PJM and its Market Monitor still don’t agree on how the Financial Transmission Rights forfeiture rule should be applied. But they have at least reached consensus on how it has been applied to date.
PJM Vice President of Market Operations Stu Bresler presented the Markets and Reliability Committee Thursday with a description of the practice as currently applied by the monitor on increment and decrement transactions.
MRC Vote in May
The MRC will be asked in May to approve a manual change documenting the monitor’s current application of the rule, and a problem statement to determine how it should be interpreted in the future.
The rule is intended to prevent participants from submitting virtual bids that boost the value of their FTRs.
PJM discovered only recently that it disagreed with the criteria by which the monitor has been determining whether a company’s virtual bid is “at or near” the delivery or receipt buses of its FTR. PJM does the billing and has the authority to use its own determination if it disagrees with the monitor’s.
The monitor has been applying the penalty based on the net impact of virtual bids, triggering its application in less than one-tenth of 1% of trades.
PJM proposed a different calculation under which companies would lose any profit for an FTR if 75% or more of the energy injected or withdrawn by a virtual bid is reflected in a constrained path between FTR source and sink.
Market Monitor Joseph Bowring says PJM’s method would eliminate the rule’s value in policing gaming.
Stalemate
The Market Implementation Committee on March 6 voted in favor of PJM’s calculation method over the monitor’s. But the MRC rejected the PJM proposal March 28, leaving the RTO with no documentation for the practice.
Incorporating Volumes
Pat Sunseri, of Twin Cities Power, LLC, Thursday reiterated his request that PJM consider the volume of transactions in its application of the rule so that it doesn’t prevent legitimate hedging. “I think it makes a lot of sense to look at the volumetric issue,” Bresler agreed.
Carol Smoots, counsel to the Financial Marketers Coalition, said the rule should be reviewed by a task force reporting to the Market Implementation Committee rather than by the MRC, as envisioned in the Market Monitor’s proposed problem statement.
“A lot of very good trading doesn’t occur” because of the current interpretation, Smoots said. “That’s harmful to the market.”
Up-to congestion transactions were in the spotlight Thursday as the Markets and Reliability Committee:
Approved a definition of UTCs and a limit on trading of them;
Approved rules for deciding when UTC traders will forfeit Financial Transmission Rights; and
Heard first reading of proposed UTC credit requirements.
The trading limits and FTR forfeiture rules each passed with only one no vote. But the near unanimity dissolved when Andy Ott, PJM senior vice president for markets, reiterated his call for imposing fees on UTCs. Echoing a recommendation by Market Monitor Joseph Bowring, Ott said fixed fees on UTCs would help reduce uplift from Operating Reserve charges (see “PJM Proposes Operating Reserve Changes to Cut Uplift”).
Ott said PJM staff will perform an analysis on how UTCs both benefit market liquidity and increase system congestion. The analysis, which Ott said was necessary to “demystify” UTCs, also will compare them with other virtual trades — increment offers and decrement bids. “We need to have actual analysis, not suppositions, not opinions,” he said.
Carol Smoots, counsel to the Financial Marketers Coalition, said she was “disappointed that some sort of back room deal has been agreed to” regarding fees on UTCs.
Smoots said virtual trades already pay fees, including 40% of line loss charges. “To say the financial sector is not contributing to the cost of physical supply is not accurate,” she said.
Smoots said financial marketers have become a “convenient dumping ground” for fees because they are a small sector with limited voting power within PJM. “Being singled out because some folks don’t choose to use this product is very troubling,” she said.
Almost 95% of UTC trading volume came from financial traders in 2012 versus less than 5% by physical traders, according to the State of the Markets report.
J.P. Morgan vice president Robert O’Connell said fees could undercut UTCs’ role in creating liquidity and price convergence between the day-ahead and real-time markets. If the market-wide benefits of UTCs and other virtual trades outweigh their costs, O’Connell said, they shouldn’t pay any fees. Setting a fee “sends the message that `we don’t want you to converge any closer than $1 or $2,’ whatever the fee is.”
Jeffrey Mayes, general counsel for the monitor, said the definition of UTCs and any consideration of fees should be the subject of a transparent process beginning with a problem statement. “This proceeding isn’t going to do that,” he said.
Trading Limits
Reason for Change:
PJM proposed the cap because high bid volumes can make it difficult for the RTO’s day-ahead markets software to reach solutions.
Impact:
PJM can limit market participants to no more than 3,000 UTC transactions each in the day-ahead market when necessary for market operations. (A similar cap also applies to increment offers and decrement bids.)
The definition of market participant includes all sub-accounts established under the member. Affiliates will be treated as separate participants and have their bids counted individually.
The cap includes changes to the tariff, Operating Agreement and Manual 11.
FTR Forfeiture Rule
Reason for Change:
The rule is intended to prevent market manipulation — in this case, the submission of UTCs that boost the value of a participant’s FTRs.
Impact:
The rule is applied when those UTCs result in a higher LMP spread in the day-ahead market than in the real-time market.
Credit Requirements
Reason for Change:
UTC trading volumes have grown dramatically since 2010 (see chart) but have no credit requirements to protect market participants against defaults.
UTC Trading Volume 2006 – 2012 (Source: State of the Markets 2012)
Impact:
The Credit Subcommittee conducted polling on five alternative credit requirements for UTCs. PJM’s recommendation (Alternative F) won support from 91% of the 159 members responding to the survey, besting Alternative C with 48%.
The alternatives vary by how much collateral would be required and how much credit exposure the collateral would cover.
PJM’s proposal sets a bid screen based on the 70th percentile of the difference between the bid price and two-month rolling historical real-time costs for prevailing flow bids. It uses the 80th percentile for counterflows.
The cleared portfolio requirement is based on the 70th percentile of the difference between the cleared price and two-month rolling historical real-time costs for prevailing flows and 95th percentile for counterflows.
PJM analyzed the impact of the five proposals against trading results for April 2011, July 2012, and January 2013 to evaluate shoulder, summer and winter periods. It also looked at how they fared against the largest losses in the 10-month period between January 1 and Oct. 31, 2012. (See chart.)
“There is not likely one perfect set of credit requirements that would cover every period,” PJM Chief Financial Officer Suzanne Daugherty said. Daugherty said the goal was to find a balance that minimizes exposure without setting collateral requirements “so high that it shuts down the market.”
One alternative (Alternative E) showed the lowest remaining exposure and highest credit requirements in all scenarios while another (Alternative B) had the lowest credit requirements and left the highest remaining exposure. (See chart.)
UTC traders would need at least $200,000 in collateral, the same as for increment and decrement transactions.
Traders in Financial Transmission Rights are required to post $500,000. Daugherty said the lower requirement was justified because UTCs’ exposure is limited to a single day while FTR exposures range from one to 36 months.
Daugherty said that because all market participants benefit from the liquidity UTCs add, PJM doesn’t support limiting defaults to only those trading UTCs.
Next Steps:
The Credit Subcommittee has scheduled a conference call for 1 pm today to discuss the results of the committee’s polling on the five alternatives.
The Market Implementation Committee (MIC) is scheduled to consider the issue May 8 and submit MRC a single option to consider on May 30.
PJM called Thursday for a broad review of its method of providing Operating Reserve payments, saying changes were needed to reduce growing uplift costs.
Operating Reserves are “make whole” payments that ensure generators dispatched out of merit for system reliability don’t operate at a loss. Because they are collected through uplift charges and not reflected in day-ahead or real-time locational marginal prices, they cannot be hedged.
In 2012, operating reserve payments totaled a near record $649 million, 2.2% of total billing. Day-ahead operating reserve charges increased by about 90% in 2012, spiking in September after PJM increased the number of “must run” units dispatched in the day-ahead market.
PJM told the Markets and Reliability Committee it should consider an overhaul that incorporates more of the charges into LMPs.
MRC will be asked to vote on a proposed problem statement at its May 30 meeting. The effort, which would create a senior task force reporting to MRC, is expected to take at least a year.
PJM Senior Vice President of Markets Andy Ott said the focus should be a broad “re-look at the whole concept of uplift charges.”
Uplift charges often result from units that may be economic for two hours but must run for longer periods because of minimum run and ramping constraints. “It’s not an unusual circumstance. It happens every day, every hour,” Ott said.
Noha Sidhom, general counsel for Vel Energy, LLC, said her traders have reduced trading of increments and decrements because of price uncertainty. Incs and decs paid an average of about $2.50/MWh in operating reserve charges in 2012, with charges ranging from 20 cents to almost $18/MWh.
Ott said imposing fixed fees on virtual transactions to reflect their administrative costs and contribution to operating reserve charges would result in “a much more robust market.”
The Market Monitor’s State of the Markets report included a dozen recommendations on operating reserves. Among them were a review of the allocation of operating reserve charges to ensure that such charges are paid by all responsible for incurring them, including those making up-to congestion (UTC) transactions. (See “MRC Defines UTCs”)
The monitor estimated the number of UTC transactions would have been cut by two-thirds if they were subject to operating reserve charges.
WILMINGTON (April 25, 2013) – PJM announced today it is negotiating a new contract with its independent market monitor, Monitoring Analytics LLC, dropping plans to put the contract out for bid.
PJM General Counsel Vince Duane told the Markets and Reliability Committee that the RTO and Monitoring Analytics have agreed to extend the company’s current contract — due to expire in mid-2014 — through the end of next year.
Duane said PJM would issue a request for proposals (RFP) for monitoring services only if it cannot reach agreement with Monitoring Analytics on a new three-year contract beginning in 2015. Such an impasse “doesn’t seem terribly likely,” Duane said.
Duane said the PJM board made the decision to renew the Monitoring Analytics contract in the interests of “continuity” after receiving feedback from stakeholders.
In March, state regulators, industrial consumers and cooperatives sent the PJM board letters protesting its draft RFP, saying it contained terms that would undermine the independence and quality of the monitoring function.
Duane said yesterday that the new contract would include “reasonable measures” for the board to exercise oversight ensuring the monitor’s “accountability.” Duane promised to update members on the status of negotiations within two months, adding, “What we’d ask for at this time is some breathing room.”
Jeff Mayes, general counsel of Monitoring Analytics, said the company was confident that the two parties would reach agreement.
“We recognize the board’s important role in promoting an independent and capable monitoring function,” Mayes said in a statement. “We appreciate the board’s interest in fulfilling its responsibilities related to market monitoring under the tariff and FERC (Federal Energy Regulatory Commission) rules.”
A new contract with the monitoring firm would allow the board to avert another showdown with stakeholders over the monitor’s role.
Monitoring Analytics is headed by Joseph Bowring, a Ph.D. economist who has served as PJM’s market monitor since 1999. In April 2007, Bowring sparked a firestorm at a FERC technical conference when he accused then-PJM President Phil Harris and his allies of attempting to muzzle him by squelching his reports and cutting his budget.
Under the terms of a settlement approved by FERC, Bowring formed Monitoring Analytics to create an independent monitoring function (EL07-56-000) and was awarded a six-year contract.
The North American Electric Reliability Corp. (NERC) issued $9.2 million in fines for violations of its cybersecurity rules between 2008 and October 2012, half of all fines issued over that period.
Violations of NERC’s Critical Infrastructure Protection (CIP) rules were involved in six of the top 10 penalties, including a $725,000 fine in October.
At a time when Congress has been unable to agree on cybersecurity legislation to protect the rest of the U.S. economy, there’s no doubt that NERC and the Federal Energy Regulatory Commission take the cyber threat seriously.
The industry has come a long way in the three years since I was sitting in on NERC audits as a member of the FERC enforcement staff. The new CIP rules approved by FERC last week will cover more assets and add more controls. They’ll no doubt be good for the business of IT consultants. Regulated utilities that are allowed to put the costs in rate base will be more than happy to spend the money.
But will it be enough to prevent the potential for what former Defense Secretary Leon Panetta called a “cyber Pearl Harbor”?
While Congress gave FERC authority to issue fines of up to $1 million per day per violation, the fines issued to date have been puny relative to the earnings of the companies involved — less than one-tenth of one percent of the companies’ net income (see table)
Meanwhile, a decision by NERC and FERC to stop disclosing the identities of CIP violators — so as not to expose the violators’ vulnerabilities — has removed any reputational risk that companies might fear. Since September 2011, virtually none of those penalized for CIP violations has been named.
In announcing the new CIP rules last week, FERC commissioners emphasized their desire to emphasize compliance over punishment. That’s a reasonable approach, especially when the rules are new.
But if there is no reputational risk and the financial penalties are not material, don’t be surprised if some companies decide that it’s better business to cut corners on cybersecurity.
FERC ruled Friday that PJM must seek commission approval for new rules requiring demand response providers to provide officer certifications and additional information on their customers.
Acting on a complaint by three demand response providers, FERC said the changes required amendments to the PJM tariff and not just its manuals. Tariff changes require commission approval while manual changes don’t.
The rules, implemented March 28, require Curtailment Service Providers seeking to participate in capacity auctions to file “Sell Offer Plans,” including information about the provider’s customers. CSPs also must have a company officer sign a certification attesting to the company’s intent to physically deliver MWs.
The demand response providers filed the complaint April 3, saying the rules create unnecessary barriers to demand response participation in PJM’s capacity markets.
The plaintiffs’ procedural victory may be short-lived, however. In a statement concurring with the order, Commissioners Philip Moeller and Tony Clark indicated they would look favorably on the changes when PJM files them with the commission. “It appears that PJM has a legitimate need to require that demand resources provide certain information to substantiate offers to supply capacity,” the commissioners wrote.
The commissioners said the information was needed to prevent uncertainty that could “degrade the very purpose of PJM’s capacity market.”
The Commission approved criteria for determining which NERC activities are eligible for cost recovery under section 215 of the Federal Power Act.
Reason for change:
A FERC audit issued last year recommended the development of the criteria.
Impact:
The criteria restrict funding to “statutory” activities such as those involving the development, monitoring and enforcement of reliability standards, along with related training.
FERC will use the criteria in approving NERC’s annual budgets. Expenses approved by FERC are eligible for cost recovery from end users.
The commission ruled that the proposed criteria were generally acceptable but required replacement of the term “involve or support” with the term “necessary or appropriate” as the basis for funding. The commission said the former term was too broad and provided no practical limitation on funding.
Programmable electronic devices and communication networks including hardware, software and data.
Bulk Electric System (BES) Cyber Asset
A cyber asset which, if lost, damaged or misused would within 15 minutes affect the reliable operation of the grid. Redundancy of affected facilities is not considered when determining adverse impact. The definition excludes assets connected to the grid for 30 consecutive days or less that are used for data transfer, vulnerability assessments, maintenance, or troubleshooting.
WASHINGTON — The Federal Energy Regulatory Commission gave preliminary approval Thursday to a rewrite of cybersecurity rules and set a “bright line” requiring most facilities at 100 kV or higher to abide by them.
The commission issued four orders approving proposals by the North American Electric Reliability Corp. (NERC). Included were:
A new definition of transmission facilities covered by NERC reliability rules that upgrades the longstanding 100 kV threshold from a guideline to a directive. Regional discretion on the definition of Bulk Electric Systems (BES) is eliminated. (more)
Version 5 Critical Infrastructure Protection (CIP) standards, which replace the current “in or out” designations with a tiered approach which classify assets as high, medium or low impact. The commission said version 5’s improvements were important enough that companies now operating under CIP version 3 will skip CIP Version 4, due to take effect date, April 1, 2014, and transition directly to version 5. (more)
New rules for generator interconnections that will eliminate the need for most generators to register as transmission operators. (more)
Criteria for determining which NERC activities are eligible for cost recovery. (more)
The commission issued a Notice of Proposed Rulemaking for four new reliability standards addressing vegetation management and facility connection requirements for generator interconnection facilities (also known as generator tie lines).
Reason for Changes:
FERC had encouraged NERC to identify reliability standards specific to generator owners and operators with interconnection facilities including transmission lines. Eliminating the need for generators to register under the transmission function will allow them to focus on reliability standards specific to them, NERC said.
Impact:
FAC-001-1 requires a Generator Owner to publish facility connection requirements when it executes an agreement to evaluate the reliability impact of interconnecting a third party facility to its tie line.
FAC-003-3 requires a Generator Owner to perform vegetation management on its tie line.
Standards PRC-004-2.1a (Analysis and Mitigation of Transmission and Generation Protection System Misoperations) and PRC-005-1.1b (Transmission and Generation Protection System Maintenance and Testing) establish generation owners’ responsibility for the FAC requirements as they apply to tie lines.
In most cases, NERC said, these are the only reliability standards that apply to generator interconnection facilities. The changes do not affect the requirement that generators comply with other reliability standards unrelated to tie lines, such as those covering system restoration plans and notification of equipment failures.
Generators currently registered under transmission functions will have to apply to change their certifications under the NERC Rules of Procedure.
