By Rich Heidorn Jr.

State regulators, consumer advocates, generators and the Independent Market Monitor have asked the Federal Energy Regulatory Commission to modify its June 9 order largely approving PJM’s Capacity Performance plan.

Most of the rehearing requests were filed Thursday, along with PJM’s submission of a 556-page compliance filing responding to the commission’s request for changes to its plan.

Maryland and D.C. regulators asked the commission to reverse the order, while generators sought relaxation of penalty provisions. Two filings seek expedited review before PJM’s “transition” auctions begin July 27.

Load Forecast

One asked FERC to order PJM to update its peak load forecasts for the upcoming capacity auctions or delay them (EL15-83).

The complainants — the PJM Industrial Customer Coalition, the Sustainable FERC Project and regulators or consumer advocates from Delaware, D.C., New Jersey, Maryland, Pennsylvania and West Virginia — say that PJM’s newly designed load forecast could reduce the amount of capacity procured by approximately 7,000 MW, saving consumers about $625 million.

While PJM told stakeholders at the May Load Analysis Subcommittee meeting that the new model is a “noticeable improvement” over the current forecast, the plaintiffs say, the RTO has said the new forecasts won’t be ready for incorporating in the capacity auctions until November.

The transition auction for delivery year 2016/17 is set for July 27-28 and that for 2017/18 for Aug. 3-4. The Base Residual Auction for 2018/19 is scheduled for Aug. 10-14.

The plaintiffs say FERC should either order use of the new models under the current auction schedule, delay the auctions until November or reinstate the short-term resource procurement target — also known as the “2.5% holdback” — for the BRA. FERC eliminated the holdback in its June 9 ruling. (See FERC OKs PJM Capacity Performance: What You Need to Know.)

They asked FERC to rule by July 17, saying continued use of the current model “will lead to substantial and imprudent over-procurement of capacity, resulting in unjust and unreasonable capacity prices for consumers.”

The plaintiffs said PJM has overestimated the RTO’s reliability requirement by an average of 6.25% in delivery years 2010/11 through 2015/16. The new model attempts to better account for energy efficiency and other factors.

PJM Vice President of Planning Steve Herling told RTO Insider on Thursday that the RTO reworked its load forecasting model with a focus on how it would affect the regional transmission expansion planning process. “We have not even begun to figure what the implication will be for” the capacity market, he said. “It started as an RTEP issue.”

In addition, he said, there is more work to do, including updating zones with new metropolitan area mapping and investigating the current practice of using 40-plus years in weather simulations. And, he added, the model has yet to pass through the stakeholder process. “Any change like that has to go through a vetting process,” he said.

Annual DR

Most of the same complainants — along with the Public Power Association of New Jersey, Duquesne Light Co. and regulators and consumer advocates from Illinois — also are seeking expedited hearing of a complaint seeking to allow annual demand response resources to bid into the transition auctions.

The plaintiffs acknowledged that the commission’s June 9 order “did not discuss specifically” whether annual demand resources could participate in the transition auctions. “This specific issue was not raised for the commission’s consideration because, ostensibly, it was clear from the operative provisions of the as-filed version of Section 5.14D [of PJM’s Tariff] that the transition auctions applied to all Capacity Performance resources, which, by definition, includes annual demand resources and other types of resources.”

The complainants said PJM has told them and other stakeholders that the Tariff does not permit annual DR’s participation.

“PJM’s view is that only generation capacity resources are eligible to participate in transition auctions. PJM has acknowledged, however, that no operational basis exists for excluding annual demand resources from the transition auctions. It appears that PJM’s concern is whether sufficient bases exist under the Tariff language that has been accepted by the commission to allow all types of Capacity Performance resources to participate.”

PJM has not responded to the filing, but in a separate challenge by the Advanced Energy Management Alliance Coalition, the RTO said Thursday it intended to exclude DR and energy efficiency from the transition auctions.

PJM said the transition auctions were designed to “provide a glide path” for generation resources that needed time to make investments to meet Capacity Performance requirements.

“The decision to limit the transition auctions to generation capacity resources was made in light of the fact demand response resources or energy efficiency resources would not need the same glide path, and also taking into account the continued uncertainty associated with the availability DR and EE to serve as Capacity Performance resources” following the D.C. Circuit’s EPSA ruling voiding FERC’s jurisdiction over DR (EL15-80). (See Supreme Court Agrees to Hear Demand Response Appeal.)

Market Monitor: ‘Inconsistent’ Incentives

The Monitor requested FERC revise findings in its June order that it said “create incentives in the energy market that are not consistent” with the Capacity Performance market design.

The Monitor cited FERC’s rejection of PJM’s proposal to allow parameter limits based only on resources’ physical constraints, saying the commission’s action would result in increased uplift payments.

“By permitting generation owners to establish unit parameters based on non-physical limits, the … order has weakened the incentives for units to be flexible and has weakened the assignment of performance risk to generation owners,” the Monitor said. “Contractual limits, unlike generating unit operational limits, are a function of the interests and incentives of the parties to the contracts. If a generation owner expects to be compensated through uplift payments for running for 24 hours regardless of whether the energy is economic or needed, that generation owner has no incentive to pay more to purchase the flexible gas service that would permit the unit to be flexible in response to dispatch.”

In contrast, NRG Energy and Dynegy asked FERC to clarify that capacity resources will not be penalized if PJM does not schedule them or reduces their output as the result of parameter limitations approved by the RTO.

The Monitor also called for changes regarding eligibility and documentation of risk premiums, the sub-zonal dispatch of DR and the calculation of “performance hours” and peak load obligations.

State Regulators Fear Higher Prices

The Illinois Commerce Commission said the commission’s order will create unnecessary barriers to market entry and undermine market power mitigation, resulting in higher costs for consumers.

The ICC said FERC erred in eliminating unit-specific cost reviews and the 2.5% holdback. It also faulted FERC for limiting the types of resources permitted to aggregate for the purpose of performance measurements, and in prohibiting external resources lacking pseudo ties from offering as Capacity Performance.

The Pennsylvania Public Utility Commission and the Delaware Public Service Commission joined the ICC in challenging the commission’s changes to PJM’s market mitigation rules and the elimination of the 2.5% holdback. They also questioned how penalties will be calculated; changes to credit requirements; the transition mechanism; and the elimination of extended summer DR and limited DR.

The Delaware commission also filed a separate rehearing request asking FERC to “identify the components of the balance upon which it relied for the determination that the market rule changes were just and reasonable” and asking that PJM be required to make informational filings regarding the costs and benefits of the new rules.

“Without such a requirement from this commission, any information and/or data would only be available on an ad hoc basis, which would not provide an appropriate foundation for the commission to make any assessment as to the ultimate cost effectiveness to customers of [Capacity Performance] and, perhaps more importantly, whether the costs for the implementation of [Capacity Performance] are appropriate and necessary,” Delaware said.

Generators: Penalties Excessive

The PJM Power Providers (P3) Group supported the commission’s ruling but asked FERC to clarify that generators operating within their approved parameters would not be subject to non-performance penalties. It also asked for clarification on what “performance quantifiable risks” can be included in avoidable cost risk calculations for units seeking to submit offers above the market seller offer cap. Exelon also requested rehearing on the issue.

“While both PJM and the commission expressly supported Tariff provisions that allow risks of fulfilling the obligation to offer capacity to be reflected in capacity offer cap calculations, the commission should go one step further and direct PJM to specifically enumerate known risks in addition to permitting the reflection of all reasonable risks undertaken to support a capacity offer,” P3 said.

Essential Power, Competitive Power Ventures, NextEra Energy and Invenergy Thermal Development contested FERC’s decision to eliminate monthly stop-loss limitations from PJM’s proposal, saying it failed to justify its decision through “reasoned decision-making.”

The coalition also said the commission erred in deciding that generator non-performance should not be excused even in circumstances beyond the control of generators, such as catastrophic weather events, compliance with state-approved tariffs or PJM-approved transmission outages.

GE Energy Financial Services, the operator of the 1884-MW Homer City coal-fired generating plant in Indiana, Pa., challenged FERC’s decision to make generators liable for a failure to deliver due to problems with transmission lines and switchyard equipment outside plant boundaries.

It said FERC was wrong in agreeing with PJM that generators were the market participants best able to bear the risk of transmission outages. “The best-placed party to bear this risk is the relevant transmission owner (and through it, load), which already collects payments to maintain these facilities,” it said.

“Unlike the ‘strict liability’ standard for generation delivery included in the CP revisions, transmission owners have limited their liability based on the customary ‘prudent industry practice’ standard. Thus, a supplier may have no recourse at law against its transmission ‘vendor’ — a sole source provider — even though the transmission owner has been paid to provide the service that it failed to deliver.”

The generator acknowledged that PJM may designate a transmission outage as a “catastrophic force majeure” that excuses generators for non-performance. But it noted “those events are intended to be region-wide in nature, even though Homer City will be equally unable to deliver its power upon the failure of its local transmission lines.”

“The penalties assessed against Homer City in that event would be funneled to other, luckier resources, which were fortuitously not in the wrong place at the wrong time.”

Public Service Enterprise Group also asked the commission to reinstate the existing force majeure provisions.

Calls for Reversal

While most of the filings sought to tweak the new rules, regulators from Maryland and D.C. argued that FERC should reverse its approval of PJM’s overhaul of the capacity market, saying it is “unnecessary for reliable service operations” and will increase end user costs in PJM by as much as $6 billion.

The commissions said the penalty provisions are not consistent with the higher revenues expected under the changes and said it should have held evidentiary hearings over the cost effectiveness of the changes. They also contend that the transition auctions are unnecessary.

Public Citizen also asked the commission to reverse its approval, citing the dissent by Chairman Norman Bay, who contended PJM’s overhaul of the capacity market was unwarranted. (See Norman Bay’s Dissent: ‘Two Carrots and a Partial Stick’.)

The group also asked that the commission review rates resulting from future capacity auctions under its “just and reasonable” standard.

“Public Citizen does not believe that the findings in this case are supported by ‘substantial evidence,’ but rather by the commission’s desire to further its market-based experiments in promoting and enabling ISOs and RTOs. Public Citizen fears that in doing so, however admirable its original intentions may have been, the commission may have lost sight of the primary goal of the [Federal Power Act], the protection of ratepayers from excessive rates and charges, and in fact may be slowly conceding its ability to protect ratepayers at all.”

— Suzanne Herel contributed to this article.