PJM set the following net-short thresholds by customer type:
150 MW for a single-customer LSE;
1,000 MW for a public power entity;
1,800 MW for a multi-state public power entity, based on a PJM region-wide assessment (or 1,000 MW for three specified Locational Deliverability Areas); or
20 percent of the LSE’s RPM reliability requirement for an investor-owned LSE.
PJM proposed a graduated net-long scale, based on “estimated capacity obligations” (calculated on a three-year average basis along with specified criteria to determine which end-use customers to include) and the following maximum net-long thresholds:
70 MW for an estimated capacity obligation less than 500 MW;
15 percent of the LSE’s estimated capacity obligation for an estimated capacity obligation greater than or equal to 500 MW and less than 5,000 MW;
750 MW for an estimated capacity obligation greater than or equal to 5,000 MW and less than 15,000 MW;
1,000 MW for an estimated capacity obligation greater than or equal to 15,000 MW and less than 25,000 MW; and
4% of the LSE’s estimated capacity obligation capped at 1,300 MW for an estimated capacity obligation greater than or equal to 25,000 MW.
PJM would develop rules for including advanced energy storage technologies in its ancillary services and capacity markets under a problem statement given first read at the Markets and Reliability Committee meeting Thursday.
Although pumped hydro participates in PJM markets, the RTO has no rules for advanced technologies such as batteries, flywheels, thermal storage and compressed air, a representative of the Electric Storage Association told MRC members.
MRC will be asked to vote on the problem statement next month.
MRC approved revisions to the confidentiality provisions of its tariff to comply with FERC Order 771, requiring provision of e-Tag data to Independent System Operators, Market Monitoring Units and FERC. The new language extends confidentiality protections to counterparties that are not PJM members.
PJM yesterday announced the first transmission project open to non-utility transmission developers under the Federal Energy Regulatory Commission’s Order 1000.
PJM will accept proposals through June 28 to correct stability issues on Artificial Island in Hancocks Bridge, N.J., the site of the Salem and Hope Creek nuclear plants. The proposals will be evaluated PJM’s planning staff, which will share their results with the Transmission Expansion Advisory Committee.
FERC Order 1000 eliminated incumbent utilities’ Right of First Refusal on construction and operation of new transmission lines, opening the business to competition from independent transmission developers.
PJM said Thursday it is pressing on with an inquiry into demand response providers’ ability to fulfill their commitments, despite resistance from members.
PJM said its Capacity Senior Task Force would proceed with the inquiry although the MRC Thursday rejected a problem statement that would have considered the need for “enhanced resource verification measures.” The problem statement — which would have assigned the inquiry to the Demand Response Subcommittee because of the planned sunset of the task force — fell far short of the majority vote needed for approval.
Instead, PJM officials said they would continue the task force and proceed under its charter, which allows it to evaluate the “auditing of DR contracts.”
“It’s a fishing expedition to look for a problem,” said Dan Griffiths, a representative of DR provider Comverge. “Here we go again.”
PJM projects DR resources will be called upon from five to nine times annually beginning in 2014/15, up from one to five calls in 2013/14, as a result of declining Installed Generation Reserve Margins. PSEG proposed the problem statement, saying the increasing calls could result in “fatigue” among demand response resources.
Griffiths said PJM’s projections fail to account for capacity resulting from intermediate auctions and are too uncertain to be the basis of policymaking.
Response to FERC Order
Separately, PJM officials said they will respond to an April 19 Federal Energy Regulatory Commission order by drafting tariff changes to implement increased data requirements for demand resources participating in capacity auctions.
Acting in response to a complaint by Comverge and two other DR providers, FERC ruled that PJM must seek commission approval for requirements that DR providers to submit officer certifications and additional information on their customers. FERC said the changes required amendments to the PJM tariff — which require FERC approval — and not just its manuals.
Andy Ott, PJM senior vice president for markets, said the FERC order would not affect DR participation in the upcoming auction. “We have what [DR information] we need,” he said.
PJM Thursday postponed a vote on changes needed to comply with the Commodity Futures Trading Commission order exempting most PJM market participants from CFTC jurisdiction.
PJM Chief Financial Officer Suzanne Daugherty said the delay was needed to address questions from members about the proposed tariff and Operating Agreement changes, which expand financial marketers’ officer certification requirements.
The CFTC agreed March 28 to largely exempt from its regulations Financial Transmission Rights, day ahead and real time energy transactions, forward capacity transactions and reserve regulation transactions, sales that are already regulated by the Federal Energy Regulatory Commission. However, the CFTC said the exemption did not apply to financial market participants that cannot qualify as “appropriate persons” under the Commodity Exchange Act (CEA).
PJM responded April 7 by announcing it may deny trading privileges to as many as 55 small market participants if they are unable to qualify for the exemption. PJM said the change was necessary for the RTO to avoid being deemed a swap dealer and becoming subject to CFTC reporting requirements.
Captive Customers
J.P. Morgan vice president Robert O’Connell said PJM’s officer certification requirements are unnecessarily complex compared with those of the New York ISO. He suggested that PJM has been less responsive to member complaints about paperwork requirements because it has “captive customers.”
If PJM members had alternatives for trading in PJM “there would be more thought given to person on the other side of the table,” O’Connell said.
Daugherty said PJM staff would attempt to simplify the requirements but was unable to accept companies’ Securities and Exchange Commission certifications, as O’Connell requested.
In preparing the changes needed to comply with the CFTC order, PJM officials discovered Operating Agreement language that raises questions about PJM Settlement Inc.’s independent authority to seek asset recovery following a trading participant’s default. Officials said they will propose deletion of the language, which appears to require a member vote before beginning collection efforts.
“Telling you about [PJM’s case] can be very detrimental to the legal position we’re in” by publicly exposing weaknesses in the RTO’s case, said PJM General Counsel Vince Duane. Instead, he said PJM would continue its current practice of “private bilateral conversations with those who are closest to the situation or most impacted by it.”
Citing reliability concerns, the Markets and Reliability Committee agreed Thursday to expand the scope of a task force exploring compensation and incentives for black start generators.
The revised charter for the System Restoration Strategy Task Force will allow the group to consider changes to black start procurement, cost allocation and compensation, including “back stop” options if response to PJM’s voluntary request for resources leaves gaps in coverage.
Dana Horton, of AEP, noted that much of PJM’s black start capability is provided by coal-fired units scheduled for retirement. “We’ve never had a need to replace so many black start units,” he said.
The MRC approved the change over the objection of several members, who said PJM should evaluate the impact of changes approved in February before it considers additional ones. The motion to approve the revised charter was approved by acclimation, with 19 no votes.
MRC in February broadened its definition of “critical load” and increased the number of generators that could restore service to the load following a disruption. MRC also said black start units in one zone will be allowed to help restart generation in neighboring zones, allowing more efficient use of existing resources.
Michael Kormos, PJM senior vice president of operations, said the RTO won’t know the impact of the changes until it gets the results of its solicitation for black start generators at the end of 2013. “To start that conversation at that time would be too late [to prepare] for 2015,” Kormos said. “It’s going to put us in a big hole.”
Chantal Hendrzak, facilitator of the taskforce, said the group will research potential incentives for quick-starting units and how other RTOs procure and compensate black start resources.
Steve Lieberman, of Old Dominion Electric Cooperative, said the task force should consider all of the compensation other RTOs provide generators, not just black start compensation. Lieberman joined Bill Schofield, representative of the PJM Public Power Coalition, in calling the expanded charter premature.
Gloria Godson, vice president of federal regulatory policy for Pepco Holdings Inc., who noted her company owns no generation, supported the expanded study. “We don’t have credible responses” to the solicitations, she said. “Something needs to change.”
Dave Weaver, Exelon’s director of transmission operation and planning, also cited the coal retirements in calling for a broader charter. “I’m not convinced the changes we’ve made, although good changes,” are enough, Weaver said. “The iron in the ground remains the same … To me it’s really irresponsible to not have this plan in place.”
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.
