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.
Are RTO market rules too clumsy and complicated to prevent gaming and protect consumers?
That’s the question on the minds of many observers following federal regulators’ $410 million-dollar settlement with JPMorgan Chase last week.
The settlement between the Federal Energy Regulatory Commission and JP Morgan Ventures Energy Corp. resulted from schemes that turned money-losing natural gas-fired generators in California and Michigan into profit centers.
It was the fourth major enforcement action over manipulation of the electric markets in the last two years, following earlier FERC cases against Deutsche Bank AG, Barclays PLC and Constellation Energy Group Inc. and a Justice Department antitrust settlement with Morgan Stanley and KeySpan.
Regulators said the JP Morgan settlement, which included a $285 million fine and disgorgement of $125 million in unjust profits, showed FERC has dramatically improved enforcement since Congress gave the agency tougher penalties in the wake of the Enron scandal.
But consumer advocates and other critics say regulators’ enforcement actions have neither provided sufficient deterrent nor made consumers and honest market participants whole. Moreover, some say regulators will never be able to catch up with clever traders looking to exploit the rules.
Traders Smarter than Regulators?
“You have to wonder whether bureaucrats constructing byzantine regulatory systems that attempt to create a market within a government-controlled sector ever ask themselves: Are we simply developing arbitrage opportunities for Wall Streeters twice as smart as we are?” asked CNBC columnists John Carney and Jeff Cox.
“FERC and the ISOs built a dumb system that rewarded a modicum of perfectly transparent gamesmanship,” wrote financial industry blogger Matt Levine. “JPMorgan gamed them in the obvious and perfectly transparent way,”
Tyson Slocum, director of Public Citizen’s Energy Program, said the repeated instances of market manipulation are an indictment of FERC’s philosophy of regulation through competitive markets. By replacing its review of individual wholesale electric tariffs with market-based rates, Slocum said, “FERC outsourced federal law enforcement to the mall cops of the industry, so-called Independent System Operators (ISOs), private organizations with internal voting structures dominated by power sellers and utilities.”
If FERC won’t return to the prior regulatory regime, Slocum said, “People representing the interests of household consumers must serve on the [RTO boards] and hold a majority of voting shares. The organizations should be subject to Freedom of Information Act requests, and all meetings must be held before the public.”
FERC found that JP Morgan used 12 bidding strategies to profit from uneconomic power plants, all designed to exploit market rules intended to make generators whole when market prices don’t cover operating costs. At times, JP Morgan was paid $999 per MWh when the market price was $12.
`Historic’ Settlement
FERC Commissioner Tony Clark said that last week’s “historic [settlement] … sends a strong signal that market manipulation is being taken seriously” while allowing immediate refunds to consumers “rather than after a long multi-year court proceeding.”
California ISO General Counsel Nancy Saracino said the fact that the scheme was uncovered by the ISO proves the effectiveness of enforcement mechanisms created to ensure competitive markets result in just and reasonable prices.
FERC Chairman Jon Wellinghoff emphasized in an interview on CNBC that the $125 million JP Morgan scheme was “only about 1%” as large as the 2000-1 Enron scandal, which cost West Coast consumers an estimated $10 billion.
“Activities in organized, competitive wholesale electricity markets are subject to scrutiny by multiple parties. They are carefully monitored by the ISOs/RTOs themselves, by the respective market monitors and by the FERC,” PJM spokesman Ray Dotter said issued this statement. “Detecting and correcting uncompetitive behavior in the PJM region has been successful.”
PJM Market Monitor Joe Bowring rejected suggestions that the repeated instances of fraud by electric traders was an argument for a return to cost-of-service regulation.
“All markets have complex rules. Look at the financial markets,” he told RTO Insider in an interview yesterday. There’s nothing uncompetitive or bureaucratic about it.”
“Competition has, in my view, been very effective in reducing prices,” he added. “But there will always be people trying to exploit the rules.”
No Deterrent
Critics said the JP Morgan case and its predecessors showed that regulators are unable or unwilling to provide real deterrence.
Blythe Masters, JP Morgan
JP Morgan’s $285 million fine was little more than twice the profits FERC estimated the company made in the scheme and little more than a day’s worth of revenues for the banking giant, which generated nearly $94 billion in revenues and $21 billion in profits last year. The settlement also allowed the traders and executives involved to keep their jobs, including head of Global Commodities Blythe Masters, who gained notoriety for helping develop credit default swaps, a derivative that figured largely in the 2008 financial crisis. A JP Morgan spokesman confirmed to RTO Insider that the employees remain with the company.
“The incentive remains for outfits like JPMorgan to stretch the rules to the breaking point — if they get caught, the cost is tolerable; if not, the returns are fabulous,” wrote Los Angeles Times columnist Michael Hiltzik. “It will have no more deterrent effect on white-collar wrongdoing at JPMorgan or anywhere else than telling its traders they’ve got to take the Ferrari to work instead of the Lamborghini, though they can still take the Lambo to the beach house.”
Public Citizen called on JP Morgan to fire Masters and on FERC to revoke the company’s market-based rates. “The most powerful sanction FERC can invoke is to no longer allow JP Morgan to engage in the charade of deregulated energy markets,” Slocum said. In November, FERC announced it was suspending JP Morgan’s right to sell power at market-based rates for six months because it had lied to California and FERC staffers investigating the scheme.
Consumers Made Whole?
Others, including Massachusetts Sens. Elizabeth Warren and Ed Markey, said they were not convinced the settlement would make consumers whole.
In a paper published in the Energy Law Journal in November, attorney Paul B. Mohler concluded that consumers are less likely to be made whole when rates are found to be unjust and unreasonable under market-based rates than under traditional cost-based regulation.
The disgorgement also doesn’t compensate generators whose legitimate bids were rejected by CAISO and MISO. And in the case of California, it resulted in the dispatch of 1950s and 1960s vintage steam boilers which are less efficient and produce more emissions than more modern plants.
Regulators Playing Catch-up
Still others say the case and those involving other large banks and utilities are proof that — more than a decade after the Enron scandal, and eight years since Congress gave FERC the power to levy heavier fines — regulators are powerless to stop gaming of market rules.
JP Morgan’s scheme ran for more than two years between September 2010 and November 2012. The company’s traders gamed CAISO’s software, alternating high bids and low bids in a way that took advantage of the ISO’s make whole rules but maximized the company’s revenues. MISO, which can manually reject bids it considered suspicious, caught the scam more quickly. While FERC estimates JP Morgan made $124 million in unjust profits in California, the agency estimated only $1 million in improper payments in MISO.
“ISO market overseers seemed always to be behind the curve,” said Hiltzik. “The ISO had to submit new market rates and regulations for FERC approval five times … in its effort to wipe out Morgan’s scheming.”
JP Morgan thought so little of the risk of getting caught that, remarkably, 10 of the 12 schemes identified by FERC were launched after regulators began investigating the company.
“The record thus far indicates that manipulative schemes can go on for months, even years, before they’re uncovered by regulators,” said Hiltzik. “When will we finally learn about the ones that may be taking place today?”
The Enron scandal stopped many states from transitioning to competition from traditional ratemaking. The criticisms raised by the recent cases aren’t yet widespread enough to cause Congress to turn back the clock on competitive markets. But if traders continue to see gaming the rules as a path to easy profits, RTOs won’t be able to take public support for granted.
Constraints that can be quickly and cheaply resolved would be included in the Regional Transmission Expansion Plan (RTEP) under a proposal given first reading at the Markets and Reliability Committee meeting Thursday.
PJM will ask MRC at its next meeting to endorse Tariff revisions allowing the RTO to add “easily resolved constraints” to the RTEP.
Before posting the planning parameters for each Base Residual Auction, PJM staff would be required to identify Locational Deliverability Areas in which the Capacity Emergency Transfer Limit is less than 1.15 times the Capacity Emergency Transfer Objective. Upgrades that raise the ratio above 115% would be added to the RTEP if they:
Cost less than $5 million;
Can be completed within 36 months or prior to June 1 of the Delivery Year; and
Does not duplicate customer-funded upgrades already in the transmission queue (e.g., one whose cost is assigned to an interconnection customer).
The proposal was approved easily in a vote by the Capacity Senior Task Force.
MRC members heard first reading on a problem statement to review potential changes to the Cost of New Entry (CONE) triennial review process. 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 of problem statement: The inquiry will assess the use of the Handy-Whitman Index of public utility construction costs for adjusting CONE and 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.
PJM members will be asked tomorrow to approve a new scheduling option for transactions into the New York ISO to reduce uneconomic power flows.
Under the current system, PJM’s Stan Williams told the Markets and Reliability Committee Thursday, power often flows from PJM into New York even when PJM’s prices are higher.
To improve the alignment of energy scheduling with interface prices, PJM and NYISO are proposing creation of an additional product that would allow participants to submit “price differential” bids that would clear when prices in New York exceed those in PJM above a threshold set by the bidder.
The Coordinated Transaction Scheduling (CTS) proposal will be brought to a vote at the next MRC meeting if it is approved at tomorrow’s Market Implementation Committee meeting.
PJM says the new product should increase forward price transparency and price convergence between PJM and NYISO.
A cost benefit analysis found that the change would have reduced total production costs in the two RTOs by as much as $26 million in 2012. PJM officials said they had not calculated how much the savings would have been reduced by generator make whole payments resulting from the change.
The biggest opportunities for savings will come when the price differential between the two RTOs is relatively low. Analysis showed prices could be reduced in about half the hours when the price difference is $5/MWh but only 13% of the hours when the difference is $15.
CTS Interface bids would be scheduled based on the projected price difference between PJM and NYISO at the interface. It would use PJM’s Intermediate Term Security Constrained Economic Dispatch (IT SCED) application, which has a two hour look-ahead capability.
The application correctly predicted prices about 60% of the time when the price differential is $5 or less. Williams acknowledged the tool was much less reliable when the price differential is higher. Williams said PJM plans to begin posting the forecasts publicly next spring and is attempting to improve its accuracy.
Bob O’Connell, vice president and compliance manager for J.P. Morgan Ventures Energy Corp., said members shouldn’t vote on the proposal until they have evaluated the risks of relying on the forecasting tool.
He also said the changes could increase balancing congestion, which would penalize Financial Transmission Rights holders. “FTR holders get no benefit from CTS,” he said.
Williams said the changes shouldn’t hurt FTR holders and should reduce price volatility.
CTS Interface Bids would have as many as four bid curves and up to 11 $/MW pairs. The option would be in addition to current hourly evaluations of traditional wheel-through transactions and intra-hour evaluations of traditional LMP bids and offers.
Credit requirements on the new scheduling option would be based on the higher of the 97th percentile historical (prior year) hourly price for the node or the 15-minute IT SCED price forecast for the node.
The issue has been under discussion with NYISO since November 2012. The new scheduling product would require approval of the Federal Energy Regulatory Commission.
