Search
`
November 14, 2024

Posted on

PJM Considers Limit on Capacity Imports

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.

Cleared Capacity Imports (Source: Monitoring Analytics LLC)
(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.”

Of the 7,483 MW in imports that cleared in the auction, 4,788 MW (64%) had confirmed firm transmission service from the resource into PJM. The remainder was under study. (See Capacity Auction: New Generation, Imports Up, Prices, DR down.)

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.

(See FERC Likely to Increase Pressure on PJM-MISO Joint Market Talks.)

Posted on

PJM Invites Transmission Projects to Reduce Congestion

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. 

Projected Annual Congestion - Top 10 Locations (Source: PJM Interconnection, LLC)
(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%.

However, the proposals will be restudied next year, when PJM’s new benefit formula — which weights the impact on production costs and net load payments equally — takes effect. (MRC Approves New Benefit Test for Market Efficiency Projects)

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.”

Posted on

Lower Target for Renewables in 2013 RTEP

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.

Posted on

TOs Flex Muscles, Reject Retailer’s Nodal Pricing Bid

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%.

Posted on

Focus on AEP Transformer, Prices in Heat Wave Review

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.

LMP Comparison - July 18, 2013 (Source: PJM Interconnection, LLC)
(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

ATSI - South Canton #3 Transformer Timeline Combined for July 18, 2013 (Source: PJM Interconnection, LLC)
(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.

ATSI Interface Map: July 18, 2013 (Source: PJM Interconnection, LLC)
(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.”

Posted on

PJM Proposes Streamlined DR Registration

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.

Posted on

MIC Corrects Omission in Replacement Capacity Inquiry

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.

The amended issue charge was approved without opposition.

Posted on

MIC OKs New Process for Exceptions to Generator Parameters

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.

Posted on

MIC, OC Review Black Start Manual Changes

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).

Affected are manuals 12 and 27:

  • 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.

PJM Contact: Tom Hauske

Posted on

Split Decision for Financial Traders on PJM Line-Loss Collections

By Rich Heidorn Jr.

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.