PJM is setting slightly lower targets for renewable power in its 2013 Regional Transmission Expansion Plan.
PJM’s Mark Simms briefed the Transmission Expansion Advisory Committee Thursday on the three scenarios the 2013 plan will evaluate for meeting state Renewable Portfolio Standards.
The 2013 study envisions PJM generating and importing between about 38,000 and 41,000 MW of renewable power for planning year 2028, a reduction from the 2012 study, which projected up to approximately 43,000 MW in planning year 2027.
PJM spokesman Ray Dotter said the changes reflected updates to PJM’s load forecast, renewable capacity factors, and calculation methodology.
This year’s study tightens the range for the onshore wind scenarios to less than 10,000 MW (ranging from about 21,500 to 31,300) and reduces the low end of the range for offshore wind (to about 1,100 from 1,500 MW). The high end of offshore wind remains at 7,000 MW.
As in 2012, one of the scenarios envisions significant wind imports from MISO, though the amount is reduced to less than 13,000 (from 14,000 in the 2012 study), 40% of the RPS requirement for the PJM states.
Solar power is considered in all three scenarios, though in a reduced role in this year’s study, with a projected 5,600 MW, a 20% reduction from last year’s assumption.
Transmission owners flexed their muscles Wednesday, uniting to block proposals that would allow network load customers more frequent opportunities to switch to nodal pricing.
Two proposals by retail marketer Direct Energy to allow a limited number of such switches monthly were rejected by the Market Implementation Committee after utility representatives said the changes would create administrative problems for their electric distribution companies (EDCs).
David Scarpignato, head of PJM regulatory affairs for Direct Energy, said the changes would allow retail marketers to offer more innovative products. He said it would not have significant impact on EDCs or other market participants because it would cap switches at to 5% of the EDC network service peak load. (MIC Considers Loosening Rules on Zonal-Nodal Price Switching)
“This lines up the retail market to the wholesale market better,” he said. “For people who say they support competition, put your money where your mouth is.”
“The existing rules were well-vetted and balanced,” countered Scott Razze, manager of interconnection & arrangements for Pepco Holdings Inc. “Couching this as a minor change is a disservice.”
Few Make the Switch
The Members Committee in 2005 unanimously endorsed a Tariff change allowing the switch to nodal pricing. But after more than seven years under the new rules, all but 15% of PJM load is still using zonal pricing.
The rules give customers one chance a year to switch to nodal pricing, effective June 1 in alignment with the planning year. Customers must provide notice of their intention to switch by October or January depending on type of service.
Scarpignato said the annual window for switching has limited retail marketers’ ability to provide innovative products such as price responsive demand, which he said is most attractive to those with nodal pricing. If a customer’s current contract expires in April, it may not start shopping for a new provider until February, Scarpignato said. But the customer could not make the switch to nodal pricing until the following June — more than a year later.
Opponents of the Direct Energy’s proposal said they were concerned that remaining zonal customers could see their costs increase with a defection of others in their Energy Settlement Area to nodal pricing.
Others cited the impact of intra-year switches on the values of Financial Transmission Rights and Auction Revenue Rights. “That’s really what [the opposition to Direct’s proposal] is all about,” said Marji Philips, ISO services director for Hess Corp.
FTR Windfall
PJM expressed similar concern in explaining to the Federal Energy Regulatory Commission why stakeholders limited switches to once a year. “It is readily apparent that where the zonal price is higher than the price that would be associated with the customer’s specific bus distribution, FTRs initially allocated to hedge the customer’s congestion based on a zonal definition of its load will provide a windfall to that customer,” PJM said.
The merits of the issue became tangled with a parliamentary question when John Horstmann, director of RTO Affairs for Dayton Power and Light, asked for a poll on support for the current rules before a vote on Direct’s proposals.
A Bias Toward Change
John Brodbeck, director of regulatory affairs for Pepco, also called for the status quo poll. “We believe [the PJM issue process] has a bias toward change and a bias toward rapid change,” he said.
After originally promising a poll after a vote on Direct’s proposal, MIC Chairwoman Adrien Ford deferred a decision on Horstmann’s request to give her time to consult PJM rules. “Whatever we do today,” she noted, “could set precedent.”
Ford ultimately ruled that the poll would be taken first. The overwhelming support for the status quo — which was supported by a 98-38 (72%) vote — made the subsequent vote on Scarpignato’s proposals a formality.
Both proposals would have limited intra-year switches to 5% of the EDC network service peak load. As under current rules, customers would be barred from switching from nodal back to zonal without FERC approval.
Direct’s first proposal, which would have further limited switches to five per month per EDC, received less than 35% support. A second option, which would have set the monthly limit at 50 per EDC, won only 28% support.
Those supporting either of Direct’s proposals included retailers, demand response provider EnerNoc, the North Carolina Electric Membership Corp., industrial energy users, the New Jersey Public Power Association and Citigroup Energy, Inc.
Utilities (registered as transmission owners and generators) voted overwhelmingly in opposition.
Not the Last Word
The defeat at the MIC — where some individual TOs hold as many 15 votes — is not the final word.
Scarpignato can bring the proposal before the Markets and Reliability Committee, where a sector-weighted vote would limit the strength of the transmission owners to 20%.
An overworked transformer and the mobilization of demand response were the focus last week as members and PJM staff continued to discuss the mid-July heat wave.
PJM officials gave lengthy briefings to the Operating and Market Implementation committees, explaining their decisions to relieve an overload on the AEP transformer in the west and their mobilization of demand response in the PECO and PPL zones in the east.
The RTO said it will create a “Frequently Asked Questions” report to address the many issues raised by its response to the six-day heat wave, which resulted in the fourth-highest peak demand in PJM history on July 18. “We intend to kind of shake the tree” for lessons learned, said Mike Bryson, executive director of system operations.
Among the issues to be reviewed will be interchange volatility, demand response flexibility (lead time, minimum run time, offer price), the quality of generator data and the creation of localized interfaces.
(Source: PJM Interconnection, LLC)
Several members asked why demand response set real time prices in FirstEnergy’s ATSI control zone July 18 — peaking at about $1,800 — but not in the PECO and PPL zones, where DR also was mobilized. RTO prices hit $465 at 2 p.m. but plummeted to $52 at 3 p.m. before returning to more than $200 between 4 and 6 p.m. (See Imports, Not DR, Caused Heat Wave Price Crash.)
Jason Barker, wholesale market development director for Exelon, said the heat wave highlighted the need for a reserve product that allows the conservative operations employed by PJM dispatchers to be reflected in prices. “It blows our mind that we’re seeing $52 prices when you have gigawatts [of demand response and peakers dispatched] with prices much higher,” he said.
AEP/ATSI
(Source: PJM Interconnection, LLC)
AEP’s formerly anonymous South Canton #3 transformer became an unexpected constraint on July 18 although the problem hadn’t been foreseen in PJM’s day-ahead projections, PJM officials said.
The high loads became acute at the transformer because of an unplanned outage of more than 1,500 MW of generation east of the transformer. “If that [generation] had been on line we wouldn’t have had this problem,” said PJM’s Chris Pilong.
Load on the transformer increased steadily from 9 a.m., briefly exceeding its “Normal Limit” of about 1,900 MVA at about 1 p.m.
PJM officials called on demand response in the neighboring ATSI control zone to maintain flows through the transformer. “It was the biggest bang for your buck,” Pilong said.
Operators also created a temporary interface in the ATSI zone (see map) so that the region had a single LMP reflecting the DR prices.
“It was creating a constraint that accurately reflected the actions the operators took,” explained Adam Keech, director of wholesale market operations.
(Source: PJM Interconnection, LLC)
“The idea is to represent the physical reality that operators were dealing with,” said Stu Bresler, PJM vice president of market operations.
Keech said he wasn’t certain PJM had manual language covering “on the fly” creation of a localized interface. “I’m not sure if we’ve done this before,” he said.
DR Call
While it was the need to unload a constraint that led to the call for DR in the west, it was capacity limits across the system that led to the call for 1,000 MW of DR in PECO & PPL, officials said.
PJM must call for all DR in a zone because its rules don’t allow a call for fractional contributions from zones. “Because it was 1,000 MW we needed we chose PECO and PPL,” Bryson said. “If we needed more we would have called additional zones.”
The Pepco zone was rejected for a DR call because of a water main break in the Washington D.C. suburb of Prince George’s County that threatened to leave thousands without water for days.
If they had to call on demand response again on Friday, Pilong said “we most likely would have looked at different zones from PPL and PECO” because of the annual limits on DR calls for individual providers.
Officials said they expected DR to set energy prices across the entire RTO at their maximum of $1,800. The assumption proved wrong because of an unexpected influx of imports.
RTO LMPs hit $465 at 2 p.m. then plunged to $52 at 3 p.m. before returning to more than $200 between 4 and 6 p.m. The fall in prices came as net interchange jumped from less than 4,700 MW to nearly 7,700 MW.
When the imports arrived, PJM operators unloaded generation that was more expensive.
Keech said 2:40 p.m. to 4:40 p.m. was the minimum run time for demand response. From 4:40 p.m. to 5 p.m., he said, operators discussed whether to release DR. “We decided we didn’t need DR. We didn’t want $1,800 prices.”
Members Wednesday heard three proposals for streamlining the time consuming and error prone 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 EDC and LSE have 10 days to approve or deny the registration. If either rejects the application — for example because they were mistakenly associated with the customer — the process has to begin from the start.
PJM presented the Market Implementation Committee with proposed improvements from the Demand Response Subcommittee, which reached consensus on changes for emergency registrations but split over three options for changing economic registrations.
All three proposals remove the LSE from the Relevant Electric Retail Regulation Authority (RERRA) review process and eliminate LSE review of economic registrations for contractual obligations. (PJM said there has never been a denial because of contractual obligations.) All three also continue the EDCs’ review for economic registrations.
Option 2A, which received the most support within the subcommittee, would remove the LSE from economic registration review process.
Option 2B, which would simplify the LSE role and remove the requirement that they approve the registration also had substantial support.
The final option, 2C, which would keep the LSE role only for Day-Ahead registration review, was the least popular.
Negative Dec
Although Option 2A received the most support within the subcommittee, PJM and others were concerned about its handling of negative decs.
Currently, if a customer registers for economic DR and participates in the Day-Ahead market, PJM places a negative dec on behalf of the LSE for any cleared bids to offset the LSE’s demand bid. PJM would no longer place the negative dec under Option 2A.
PJM’s Andrea Yeaton, who presented the issue to the committee, said eliminating the negative dec can make it difficult for PJM to clear the market.
Jung Suh, of Noble Americas Energy Solutions, LLC, said the negative dec also is important to LSEs. “It protects us from financial harm,” he said.
The issue will be brought to a vote at the next MIC meeting.
The Market Implementation Committee Wednesday revised an issue charge it approved in March, adding a work activity inadvertently omitted from the original.
MIC agreed March 6 to consider changing the rules of the PJM capacity market to eliminate arbitrage opportunities between the Base Residual and Incremental capacity auctions. (MIC to Investigate Arbitrage in Capacity Market)
The issue charge brought to a vote mistakenly omitted a friendly amendment from Dave Mabry, energy management specialist for McNees, Wallace, & Nurick LLC, to include “capacity market costs” in the work activities.
PJM will add new processes for generators seeking exemptions from operating parameters under changes endorsed by the Market Implementation Committee Wednesday.
PJM’s generation parameters set defaults for different types and sizes of generators. The parameters cover 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.
The proposed change, the result of a year-long effort between PJM and the Market Monitor, 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.
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.
The Markets and Reliability Committee will be asked to endorse the changes at its next meeting. Assuming FERC approval, the changes will be effective Oct. 1.
The Operating and Market Implementation committees heard first reading last week on proposed manual changes governing PJM’s acquisition and deployment of black start resources.
The revisions conform to proposed Tariff changes developed by the System Restoration Strategy Task Force to increase the pool of potential resources. PJM expects to lose some existing black start capacity by 2015 as a result of the planned retirements of coal-fired generators.
The Tariff changes were submitted to the Federal Energy Regulatory Commission last month (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.
The MIC will be asked to endorse the changes at its next meeting.
In a split decision for financial traders, an appellate court Monday sent a dispute regarding PJM’s overcollection of line-loss revenues back to the Federal Energy Regulatory Commission.
The U.S. Court of Appeals for the D.C. Circuit upheld (Case No. 08-1386) FERC’s decision denying financial traders a share of surplus line-loss revenues. But the court ordered the commission to justify its rationale for demanding repayment of $37 million in surplus funds awarded to the traders in 2009.
The money at stake is the result of PJM’s “marginal loss pricing” method for collecting transmission line-loss payments, which treats every transmission as if it were the last transmission in the system. Because this method charges each buyer for the most problematic load transmission at the time, it collects far more than actual losses.
The alternative, average loss pricing, is more accurate in the aggregate, but overcharges loads close to generation and undercharges loads far from generation. It was outlawed in a 2006 FERC order.
The result of the marginal loss method is “a large pot of money,” as the court described it, with “no clear owner.” About $18 million was overcollected in 2011.
The commission approved PJM’s plan to distribute the surplus to recipients based on their contributions to the transmission system’s fixed costs. The commission said that financial traders – those who make “virtual” trades that are settled financially – had no claim because they do not transmit or take delivery of power.
FERC had ordered PJM not to use the money to “reimburse” market participants for their transmission loss payments, fearing that it would distort trading. The commission said any system that paid virtual marketers according to trading volume would create incentives for them to increase those disbursements by increasing trading volume through uneconomic trades.
The court Monday upheld FERC’s ruling denying virtual traders a share of the surplus, but said the commission had failed to justify its attempt to “claw back” $37 million distributed to the traders in 2009, before the commission changed its position on the matter.
The court said that the disparate treatment of virtual traders was justified because they “perform different roles from load-serving entities within the market and that the system will limit virtual marketers’ incentives to engage in market manipulation.”
But it said FERC had not justified its 2011 decision ordering PJM to “claw back” $37 million awarded to virtual marketers in 2009 for their share of fixed costs paid through up-to-congestion trades.
The court backed the traders’ argument that FERC’s about-face threatened to undermine their confidence in the market.
“In addition to explaining why it should have denied the refunds in the first place, FERC must explain why recouping is warranted. Because FERC failed to explain how it analyzed this crucial aspect of the case, we hold that the Commission acted arbitrarily and capriciously,” the court said. “It may well be that FERC’s policy reasons for effectively ordering recoupment outweigh its negative effects, but FERC must analyze that question, not ignore it. “
The court did not vacate FERC’s recoupment order, however, saying it was “plausible” that the commission could provide a sufficient argument for its decision.
Unexpected imports from New York — not the mobilization of demand response — caused power prices to crash July 18 after spiking to $465/MWh amid the hottest day of the summer, PJM officials told members Thursday.
LMP prices jumped from nearly $300 for the hour ending 1 p.m to $465 at 2 p.m. before plummeting to $52 an hour later, as PJM called into service 1,000 MW of demand response from the PPL and PECO zones. But the DR was dwarfed by an unexpected 3,000 MW increase in net interchange as thunderstorms dampened load in New York and New England.
Prices jumped again to $232 at 4 p.m. and continued rising through 6 pm as imports declined.
“Did DR cause prices to crash?” PJM Vice President of Market Operations Stu Bresler told the Markets and Reliability Committee, repeating what he said was a frequent question following the heat wave. “The answer is no.”
PJM Load and Prices: July 18, 2013(Source: PJM Interconnection, LLC)
It was the fourth-highest load ever for the PJM footprint (including ATSI, Duke Ohio and East Kentucky Power Cooperative, which are now part of the RTO), and the biggest day since July 2011.
The cause of the price drop was just one of the questions PJM officials will be trying to answer as they sift through data from the heat wave. They said there will be additional briefings on how the system fared at future meetings. “This is a very data rich, information rich opportunity,” said Executive Vice President for Markets Andy Ott.
PJM issued a Hot Weather Alert for the RTO, excluding the Commonwealth Edison zone, on Sunday July 14. The alert, which signals that demand and unit unavailability may be higher than forecast for an extended period, was scheduled to run through Thursday July 18.
On both Monday and Tuesday, PJM issued a call for long lead demand response and a maximum emergency generator action for the ATSI zone — notification that system conditions may require the use of emergency procedures — but cancelled both hours later.
Monday’s alerts were prompted in part by TVA’s cut of 3,300 MW of exports to PJM, a cut for which PJM had only about 10 minutes’ notice, according to Mike Bryson, executive director of system operations.
On Wednesday, when demand peaked at nearly 155,000 MW and temperatures rose as high as 96 degrees, PJM revised the alert to include the entire RTO.
At 12:40 p.m. Thursday, PJM again put out a call for long lead demand resources and declared a NERC EEA2 —signaling public appeals to reduce demand, possible voltage reductions, and interruptions of non-firm load — for the PECO, PPL and ATSI zones. Operators also issued a maximum emergency generator action for the ATSI zone.
Fearing they would lose 1,000 MW of imports from NYISO, which was running low on reserves, PJM operators mobilized 1,000 MW of demand response in the PPL and PECO zones.
Twenty minutes later, PJM added the AEP Canton subzone to the long lead DR and EEA2. The demand response was called on to relieve an overload on AEP’s South Canton #3 transformer, which briefly exceeded its “Normal Limit” of about 1,900 MW. (Bryson said the transformer is scheduled to be upgraded this fall.)
Operators also created a temporary interface in FirstEnergy’s ATSI control zone so that the region had a single LMP reflecting the DR prices.
Demand climbed throughout the afternoon and into early evening. RTO LMPs increased as well until midafternoon, when prices fell from $465 at 2 p.m. to $52 at 3 p.m. before returning to more than $200 between 4 and 6 p.m.
The fall in prices came as net interchange jumped from less than 4,700 MW to nearly 7,700 MW, including 700 MW of the 1,000 MW PJM feared it would lose from NYISO. Bresler said the unexpected rush of imports was due to the high prices in PJM, which “may have caused market participants to think prices would go even higher.”
At the same time, thunderstorms provided cooling relief in New York and New England, which had been running low on reserves.
In ATSI, prices dropped from $506 at 2 p.m. to $55 an hour later before spiking to $1,512 at 4 p.m. and $1,800 between 5 and 6 p.m. ATSI’s peak demand, 13,123 MW, was reduced by nearly 400 MW of emergency demand response.
PJM’s emergency measures ran through 6 p.m. as temperatures reached 98 in Philadelphia and RTO load peaked at 158,156 MW, the highest of the week. The peak would have been higher but for the assistance of 2,100 MW of demand response.
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: Adds a new section (2.1.2) on Market Efficiency projects and modifies planning time horizons.
Manual 28: Operating Agreement Accounting
Reason for changes: Incorporating changes to lost opportunity cost compensation as approved by FERC in Docket ER13-1200.
Impact:
Lost opportunity costs will be limited to the lesser of a unit’s economic maximum or maximum facility output.
Revises section 7.2 to incorporate details regarding shortage pricing (non-synchronized reserve lost opportunity cost calculations).
Clarifies revisions to section 5 regarding exempting deviations during shortage conditions and associating interfaces to the East or West BOR regions.
