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October 31, 2024

OC Ponders Increased Penalties for Poor SR Performers

The Operating Committee voted last week to consider certification requirements for resources providing Tier 2 synchronized reserves and increased penalties for those that fail to perform.

Tier 2 resources, which include combustion turbines operating at low capacity and demand response that can drop load, receive payments for being available to provide synchronized reserves when required — currently about three times per month.

No Guarantee of Performance

The resources are required to respond within 10 minutes but there is no certification process to ensure performance. “Right now I have absolutely no way of knowing if they have the capability” promised, said Kim Warshel, who presented the problem statement for PJM.

Tier 2 generation and demand resources each provided only 70% of the MWhs requested for events lasting 10 minutes or longer between 2009 and 2012. For all events over that period, DR provided only 53% of requested MWhs while generation provided 64% of requests.

Resources that fail to perform lose revenue for the hour of the call and also must provide reserves for three days without compensation.

In contrast with Tier 2 resources, which are paid regardless of whether they are called upon, Tier 1 resources are not paid except when they deliver the service. Tier 1 resources (generators following economic dispatch that are only partially loaded and can increase output within 10 minutes) are not required to perform when called upon.

Bruce Campbell, representing DR provider EnergyConnect, said PJM should consider both tougher penalties and higher incentives to improve performance.  Campbell said the three-day no-compensation penalty, initiated when PJM was calling on synchronized reserves every three days, is no longer in “alignment” with PJM’s reduced calls of once every 10 days.

The Operating Committee will consider the need for additional validation processes, disqualification criteria for poor performers and a requalification process for those disqualified.

The committee will recommend potential modifications to Manual 12 and the Tariff. Work is expected to be complete by Oct. 1.

FERC OKs PJM MOPR Exemptions; Rejects End to Unit-Specific Review

(May 3, 2013) — The Federal Energy Regulatory Commission yesterday handed PJM a split decision on disputed changes to its Minimum Offer Price Rule (MOPR), allowing the RTO to exempt two categories of resources but denying its request to eliminate its current unit-specific review (ER13-535).

In a unanimous decision, the commission approved PJM’s request to exempt certain self-supply and competitive entry resources from the unit-specific review. But it said eliminating the review for generators that don’t meet the exemptions was not just and reasonable.

“… We find that there may be resources that have lower competitive costs than the default offer floor, and these resources should have the opportunity to demonstrate their competitive entry costs,” the commission wrote. “In the base residual auction for 2012, resources that likely would not have qualified for either of PJM’s proposed exemptions were able to justify their net costs through the unit-specific review process.”

The commission also:

  • Rejected PJM’s request to extend mitigation from one to three years for units that fail the MOPR review.
  • Approved PJM’s proposed increase of its threshold for applying MOPR mitigation to 100% of the net Cost of New Entry (CONE) from the previous 90%.
  • Approved an expansion of the MOPR review to the entire RTO from constrained Locational Deliverability Areas.
  • Accepted PJM’s request to limit MOPR review to gas-fired combustion turbines, combined cycle and integrated gasification combined cycle (IGCC) units.
  • Rejected complaints that PJM’s process for approving the MOPR changes — which included negotiations between generators and load-serving entities to which consumer advocates and state regulators were not invited — meetings violated its Code of Conduct.

“By targeting those resources most likely to raise price suppression concerns (i.e., gas-fired resources), adopting exemptions for competitive entry and self-supply, and retaining the unit-specific review process for resources not eligible for the exemptions, we find that the MOPR as modified herein appropriately balances the need for mitigation of buyer-side market power against the risk of over-mitigation,” the commission wrote.

Regulators’ Reaction

Regulators in Maryland and New Jersey praised FERC for maintaining the unit-specific review.

“Rather than compete based on actual costs, incumbent generators enlisted PJM to try to rewrite the MOPR rules,” Bob Hanna, president of the New Jersey Board of Public Utilities, told PJM Insider. “FERC saw through their brazen attempt to saddle ratepayers with additional costs.  This is an important win for residents and businesses in New Jersey.”

Kimberly Frank, an attorney representing the Maryland Public Service Commission, said she was “hopeful that FERC’s order will provide competitive opportunities for all new entrants, but there is further work to be done.”

Representatives of generators did not immediately respond to requests for comment.

MOPR’s Creation 

MOPR was added to PJM’s capacity market rules — known as the Reliability Pricing Model (RPM) — in 2006 to prevent buyer-side market power.

Large net-buyers —those that buy more capacity from the market than they sell — can offer capacity at suppressed prices in an attempt to reduce the clearing price in PJM’s capacity auction. The strategy reduces the buyer’s overall costs as long as savings from the reduced clearing price exceeds its losses from selling capacity below-cost.

The commission said yesterday that such strategies — in addition to cutting generators’ revenues — are ultimately shortsighted for load as well.

“Ultimately, this strategy will prove more costly as existing generators become unable to recover their costs and therefore choose to exit the market, thus tightening capacity and raising prices,” the commission said. “Similarly, new merchant generators will be reluctant to enter a market in which their expected prices are susceptible to such reduction.”

Previous Rulings

The Commission issued several orders on MOPR between 2008 and 2011. In the 2011 case, generators challenged plans by the states of New Jersey and Maryland to procure 2,000 MW and 1,800 MW, respectively, of new generation to be bid into PJM’s capacity market auction at non-competitive prices.

As a result of the 2011 case, the IMM and PJM created a process for reviewing cost justifications submitted by generators that bid below the net Cost of New Entry.

PJM said some of its members called for changes to MOPR after its May 2012 capacity auction, in which several offers made by new gas-fired, new entry projects managed to clear with capacity price assurances from states. PJM said the 2012 results indicated the unit-specific review lacked transparency, including a lack of objective standards for reviewing sell offers. As a result, PJM said, state initiatives to subsidize new generation were interfering with the ability of the capacity market to send competitive price signals.

Based on recommendations from a report by The Brattle Group, PJM proposed eliminating the review process and instead creating MOPR exemptions for two types of resources:

  • Winners of competitive, non-discriminatory requests for proposals that are open to both new and existing resources; and
  • Self-supply resources bid into the auction by vertically-integrated LSEs that are:
    • not substantially “net-short” in the RPM; and
    • a resource if the owner (and its contractual counter-party, if relevant) are not substantially net-long in RPM and, as a result, would not benefit from depressed capacity prices.

Competitive-Entry Exemption

New resources built by a state regulated utility would not qualify for the exemption if their costs were recovered from ratepayers through a non-bypassable charge or if the resource received a state subsidy contingent on the resource clearing in the RPM.

A resource obtained through a state procurement process could qualify if the process had objective and transparent requirements and did not give preference to new resources over existing ones or restrict the type of resource that may participate.

Consumer advocates and regulators from Maryland and New Jersey contested the latter requirement, saying states should have the right to select capacity based on fuel diversity, environmental benefits or economic development.

The commission approved the exemption, agreeing that it would remove an “unnecessary barrier to entry.”

It rejected arguments that a procurement process should not be considered uncompetitive for being limited to new resources only.  “An RFP process available only to new resources is discriminatory and will not necessarily procure the lowest cost resources,” the commission ruled. “… Allowing such a resource to bid into RPM as a price taker would violate the intent of the MOPR to protect against the exercise of buyer-side market power.”

But the commission rejected PJM’s proposal that resources petition for FERC certification that the RFPs in which they were selected were competitive and non-discriminatory. The commission said that review should be done initially by PJM and its market monitor. Parties unhappy with the RTO determination can seek commission review.

Self-Supply Exemption

Based on data from the 2012 base residual auction (BRA), PJM proposed a set of net-short and net-long thresholds for eligibility under the self-supply exemption. (See  Thresholds for Self-Supply Resources Eligible for Exemption.)

The commission rejected complaints by consumer advocates and the New Jersey Board of Public Utilities that the self-supply exemption discriminates against restructured states by allowing regulators in traditional cost-of-service states to require their LSEs to build a resource and offer it into the market as a price taker while not allowing a restructured state like New Jersey to do so.

While vertically-integrated utilities in traditional states don’t have incentives to bid below costs, the commission said, “The incentives for uneconomic entry in restructured states differ because, in those market structures, LSEs rely largely on the market to meet their capacity obligations.”

The commission sided with intervenors who said that the thresholds’ accuracy and utility could degrade as market conditions change. While the last BRA benefited from surplus supply that created a relatively elastic capacity supply curve, an auction with tighter supplies would see an inelastic supply curve, so that offering additional capacity below cost will reduce prices at a steeper rate.

As a result, the commission required PJM to review and revise the thresholds periodically to reflect changing market conditions and assumptions.

Unit-specific Review

FERC rejected PJM’s request to eliminate the unit-specific review, saying that some units that fail to qualify for either of the two categorical exemptions may still be able to justify costs below PJM’s CONE threshold.

The commission urged PJM and its stakeholders to consider changing the unit-specific review to incorporate common modeling assumptions for establishing unit-specific offer floors and improvements in the calculation of Net CONE.

Resources Subject to MOPR

The commission approved PJM’s request to limit the MOPR to gas-fired generators, saying that the low construction costs and short development times of combustion turbines and combined cycle generators make them the most capable of suppressing capacity clearing prices. It required PJM to clarify whether cogeneration and combined heat and power facilities are eligible for exemption, even when they receive state and federal incentives.

The commission found, however, that PJM failed to justify limiting the MOPR exemption for Qualifying Facilities (QFs) to those owned by a capacity market seller. The commission ordered PJM provide further justification or modify its tariff to allow the exemption of QFs under contract to capacity market sellers.

PJM also was ordered to define “repowering” to clarify whether it includes both projects that increase capacity and those that don’t. PJM proposed that repowered gas generators be treated as a new resource under MOPR.

Net CONE Percentage Factors

FERC approved PJM’s proposal to raise the trigger initiating mitigation under MOPR from 90% of Net CONE to 100%.

PJM said that sparing sellers from the administrative burdens of the unit-specific process justified eliminating the 10% tolerance.

In addition, the commission “strongly encourage[d]” PJM to begin a stakeholder process to improve techniques for calculating Net CONE.

Mitigation Period

As it had done in its 2011 ruling, the commission again rejected a PJM proposal to increase MOPR mitigation from one to three years.

The commission said it agreed with the Maryland Public Service Commission that such a change could lead to “over-mitigation” by requiring resources to bid substantially above its costs. “The narrowed application of the MOPR to those deemed more likely to present price suppression concerns does not justify an unreasonably prolonged mitigation term,” the commission ruled.

Geographic Scope

The commission approved PJM’s proposal to expand the scope of MOPR — previously limited to constrained Locational Deliverability Areas — to the entire RTO.  The commission said it agreed “that the potential for the exercise of market power exists throughout the PJM region” and said the two categorical exemptions ensured that the larger geographic scope was unlikely to lead to over-mitigation.

Stakeholder Review

The commission rejected complaints that the stakeholder process that led to PJM’s MOPR filing warranted invalidating the filing.

Consumer advocates and state regulators in Maryland and New Jersey were outraged to learn that PJM and the market monitor had participated in confidential settlement negotiations among seven generating companies and five load-serving entities between July and September 2012. The resulting settlement was brought before the full membership in October and November, when it was ultimately approved by an 89% sector-weighted vote.

Kimberly Frank, the attorney for the Maryland PSC said FERC “missed an opportunity to call attention to the importance of an open, transparent, and fair RTO stakeholder process for all participants.  The process followed in this instance disregarded these fundamental principles and the proposal never should have been presented to FERC in these circumstances.”

Thresholds for Self-Supply Resources Eligible for Exemption

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.

Advanced Energy Storage Proposed

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.

E-Tag Privacy Rules OK’d

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 Seeks Proposals on NJ Transmission Project

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.

DR Inquiry to Proceed Despite MRC Rebuff

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 contact: Sarah Burlew

PJM Delays Action on CFTC Order

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.”

MRC Expands Black Start Study

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 Contact: Chantal Hendrzak

Back to the Drawing Board on FTR Forfeitures for Incs, Decs

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.”