PJM briefed members Wednesday on manual changes documenting two improved methods for verifying demand response providers’ customer baselines (CBL).
The CBL is used to forecast how much power a resource would have used absent DR. The two methods being added to Manual 11 are already permitted and one is in limited use.
The Same Day (3 + 2) method bases the CBL on the average of three hours before event (after skipping one hour) and two hours after event (after skipping one hour). For an event occurring in hours ending 13-17, for example, PJM would average hours ending 9-11 and 19-20.
The Match Day (3-day average) method uses an average of the three non-event days with the most similar load to the non-event hours on the event day. The hour before and after the event are excluded from the “non-event” hours.
PJM officials gave the Transmission Expansion Advisory Committee a status report Thursday on their analysis of the 26 proposals for correcting stability problems at Artificial Island in South Jersey.
PJM’s first competitive transmission project under FERC Order 1000 attracted proposals from five utilities and three independent developers. The proposals ranged from $116 million to $1.5 billion. (Eight Companies Vie for Artificial Island Project)
Salem and Hope Creek Nuclear Reactors on Artificial Island. Photo Taken By Peretz Partensky from San Francisco, USA [CC-BY-2.0 (http://creativecommons.org/licenses/by/2.0)], via Wikimedia Commons
PJM’s Mark Sims told the TEAC that PJM planners wouldn’t be judging them on a “pass-fail” system but “don’t have the ability to analyze each one in excruciating detail.”
Sims said planners were conducting short circuit and thermal studies and hoped to have some initial findings at the next TEAC meeting. “We’re looking at projects as proposed” at this stage and not considering modifications to improve them, he added.
Sims also said PJM is seeking an outside engineer to help with the analysis. The consultant will help vet the developers’ cost estimates as well as providing “higher level information” for comparing the proposals, including issues such as line and river crossings.
In response to a question, Steve Herling, PJM vice president of planning, said public policy benefits of the proposals “can only be entertained if those states are on board to pay for those benefits.”
Sharon Segner, of LS Power, said one of her company’s two proposals includes at least $265 million in market efficiency benefits as a potential “tiebreaker” in the evaluations. The proposal, which envisions a new 230 kV line, has an estimated cost of $116 to $148 million.
Artificial Island is the home of the Salem and Hope Creek nuclear plants in Hancocks Bridge N.J.
The Planning Committee approved two alternatives to protect wind generators from being assigned artificially depressed capacity values due to curtailments ordered by PJM.
Under current policy, when wind generators are curtailed by PJM for any portion of a peak summer hour, the hour is excluded from the generator’s capacity credit calculation. (See Alternative Wind Capacity Calculations Yield Murky Results.)
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 hours with curtailments.
Metered data would be used for all hours without curtailments under both options. Units with no curtailments over peak summer hours would not be affected by either option.
Alternative 2 was approved by a 101-23 margin and will be the primary option considered by the Markets and Reliability Committee. The MRC also can select Alternative 3, which was approved by a narrower 68-40 margin.
Assuming MRC approval, the new procedure would be applied to summer 2013 when capacity credit calculations are finalized in December 2013.
The Market Implementation Committee Thursday endorsed changes to Manual 28: Operating Agreement Accounting.
Reason for change: Incorporating changes to lost opportunity cost compensation as approved by FERC.
Impacts:
Changes sections 5.2.6 and 5.2.8 (Operating Reserve & Reactive Services Lost Opportunity Cost Credits) to limit lost opportunity cost compensation to the lesser of a unit’s economic maximum or maximum facility output as approved in FERC Docket ER13-1200.
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 and 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.
Members hit the brakes Wednesday on a proposed new product for scheduling trades between PJM and the New York ISO.
PJM officials, who had planned to ask the Market Implementation Committee to endorse the proposal, postponed a vote in order to provide answers to members’ questions.
“The devil is in the details with this product,” said Jung Suh, of retailer Noble Americas Energy Solutions, LLC. He said his company’s traders would need to review the proposed rules and procedures before he could support the change.
Under the current system, according to PJM, 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. (See PJM, NYISO Tout New Option to Improve Power Scheduling.)
Other members had questions about the impact on balancing congestion and Financial Transmission Rights and asked for data to analyze price risks.
Ed Tatum, vice president of RTO & regulatory affairs for Old Dominion Electric Cooperative also said he needed more details before he could vote. “Based on what I’ve heard, it sounds like a good idea,” he said.
How much is too much? That’s what PJM officials want to know following May’s base capacity auction, in which an unprecedented volume of external resources cleared.
(Source: Monitoring Analytics LLC)
In the previous four base capacity auctions, cleared imports grew from about 3,000 MW to more than 4,500 MW. In this year’s auction, cleared imports jumped to more than 7,400 MW.
“Up until the last auction I would say we were well below our limits,” Steve Herling, PJM vice president of planning, told the Planning Committee Thursday. With the latest auction, PJM officials fear imports “may have approached, or even exceeded, the amount that can be reliably supported during actual emergency conditions.”
Officials outlined a proposed problem statement to develop a methodology for determining an import limit that would be used in the planning process and applied to future auctions. The committee will be asked to endorse the problem statement at its next meeting with a goal of obtaining FERC approval in time for the May 2014 base auction.
Establishing a cap will require revisions to the Reliability Assurance Agreement, which governs procedures for maintaining system reliability.
To clear in the auction, external generators, like internal resources, must be considered deliverable, meaning the capacity isn’t bottled locally and can get to the transmission system. Resources currently need nothing more than a request for firm transmission service in the transmission queue, said Herling, “which is virtually no hurdle at all.”
PJM officials are particularly concerned because the majority of the imports in this year’s auction are coming from MISO and other points west, with very little from the north or south.
West of PJM imports nearly doubled to 7,081 MW over last year’s auction, 4,723 MW of it from MISO and areas that will be integrated into MISO by the 2016/2017 Delivery Year.
Efforts to set a cap on imports will be closely scrutinized by PJM generators, who have been dismayed by falling capacity prices. Also watching closely will be MISO officials, who have complained to FERC that PJM’s modeling of cross border transmission deliverability is unfairly limiting its generation from competing in PJM’s capacity market.
PJM yesterday began inviting competitive proposals for transmission improvements to provide relief at its 25 most congested locations.
The top 25 “congestion events” are projected to cost $237.8 million in 2017 (97% of all congestion for the year), rising to $514 million (95% of the total) in 2023. Proposals for “market efficiency” projects to relieve the congestion will be accepted through Sept. 26.
The competitive solicitation is PJM’s second to be conducted under the rules of FERC Order 1000, which reduced transmission owners’ historic Rights of First Refusal and opened transmission projects to competition. See PJM Briefs TEAC on Artificial Island Proposals.
(Source: PJM Interconnection, LLC)
Eight of the 25 locations eligible for market efficiency projects are market-to-market (M2M) flowgates between PJM and MISO and would have to be approved by both regions. Three spots are located in Commonwealth Edison and two each in Dayton Power & Light, MetEd and PECO.
The top location on the 2017 list is the Breed 345 kV-Wheatland Power Facility 345 kV, a market-to-market line projected to bind for 3,063 hours at a cost of more than $59 million. Another M2M facility, the Pawnee 345 kV- Pawnee 138 kV transformer, is projected to bind for 4,806 hours at a cost of $34 million.
Within PJM, the top spot is the AP-South interface with Bedington-Black Oak, projected to bind for 942 hours at a cost of nearly $47 million.
In total, eight locations showed at least $20 million in congestions costs for study years 2017, 2020 or 2023.
To be considered by the PJM Board of Managers for inclusion in the Regional Transmission Expansion Plan, proposals must produce at least $1.25 in savings for every $1 in project cost.
The calculation of benefits will use PJM’s existing rules, which weigh reductions in production costs at 70% and changes in net load payments at 30%.
PJM’s Chuck Liebold said the joint operating agreement with MISO does not require opening of a competitive window for the M2M flowgates, which he said is being done on “an experimental basis.”
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.”
![Salem and Hope Creek Nuclear Reactors on Artificial Island. Photo Taken By Peretz Partensky from San Francisco, USA [CC-BY-2.0 (http://creativecommons.org/licenses/by/2.0)], via Wikimedia Commons](/ext/resources/2013/09/Salem_and_Hope_Creek_Nuclear_Reactors_7238282472.jpg)
