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.
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.
Summary of Answers
Many of the 64 questions submitted in writing were repetitive or had been addressed in previous presentations to the members. (See Focus on AEP Transformer, Prices in Heat Wave Review; Imports, Not DR, Caused Heat Wave Price Crash.)
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
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).
