Page 1682 – RTO Insider

August 13, 2013

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%.

August 13, 2013

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.”

August 13, 2013

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.

August 13, 2013

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.

August 13, 2013

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.

August 13, 2013

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

August 8, 2013

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.

August 6, 2013

Imports, Not DR, Caused Heat Wave Price Crash

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) — 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.

August 6, 2013

MRC First Read on Proposed Manual Changes

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.

August 6, 2013

Analysis – JP Morgan Settlement: A Verdict on Electric Markets?

By Rich Heidorn Jr.

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.

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.