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December 20, 2024

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MIC OKs Options to Reduce FTR Shortfalls

The Market Implementation Committee gave preliminary approval Wednesday to two proposals for lowering the risk of FTR revenue shortfalls.

The two proposals from the Financial Transmission Rights Task Force (FTRTF) received near-unanimous support, while a third option failed with less than 40% support and a vote on a fourth option was postponed.

All of the proposals were designed to eliminate modeling differences between the energy and Financial Transmission Rights (FTR) markets that contribute to FTR funding shortfalls.

The two proposals approved for consideration by the Markets and Reliability Committee reduce or remove infeasibilities in the FTR model and may allow increased counter flow FTRs to clear.

The four proposals were whittled down from more than 20 options the task force considered in eight meetings since October.

PJM’s Tim Horger said an analysis for one constraint found more than a $15 million improvement in FTR adequacy. However, he added, “we’re not guaranteeing anything with this.”

Under the first option (FTR Task Force option 2J), PJM “may model normal facility capability limits, if possible, for all Stage 1A over allocated facilities in FTR Auctions.”

The second option (option 3G), would allow PJM to “model normal facility capability limits, if possible, on facilities which are infeasible as a result of modeled transmission outages in monthly FTR Auctions.”

The other two options would attempt to reduce FTR funding deficits by lowering capability in FTR auctions rather than reducing infeasibilities.

The rejected proposal (option 2K) would have allowed PJM to “reduce capability, if possible, on facilities that have historically caused FTR underfunding in FTR auctions.”

MIC voted to table consideration of the fourth proposal (Long Term Auction Option) until the Federal Energy Regulatory Commission rules on FirstEnergy’s complaint over FTR underfunding (EL12-19-000). That proposal would have reduced “capability in Long Term FTR Auctions … from 100% to 50% of available capability after reserving ARR capability.”

All the proposals would guarantee ARR target allocations and ensure that self-scheduled FTRs are not impacted.

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MIC OKs UTC Credit Requirement

The Market Implementation Committee endorsed a first-ever credit requirement for up-to-congestion transactions. The new rule, a consensus resulting from 12 Credit Subcommittee meetings since December 2011, will be brought before the Markets and Reliability Committee May 30.

Reason for Change:

UTC trading volumes have grown dramatically since 2010 but there are no credit requirements to protect market participants against defaults.

Impact: Bid screen and cleared portfolio credit requirements are based on a percentile of the difference between each member’s bid or cleared price and the two-month rolling average of real-time value per path.

Bid Screen Credit:

  • Prevailing flow paths: 70th percentile
  • Counterflow paths: 80th percentile

Cleared Portfolio Credit:

  • Prevailing flow paths: 70th percentile
  • Counterflow paths: 95th percentile

Minimum Financial Participation Requirements — the same minimum requirements as for increment and decrement transactions:

  • tangible net worth of at least $500,000 or
  • tangible assets of at least $5 million, or
  • posting $200,000 of financial security against which the member may not trade, plus a 10% reduction in additional collateral.

UTC-credit-requirement-performance-vs.-4-scenariosPJM analyzed the impact of the proposals against trading results for April 2011, July 2012, and Jan. 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 Jan. 1 and Oct. 31, 2012.

The proposal covered 95% or more of bid exposure for each scenario except for January 2013, when it covered 82%. Excess collateral ranged from a low of $1.9 million (January 2012) to a high of $8 million (July 2012). Excess collateral is concentrated in members with high bid volumes. (See chart.)

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Substation Sabotage Raises Concerns over NERC Alerts

NERC’s delayed and muted response to the sabotage of a Pacific Gas & Electric Co. substation April 16 has some electric industry officials concerned.

One or more gunmen breached a security fence and shot and damaged seven of eight transformers at PG&E’s Metcalf substation near San Jose about 2 a.m. The shooting prompted the California Independent System Operator to issue an alert asking residents in the region to cut their electricity use.

But the seriousness of the sabotage was slow to spread elsewhere in the electric industry. PJM didn’t receive an alert from the North American Electric Reliability Corp. until two days later, Mike Bryson, executive director of system operations, told the Operating Committee last week. The incident “was a lot worse than it appeared to be when we got the alert,” Bryson said.

Bryson said the NERC official who authored the alert believed “it went out later than he would like and didn’t get the reaction it should have.” An alert sent the following day by the SERC Reliability Corp. made clear the seriousness of the incident, Bryson said.

NERC and SERC told PJM Insider the alerts are confidential and would not be made public. The shooting occurred minutes after someone cut underground fiber optic cables a half mile from the substation, briefly knocking out phone and 911 service in the area. Law enforcement officials believe the two incidents are related.

Bryson said the industry gets more than 10 reports annually of shootings at transmission lines but most incidents are far less serious than the April 16 event.

The incident underscored a risk raised last year by Jon Wellinghoff, chairman of the Federal Energy Regulatory Commission. Wellinghoff told Bloomberg News that he feared saboteurs with guns could target transformers. Transformers, which are usually protected only by chain-link fences, are often custom built and can take 18 to 36 months to replace, Wellinghoff said.

An attacker “could get 200 yards away with a .22 rifle and take the whole thing out,” Wellinghoff said. The physical security of the grid “is an equal if not greater issue” than cybersecurity, he added.

Cyber Threat Raised

Separately, the Department of Homeland Security warned last week of a heightened risk of a cyber attack on water and electric utilities.

DHS’s Industrial Control Systems Cyber Emergency Response Team (ICS-CERT) reported “increasing hostility” against “U.S. critical infrastructure organizations,” The Washington Post reported, quoting from the alert. “Adversary intent extends beyond intellectual property theft to include the use of cyber to disrupt … control processes.”

The alert included indicators that companies can use to detect attacks and recommended countermeasures. Industry officials told the Post that the level of detail in the alert was evidence that President Obama’s February executive order — which directed the executive branch to increase information sharing with industry — was having an impact.

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PJM Outlines ‘Crisper’ Approach to Stakeholder Initiatives

PJM last week announced a two-step process for defining new initiatives and tools prioritizing its growing stakeholder workload.

The Market Implementation Committee will be the first to implement the new procedure, which will separate the voting on problem statements (defining the problem, situation or opportunity to address) from voting on issue charges (defining which body will study the issue, their goals and deadlines).

MIC Chairwoman Adrien Foley said it will result in a “crisper” process than the current practice, in which the two votes are combined, generally a month after the issue is presented on first reading. The new process will allow a vote on the problem statement on first read; those that are approved will have a vote on the issue charge a month later.

If stakeholders assign the issue to a new task force or work group, it will also require a charter to set the objectives and milestones for the group.

The process will be rolled out to other committees after testing in the MIC.

Work Plan

Foley also presented the MIC with its first “Work Plan,” listing the status and projected schedule of 21 current issues being pursued by MIC and nine subcommittees, task forces and work groups. The work plan, which includes a meeting schedule, is intended as a way to set priorities and budget stakeholders’ time.

The first issue considered under the plan was a problem statement by Market Monitor Joseph Bowring that was approved by MIC in April. It called for inves­ti­gating whether traders could be manip­u­lat­ing PJM’s inter­face pric­ing points by break­ing sched­ules into mul­ti­ple “back-to-back” transactions. (See “MIC to Probe ‘Sham Scheduling’.”)

After receiving comments from stakeholders and Bowring, Foley said the issue would be started “as soon as practical.”

Voting App, Self-Serve Registration

MIC also heard about enhancements that will allow members to cast votes with their smartphones, a capability that was offered to tablet users in February. The changes are expected to be complete this summer.

PJM also is developing a self-service web application that will allow members to update the names of their voting representatives on committee rosters without filing forms with the RTO. The improvements also will allow the use of the committee voting application in additional committee meetings (e.g., Operating Committee, Market Implementation Committee). PJM plans to solicit member feedback on the changes this summer.

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CIP Audit Finds 4 Potential Violations

Last month’s audit of PJM’s adherence to Critical Infrastructure Protection (CIP) standards may result in up to four potential violations, PJM officials told the Operating Committee May 7.

Two of the issues were reported by PJM before the audit by ReliabilityFirst Corp. and SERC Reliability Corp. and may not result in violation notices, PJM spokesman Ray Dotter said. Dotter said the other two were minor issues that posed no risk to the system. “In fact, it was noted that PJM’s strong compliance program and its commitment to compliance allowed” completion of the audit in only two and one-half days, half the time scheduled, Dotter added.

The draft report detailing the violations has not been released.

Correction: In its April 16 edition, PJM Insider incorrectly referred to a ReliabilityFirst/SERC audit that had no findings as a CIP audit. That reference was to a separate RFC/SERC audit focused on transmission system operations and planning.

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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.

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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.”

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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.

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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.

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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.