groups that also calls for the company to increase its investments in renewable energy. The Natural Resources Defense Council ranked the Wabash River Station ninth among 25 coal-fired power plants it says are responsible for half of the mercury pollution in the Great Lakes region.
The settlement ends the activist groups’ challenge of Duke’s state air permit for its new $3.5 billion, coal-gasification plant in Edwardsport that went online this summer.
The Maryland Public Service Commission deferred action for one week on a request from Dan’s Mountain Wind Force LLC that its deadline to start building wind turbines be extended until Dec. 31, 2014. The PSC staff recommended approval of the extension request, saying the company had solved financial problems with an agreement with Exelon Corp. to fund construction and eventually purchase the project.
The U.S. Department of Energy and the state of New Jersey announced plans to design a small electric grid that will serve the state’s transit system and withstand the onslaught of storms like Superstorm Sandy. The micro grid will power the transit system’s rail operations between Newark, Jersey City and Hoboken.
The Chemical Industry Council of New Jersey and the state’s Division of Rate Counsel are balking at the expansion of PSEG’s solar power program, calling it too expensive. Public Service Electric & Gas won state regulatory approval of a plan to expand its “Solar4All” program by putting solar panels on factories, warehouses and landfills.
The chemical trade group says power costs for New Jersey industrial customers are already 59% higher than the national average.
Virtually all the nearly 5,000 comments filed on a proposed settlement of coal-ash lawsuits against Duke Energy opposed the deal or called for hearings on it. North Carolina filed suit in August against 12 Duke Energy coal-fired power plants where it said ash has polluted water.
The actions followed earlier suits against Duke’s Riverbend and Asheville plant, meaning that all 14 of Duke’s North Carolina coal plants are now the targets of state litigation.
Attorney General Roy Cooper said a state Supreme Court ruling should lead to lower utility profits and customer rates. The court backed Cooper’s appeal of Duke Carolinas’ 2011 rate case, which increased rates 7.2%, saying that the state Utilities Commission didn’t fully document the impact to customers of the return on equity granted Duke.
Cooper says state regulators should heed that ruling in reducing ROE in a rate case currently before them.
American Electric Power says there is no basis for an analyst’s report suggesting the company might sell its Ohio power plants. The report, from UBS Investment Research, comes as AEP is changing its structure to make the Ohio plants into a new subsidiary.
An AEP spokeswoman said there are “no current plans to sell that business.” AEP has about 9,000 MW of generation in Ohio, the company’s largest market among the 11 states where it has utility customers.
The spokesman for Ohio Gov. John Kasich mocked a Democratic legislator who asked the governor to release documents on the sudden resignation of the Ohio EPA’s chief water expert. “If she had her way, we’d all be living on a collective farm cooking organic quinoa over a dung fire,” Kasich’s spokesman said. “So, I think we’ll take her views in context.”
Meanwhile, the Associated Press reported that coal interests have contributed about $50,000 to Kasich and another $170,000 to state lawmakers since 2011.
Dayton Power and Light Co. won’t be offering gimmicky plans to lure customers as its Ohio market opens to retail competition, company officials said. “We’ll try to keep it on the straight and narrow,” CEO Phil Herrington told the Dayton Daily News in an interview.
The state Environmental Quality Board approved a draft regulation that officials said will strengthen environmental performance standards for oil and gas activities.
The proposal includes provisions covering exploration in parks and wildlife areas, spill prevention, waste management and the restoration of well sites after drilling. The rule also includes standards on the construction of gathering lines and temporary pipelines and provisions for identifying and monitoring abandoned wells.
The Department of Environmental Protection is recommending a 60-day public comment period on the new rules, with at least six public hearings across the state.
FirstEnergy Corp. estimated it will cost nearly $1 billion to decommission Three Mile Island Unit 2, which has been idle since its partial meltdown in 1979. The company disclosed the figure at a public hearing in Hershey Aug. 28.
FirstEnergy says it will continue to maintain the facility until Unit 1, operated by Exelon Nuclear, is shut down. Unit 1 has a license to operate until 2034.
The price of electricity for PPL Electric Utilities’ default residential customers will increase slightly while default commercial customers’ rates will drop. The new “price to compare” for residential customers will be 8.5 cents per kWh, up from the current 8.2 cents.
A federal judge threw out a lawsuit by conservation groups to block construction of a high-voltage power line by PPL and PSEG through the Delaware Water Gap National Recreation Area.
PPL agreed to pay a $60,000 fine to settle a complaint that it transferred a repair crew working on a high-priority outage in a 2011 snowstorm to fix a low-priority outage. The switch — a violation of the state utilities code — meant 1,326 customers in the higher-priority area were left in the dark about four hours longer than necessary.
A 14 MW solar project that will be Pennsylvania’s largest has won local land use approvals. Orion Renewable Energy Group, LLC should begin construction in about a year on the 100-acre site near Chambersburg in Franklin County.
In a joint forum on energy issues, Virginia gubernatorial hopefuls Terry McAuliffe and Ken Cuccinelli sparred over McAuliffe’s electric car company and Cuccinelli’s position on climate change and involvement in a dispute over gas royalties.
Natural gas-fired generation is the foundation of Dominion Virginia Power’s updated long-range energy plan, which also includes emissions-free resources to respond to U.S. greenhouse gas regulations.
The State Corporation Commission (SCC) has approved rules allowing Rappahannock Electric Cooperative customers to participate in a voluntary prepaid electric service program, the first offered in the state. The program allows a customer to prepay for electric service and permits the cooperative to suspend service when sufficient funds are not available.
Customers using the prepaid option will pay the same for electricity as those using traditional billing but will avoid having to pay a large deposit, late payment fees, or reconnection charges. The coop serves about 155,000 customers in a rural region from Fredericksburg to Front Royal.
Potomac Edison said it is complying with a West Virginia Public Service Commission investigation into the company’s billing practices, after residents complained about irregular billing and a lack of meter-reading.
The West Virginia Public Service Commission is seeking suggestions for simplifying its application process for homeowners seeking credits for rooftop solar systems.
PJM officials told members Thursday they may seek to lower the price cap on emergency demand response as a result of their review of the July 14-19 heat wave.
The comments came as PJM gave its most detailed explanation yet regarding the heat wave, with a lengthy presentation and answers to 64 questions submitted to officials after earlier presentations last month.
The more than two-hour presentation, which concluded the Markets and Reliability Committee meeting, seemed to exhaust most members’ questions. The Wilmington meeting room gradually emptied like a baseball stadium late in a lopsided game; by the end of the pre-Labor Day meeting, less than half of the members remained.
Much of the focus of the discussion was on PJM’s actions in the ATSI zone, where officials created a temporary interface July 17 to reflect the actions they were taking to ensure reliability.
(Source: PJM Interconnection, LLC)
PJM deployed emergency demand response in the zone on July 15, 16 and 18. During hours ending 16 through 18 on the 18th, DR set prices at $1,800/MWh, based on PJM rules that cap bids and offers at $1,000/MWh plus two times the reserve penalty factor (currently $400/MWh).
“The offer cap for emergency DR is probably too high at $1,000 when you add the two times the penalty,” said PJM Vice President of Market Operations Stu Bresler. Bresler recommended the limit be reduced to less than $1,000 plus only the primary reserve penalty. The cap “should be just short of [the price of] primary reserves,” Bresler said.
DR also was dispatched in the PJM, PPL and AEP South Canton zones on July 18 but did not set prices there. DR provided 92% to 102% of its obligations, depending on zone, PJM said.
Below is a summary of several key questions and answers. Unless otherwise attributed, direct quotes are from PJM’s written responses to member questions.
ATSI Interface
Q. Why did PJM create the pricing interface for the ATSI zone and not for AEP’s overloaded South Canton transformer? Was the interface necessary for dispatching demand response?
A. PJM created the ATSI Interface because its controlling actions were taken to address multiple post-contingency overloads in the area in addition to reducing load on the South Canton transformer. “Because a zonal action was being taken to limit imports into the zone in aggregate, the ATSI Interface provided the price signal that most appropriately reflected system conditions.”
PJM didn’t need the interface to call on Emergency DR. Without the interface, however, “other transmission constraints may have bound but the price impacts would have likely been inappropriately more localized.”
Some members said PJM should document in its manuals the process for adding localized interfaces in the future. PJM said it acted without giving members prior notice because of the urgency of the situation. But officials said they are “open to discussing a process that allows ample time for stakeholders to be notified of such new interfaces provided that it allows for flexibility for unforeseen system conditions to be priced accurately.”
South Canton Transformer
Q. What was the quantity and general characteristics (size, fuel-type, reason for outage) of the generator outages that resulted in the overload on the South Canton transformer? (Different quantities have been reported in different presentations, leading to some confusion as to the actual amount of generation that was unavailable).
A. PJM said it could not provide specifics on the generator outages, which totaled about 2,700 MW north and east of South Canton. “The response to this request would contain market sensitive information that PJM is not able to provide.”
Q. What is the limit on this transformer? What are the details of the transmission upgrade that will relieve the limit?
A. PJM was using a 95-degree normal rating of 1718 MVA, based on data submitted by AEP in November. The rating was raised to 1852 MVA on July 17 after AEP informed PJM that the rating submitted in November was incorrect. Officials said they don’t know the reason for the error.
AEP is scheduled to replace a disconnect switch on the transformer (RTEP project b1972) by October 4, which will increase the unit’s ratings to 2713 MVA (summer normal)/2922 MVA (summer emergency).
Operations
Q. Why did TVA issue a TLR 5b on July 15?
A. “TVA issued a TLR 5b [transmission loading relief] for a unit trip that caused an overload on their system. Both Firm and non-Firm contracts were curtailed as a result.”
The TLR cut 3,381 MW of imports to PJM, including 29 MW of firm imports.
Marji Philips, of Hess, questioned whether TVA could have avoided the TLR by redispatching its generation but decided against doing so because the TLR was cheaper. “TVA had a reputation for leaning on the system,” she said.
PJM CEO Terry Boston, former executive vice president of system operations for TVA, said that TVA’s problem was caused when a MISO generator that was providing counterflow reduced its output. As soon as the MISO unit returned, TVA’s problem was cured, Boston said. “It did not look like a market issue. It looked like a transmission issue,” Boston said.
Officials said they are working to improve their coordination with TVA. They said the incident raised questions about PJM’s control over external resources that are block scheduled and not pseudo-tied.
“We don’t have authority to reduce the output of external resources to relieve constraints,” Bryson said. The plants could keep running and sell their energy to other customers, he said.
Price Formation
Q. Was Shortage Pricing invoked? If not, why considering that a Maximum Emergency Generation was invoked?
A. “In this case, a Shortage event did not occur; reserves are not monitored in individual transmission zones such as the ATSI zone, and actual primary reserves were not less than the reserve requirement in either Mid-Atlantic and Dominion (MAD) or RTO. In real-time, hot weather procedures, including alerts of reserve shortages, are communicated to the market via Emergency Procedure messages.”
Demand Response
Q. Does Operations have any biases about using DR? Don’t want to use it? Want to use it? Want to use it to get practice? Feel DR is cumbersome so don’t like to use it?
A. “There are operational characteristics of the current DR products (2 hour lead time, majority only available in emergency, etc.) that make DR difficult for the operators to use efficiently and PJM has initiated stakeholder discussions to adjust these characteristics. The vast majority of Emergency DR is long lead.”
Reserve Sharing Agreements
Q. What actions will PJM take to support a neighboring RTO that is short of its reserves and how does this action impact PJM LMPs and charges (for instance, would PJM curtail DR/load Max Emergency Generation to support a neighboring RTO)?
A. PJM has reserve sharing agreements with the Northeast Power Coordinating Council (including NYISO and ISO-NE) and with Virginia-Carolinas (VACAR) (including Duke Energy Carolinas, Progress and South Carolina Electric & Gas).
“The nature of these agreements are `good utility practice.’ They are not requirements to provide reserves at all times. A company may elect to not respond if they cannot provide. Because responding to a request is not required, PJM does not rely on shared reserves and does not include them in reserve calculations for scheduling and dispatch.”
Bryson added: “We cover our needs from the ancillary markets. When our internal markets are not sufficient we can call on external reserves. We don’t rely on external reserves to meet NERC compliance requirements.”
Financial Transmission Rights (FTRs)
Q. What happened to balancing congestion and Financial Transmission Rights revenues on July 18?
A. Balancing Congestion costs for more than three hours totaled about $238,000, approximately 0.2% of total of FTR revenue inadequacy in July. “It wasn’t huge but it wasn’t insignificant,” said Bresler.
During the three hours of congestion, the day-ahead market flow averaged 8% higher than real-time. “Day-ahead congestion on [the] South Canton transformer and lower load resulted in reduced flows into the ATSI zone in the Day-ahead market, although not completely down to the Real-time level.”
Forecasting
(Source: PJM Interconnection)
Q. How did peak loads compare with PJM’s forecasts?
A. PJM’s hourly integrated peak load during the July 2013 heat wave was 158,156 MW, which occurred on July 18 for hour ending 17. The Day-Ahead Load Forecast for that hour was 157,033 MW (99.2% of actual load).
The 50/50 Projected Seasonal Peak Load Forecast from the January 2013 Load Forecast Report was 155,553 MW (98.3% of actual).
PJM would create rules allowing batteries, flywheels and other advanced energy storage technologies to participate in its capacity market under a problem statement presented to the Markets and Reliability Commission on first reading Thursday.
The proposal was introduced by Janette Kessler Dudley of Demansys Energy, which aggregates commercial and industrial customers for participation in the regulation market.
Dudley said the purpose of the problem statement is to establish enrollment procedures. Because advanced storage technologies — which also include thermal storage and compressed air — are still being developed, rules should not be limited to current products, she said.
In its second performance assessment of PJM’s capacity market, The Brattle Group recommended the RTO develop such rules: “Although the primary driver behind the development of these devices is to provide additional ancillary services to balance the grid, these resources could also participate in RPM.”
To do so, Brattle said, PJM will have to incorporate different ways for calculating capacity values. “Storage devices may be able to provide two types of capacity products: (1) an annual product, for devices that can sustain their capacity value for at least 10 hours; and (2) a limited product for devices that can sustain their capacity value for at least 6 but less than 10 hours.”
John Brodbeck, of Pepco, said he agreed PJM should consider the issue. “But we’re busy and here it is August. I don’t think there should be any changes” expected before the next base capacity auction in April, he said.
Energy storage received a boost from the Federal Energy Regulatory Commission in July with an order requiring PJM and other transmission providers to consider speed and accuracy in acquiring regulation resources. The order will make batteries, flywheels and other emerging technologies more competitive against slower-responding gas- and coal-fired generators in the regulation market. (See FERC Rule Boosts Storage, Renewables.)
