The Market Implementation Committee approved an issue charge directing the Demand Response Subcommittee to consider ways to allow residential customers to participate in the synchronized reserve market through demand response.
Comverge’s Frank Lacey, sponsor of the initiative, said residential DR will only be economical as a synchronized reserve resource if members approve an alternative to one-minute direct metering, which can cost upwards of $1,500 per unit.
Dave Pratzon, of GT Power Group, said that after discussions with Lacey he was satisfied that “not metering certain customers would be appropriate if the customers are very homogenous in nature so that DR response is going to be [predictable].”
Another question the subcommittee will consider is whether to limit eligibility to direct load-controlled properties.
PPL announced a special protection scheme to prevent overloads on its Susquehanna-Jenkins 230 kV transmission line.
According to PPL’s presentation to the Planning Committee last week, the protection would be activated under NERC N-1-1 contingencies, for example the loss of both the Susquehanna-Lackawanna 500 kV line and Mountain-Lackawanna 230 kV lines.
The scheme would trip the Stanton #1 and #2 breakers at Jenkins five minutes after the Susquehanna-Jenkins line exceeds 100% of its emergency rating and one minute after it exceeds its loadshed rating.
The scheme will be removed following the rebuild of Susquehanna-Jenkins (RTEP project b2269), which is scheduled for completion in summer 2018.
PJM will conduct training April 17 for transmission developers who want to submit proposals in the RTO’s second “market efficiency” window in November. The session will educate developers on how PJM calculates the benefits of improvements to reduce transmission congestion.
PJM officials acknowledged the need for training after selecting only one of 17 proposals submitted in the first market efficiency window last year. It was a disappointing beginning for those who had hoped FERC Order 1000 would unleash competition in transmission development. (See PJM to OK Only 1 of 17 Congestion Relief Proposals.)
Five of the projects were rejected because the congestion developers targeted had been addressed by other transmission projects or generation, while another nine projects failed to clear the 1.25 benefit-to-cost threshold.
Three projects passed the cost-effectiveness screen, but because they all addressed congestion in the same area, only one proposal was approved.
At last week’s Transmission Expansion Advisory Committee meeting, PJM officials outlined the data and assumptions that will be used to identify areas of the grid that could benefit from “economic” upgrades.
The assumptions are to be finalized by May, with preliminary results from the congestion analysis in June. After incorporating stakeholder feedback on the model, PJM will open the proposal window in November.
PJM told the Federal Energy Regulatory Commission last week that it should reject an attempt by Consolidated Edison Co. to avoid paying for more than half of a $1.2 billion transmission upgrade to address a short circuit problem in the PSE&G transmission zone outside New York City.
The project, part of PJM’s Regional Transmission Expansion Plan (RTEP), will convert Public Service Electric and Gas Co.’s Bergen-to-Linden 138 and 230 kV transmission line to 345 kV and add a second 345 kV transmission line between those points. (See Planners Choose $1.2B PSEG Short Circuit Fix.)
$629 Million Allocation
(Source: Con Edison)
Con Edison says PJM’s cost allocation unfairly assigns $629 million of the cost to it as a result of the Con Ed-PSEG “wheel,” in which PSEG takes 1,000 MW from Con Ed at the New York border and delivers it to Con Ed load in New York City. Its protest was joined by the New York Public Service Commission and New York City (ER14-972).
PJM told FERC in an answer filed Friday that Con Ed’s protest is a challenge to the distribution factor (DFAX) cost allocation method outlined in Schedule 12 of PJM’s Open Access Transmission Tariff and approved by FERC in Order 1000 proceedings.
If Con Ed’s challenge prevailed, PJM said, “Every project would be open to project-by-project subjective ad hoc determinations of `beneficiaries,’ which the [Order 1000] cost allocation process is designed to avoid.”
Regional Benefits or Local Reliability Fix?
The dispute could turn on whether the commission agrees with PJM that the PSE&G upgrade has regional benefits, as PJM insists, or whether it primarily addresses a local reliability problem, as the protestors contend.
Under rules approved by FERC last year (142 FERC ¶ 61,214), PJM will allocate the cost of regional projects — defined as double 345kV and those 500kV and above — under a hybrid formula: Half of the cost is socialized based on load share and the other half based on identified beneficiaries. PJM previously allocated the cost of regional upgrades solely on load share. (See PJM TOs’ ROFR Bid Rejected; “Hybrid” Cost Allocation Plan Approved.)
For reliability projects, the beneficiaries are identified based on post-upgrade load flow, as determined by a DFAX analysis.
In approving the use of DFAX, the commission ordered PJM and its transmission owners to provide more detail regarding how the formula would be implemented. “While PJM has adequately shown how the DFAX values and usage of transmission facilities will be calculated, there is no detail regarding how these values will be utilized to calculate assignments of cost responsibility,” the commission said.
The PJM Transmission Owners responded with a compliance filing in July. The commission has not ruled on the filing.
Jan. 10 Filing
On Jan. 10, PJM submitted to FERC amendments to Schedule 12 of its Tariff reflecting cost responsibility for 111 baseline RTEP upgrades approved by the Board of Managers in December.
PSEG Short Circuit Solution (Source: PJM Interconnection, LLC)
The filing said the “PSEG Northern NJ 345 kV Project” (project b2436) is intended to relieve overdutied breakers at Essex, Kearny, and NJ Meadowlands 230kV.
In the Transmission Expansion Advisory Committee’s recommendation to the Board, PJM said the $1.2 billion project would also allow cancellation of previously approved RTEP projects totaling $1.04 billion. Thus, the additional work had an incremental cost of only $160 million, PJM said.
The hybrid formula was applied to 15 of the 26 subprojects that comprise the PSE&G upgrade. Of the remaining 11 subprojects, one is fully allocated to PSE&G and the remaining 10 are allocated based on DFAX, according to Con Ed.
According to Con Ed’s calculations, almost $763 million of the project cost will be assigned based on DFAX calculations, with the remaining $418 million allocated based on load ratio shares.
Con Ed-PSEG Wheel
The Con Ed-PSEG wheel began in the 1970s as a grandfathered service by PSE&G, and was converted in 2012 to the PJM Tariff.
Con Edison says RTEP charges currently represent about $9 million of the wheel’s $40 million annual cost. The $600 million allocation for the short circuit fix would quadruple the cost of the wheel to $160 million annually, Con Ed says. “While Con Edison continues to find value in the service that the Commission approved as important to regional reliability, irrational increases in costs could ultimately undermine this arrangement,” it said.
Con Ed says it was unfairly assessed almost 83% of the $762.6 million assigned through DFAX for its 1,000 MW wheel while PSE&G was assessed only 7%, despite load of 11,000 MW. Con Ed said the cost distribution for the project — which contends the upgrade would be needed without its wheel — is “grossly disproportionate to the relative loads” of the two companies.
Linden Challenge
After Con Ed filed its challenge, Linden VFT LLC, a subsidiary of General Electric Capital Corp., filed a protest of its own. Linden VFT, which owns a 315 MW merchant transmission facility which interconnects both PJM and NYISO, said it learned from the Con Ed challenge that it would be billed an additional $2.5 million in RTEP charges annually, more than doubling its current RTEP tab.
LindenVFT Variable Frequency Transformer (Source: LIndenVFT)
“It is simply inaccurate to allocate to Linden VFT these costs based on likely power flows over the PSE&G Upgrade when the PSE&G Upgrade will be built to resolve short circuit fault currents, not to accommodate additional power flows,” Linden said.
“PJM has chosen to apply the rules applicable to double circuit 345 kV transmission lines versus those for circuit breakers that would more appropriately reflect what is happening,” Linden said. “As a result, rather than bearing the entire cost of the PSE&G Upgrade, the PSE&G zone would avoid almost 94% of the portion of the project cost that is allocated using DFAX.”
In addition, Linden complains, the allocation makes no adjustment for the benefits received by customers who would have been assessed the costs of the previously approved RTEP projects that were cancelled as a result of the PSE&G upgrade.
Linden filed its protest Feb. 27, 17 days after comments were due. Linden said it should be permitted the late filing because the Con Ed protest “identified new issues that should have been identified in PJM’s January 10 filing.”
PJM responded that “the PSE&G Upgrade solves more than local short circuit issues and is properly treated as a Regional Facility.”
“Linden VFT’s objections are challenges to the justness and reasonableness of the cost allocation process set forth in the PJM Tariff, which are beyond the scope of this proceeding,” it added.
The Planning Committee voted last week to initiate work to bring PJM into compliance with the Federal Energy Regulatory Commission’s Small Generator Interconnection rules.
FERC Order 792, issued in November, streamlines interconnection procedures for small generators connecting to transmission at 69 kV and below. (See Rule Set for Small Generators.)
The PC approved a problem statement that will lead to changes in PJM’s Small Generator Interconnection Procedures and Small Generator Interconnection Agreement.
John Brodbeck of Pepco Holdings Inc. said he hoped the changes PJM makes will accommodate Pepco’s proposed alternative to pre-application and fast-track screening, which he said is more appropriate for testing renewable generation’s impact on system reliability.
Pepco has told FERC that it has developed a modeling tool that can determine a maximum allowable hosting capacity at a given point of interconnection.
“As we move through the process, I fear we’re going to [endorse] a process for all of PJM even if we believe we have an alternative that’s more appropriate for our territories,” said Brodbeck.
Nearing the end of one of the harshest winters in its history, PJM is considering requiring cold-weather testing of generators, officials told the Operating Committee last week.
Generation Outages by Unit Type (Source: PJM Interconnection, LLC)
During the polar vortex in early January, forced outages downed as much as 20% percent of PJM’s generation, including almost one-third of combustion turbines and diesel units. Operators had to resort to demand response and a voltage reduction to keep the grid functioning. Generator failures dropped to more typical rates of 8% to 10% later in the month.
The early January failure rate was the worst PJM has experienced since 1994, according to a “frequently asked questions” report on the January cold released last week. PJM, then only consisting of the MAAC region, saw rotating blackouts for several hours during the 1994 “Deep Freeze.”
Executive Director of System Operations Mike Bryson said the high initial failure rate has officials considering rules to require winter start tests for generators. Reintroducing winter capacity tests is also under consideration, he said.
Winter testing would “give GOs the opportunity to test units that don’t ordinarily start or that are using alternative fuels,” he said. “I’m less worried about capacity.”
Among the issues that stakeholders will need to discuss are the timing of the tests and compensation for generation operators. “You don’t want to start too early because that doesn’t replicate the cold weather,” said Bryson, who suggested the checks could be conducted between Thanksgiving and the end of December. Waiting until January, he said, “sort of defeats the purpose.”
One stakeholder suggested installing heaters on units and that providing additional staffing could help reliability but added that those costs aren’t recoverable.
Although the North American Electric Reliability Corp. may eventually issue cold weather reliability standards, Bryson said PJM should move to institute its own requirements by the fall.
“I don’t want to do nothing for next year,” Bryson said.
The Commodity Futures Trading Commission has begun regular information-sharing with the Federal Energy Regulatory Commission after several years of wrangling and pressure from the Senate to make good on promises of cooperation.
The CFTC is now sending FERC its Large Trader Report on a routine basis so FERC will not have to request it case-by-case for market surveillance.
The sharing, which followed memorandums of understanding the agency heads signed in January, is a milestone in the government’s efforts to police market manipulation. But conflicts over the two agencies’ jurisdiction are still being played out in court.
As the commissions announced their initial data-sharing last week, they also announced establishment of a staff-level Interagency Surveillance and Data Analytics Working Group to coordinate the sharing “and focus on data security, data-sharing infrastructure and the use of analytical tools for regulatory purposes.”
Last month, eight senators leaned on the CFTC to make good on the sharing promised in the Jan. 2 MOUs, which were required by the 2010 Dodd-Frank law.
Sen. Dianne Feinstein (D-Calif.), who has pressed the agencies more than once for action, last week commended them for starting the “overdue” sharing. “FERC investigators have caught multiple entities manipulating California’s markets in recent years – even without access to this critical data,” she said. “I am hopeful the trading data … will allow FERC to prevent the complex and sophisticated schemes that robbed consumers and disrupted economic activity during the Western energy crisis.”
One of the January MOUs outlined a process by which the commissions would notify each other of activities that may involve overlapping jurisdiction, and when entities request authorization or exemptions that may fall in that overlap. The other MOU established processes for sharing information of mutual interest.
The eight senators who wrote to the CFTC Feb. 10 said they were impatient that no concrete action had taken place yet because of what the CFTC had said were data transfer issues.
“Considering the CFTC’s technical ability to share data with other nations and other regulators,” the senators wrote to CFTC acting Chairman Mark Wetjen, “we believe that technical barriers preventing the sharing of information with FERC — a fellow arm of the federal government — could be addressed and solved in a matter of weeks under your direction and leadership.” The trader-report sharing came a few weeks later.
The CFTC has not yet asked for access to FERC data on an ongoing basis.
Questions surrounding the exchange of information are only part of the conflict that has characterized the commissions’ relationship. FERC lost a fight to pursue a market manipulation case against Brian Hunter, of hedge fund Amaranth Advisors, when the U.S. Court of Appeals for the District of Columbia Circuit ruled the CFTC had exclusive jurisdiction over the matter.
FERC has continued to assert its jurisdiction, however, particularly in the power arena. Last year it ordered Barclays Bank PLC to pay $470 million in fines and disgorged profits for allegedly manipulating California’s power markets.
The bank challenged FERC’s authority, saying the agency lacks jurisdiction over transactions that involve futures and swaps and do not involve actual physical transmission or delivery of power.
The case is pending before the U.S. District Court for the Eastern District of California (FERC v. Barclays Bank PLC et al., Case No. 2:13-cv-02093-TLN-DAD).
Attorneys at Bracewell & Giuliani said the case’s “resolution may significantly affect the scope of FERC’s enforcement authority going forward.”
The commission seems to agree. In a filing in February, FERC said that a ruling in Barclays’ favor would “eviscerate the regulation of wholesale electricity markets contemplated” in the Federal Power Act.
Responding to concerns raised by last spring’s sabotage of a Pacific Gas and Electric substation, the Federal Energy Regulatory Commission has ordered development of reliability standards to protect the grid from physical attack.
The North American Electric Reliability Corp.’s standards, due in 90 days, do not have to require uniformity, FERC said in its order to NERC, nor are they likely to apply to the majority of facilities (RD14-6). NERC CEO Gerry Cauley and FERC commissioners Philip Moeller and John Norris warned last month that an overreaction to the threat could be expensive and counterproductive. (See FERC-NERC: Don’t Overreact to Sabotage Threat.)
Identify Critical Facilities
NERC’s standards must require owners and operators to take at least three actions. The first step is a risk assessment to determine what facilities, if damaged, could have a critical impact on grid operations.
The next steps are to evaluate potential threats and vulnerabilities to those critical facilities and then to develop and implement security plans.
FERC told NERC to include a procedure that would ensure confidential treatment of sensitive information but still allow appropriate oversight for compliance.
“The commission is not requiring NERC to adopt a specific type of risk assessment, nor is the commission requiring that a mandatory number of facilities be identified as critical facilities,” the order said. It added that FERC “expects that critical facilities generally will include, but not be limited to, critical substations and critical control centers.”
Once facilities are identified, FERC said, the standards need not dictate specific protective steps to be taken. But they “need to require that owners or operators of identified critical facilities have a plan that results in an adequate level of protection.”
FERC expects that the number of critical facilities will be relatively small. Most substations, for example, would not be deemed critical under the standards.
“We do not expect that every owner and operator of the bulk power system will have critical facilities under the reliability standard,” the commission said. “We also recognize that the industry has engaged in longstanding efforts to address the physical security of its critical facilities.”
Norris’ Concerns
Commissioner Norris issued a concurring statement expressing concerns that the expedited 90-day deadline and the commission’s ex-parte rules will inhibit the development of intelligent rules.
“I believe the order does not sufficiently justify the uniquely expedited nature of the standard development process, particularly when it will foreclose the Commission from engaging with stakeholders during that process,” Norris said.
The Electric Power Research Institute will lead an educational session on smart inverters March 31 as the Planning Committee begins work on developing standards for the devices.
The Markets and Reliability Committee approved a problem statement/issue charge on Feb. 27 directing the Planning Committee to set rules for the devices, which allow solar PV and other renewables to provide reactive power. (See Enhanced Inverters Clear MRC.)
The Planning Committee will meet twice monthly on the issue. PJM will provide a second educational session April 18.
PJM said it will change Manual 11’s rules regarding compensation for demand response despite a lack of stakeholder support.
In an unusual move, the Markets and Reliability Committee last month balked at endorsing the manual changes, which outline when Economic Demand Response qualifies for payment.
In an email to the Demand Response Subcommittee Friday, PJM’s Dave Anders cited a provision of the Operating Agreement that gives PJM the authority to make manual changes without a two-thirds member endorsement. “While PJM rarely exercises this right and responsibility, PJM has determined that this is the proper course of action in this case,” Anders wrote.
The changes were backed by only 57% of the MRC in a sector-weighted vote Feb. 27, with no End Use Customers and less than half of Other Suppliers voting in support. (See Manual Change on DR Compensation Rejected; 3 Others OK’d.)
Most Generation Owners and Transmission Owners voted in support of the changes, which specify that demand reductions are eligible for compensation only when they “are not implemented as part of normal operations.”
Load reductions “that would have occurred without PJM dispatch, or that would have occurred absent PJM energy market compensation” would be ineligible for compensation, according to the new rule.
PJM officials contend the manual changes only explained the RTO’s existing interpretation of FERC Order 745, and would not change operating practices.
But John Webster, of Icetec Energy Services, said the new language would give PJM too much latitude in determining the motives of DR participants and when they should be compensated. He said any revisions should be made through Tariff changes and subject to full stakeholder review.
