Audrey Zibelman, chair of the New York Public Service Commission since 2013, is headed to Australia to lead the operator of that country’s largest gas and electricity markets.
In a press release late Sunday — Monday morning in Australia — the Australian Energy Market Operator said Zibelman will become its CEO on March 20. Zibelman’s last meeting heading the NYPSC is scheduled to be on March 16 in New York City.
Then living in the Philadelphia area, Zibelman was appointed by Gov. Andrew Cuomo as PSC chair in 2013. She was tasked with shepherding the state’s Reforming the Energy Vision initiative, which was unveiled in 2014.
Prior to joining the NYPSC and founding Viridity Energy, a demand response and demand management provider, she was the chief operating officer of PJM from 2004 to 2007 and held various utility and regulatory positions before that. She is the wife of former PJM CEO Phil Harris.
“Audrey’s vast experience in creating and managing new wholesale electricity markets, and transforming existing energy markets and large power systems will further strengthen the work that AEMO has undertaken to support Australia’s energy industry transformation,” Anthony Marxsen, AEMO board chair, said in a statement.
“Audrey has the vision to lead, guide and support our organization and the broader Australian energy industry as we transition our energy markets and reform power systems planning and management.”
Melbourne-based AEMO is responsible for operating Australia’s largest gas and electricity markets and power systems, including the National Electricity Market and interconnected power system in Australia’s eastern and south-eastern seaboard, and the Wholesale Electricity Market and power system in Western Australia.
Zibelman succeeds acting CEO Karen Olesnicky, who has held that title since the death of AEMO’s founding CEO, Matt Zema, in July 2016.
“I am forever grateful to have played a part in bringing the governor’s highly lauded vision of a clean-energy economy to fruition,” Zibelman said in a statement. “Thanks to the governor’s leadership, New York state is on a pathway to achieve 50% renewable electricity by 2030 and create an affordable, clean and resilient power system for all New Yorkers. It has been an immense privilege to work with my colleagues in the governor’s office, on the commission and the dedicated, capable Department of Public Service staff.”
Anne Reynolds, executive director of the Alliance for Clean Energy New York, was dismayed by the news.
“PSC Chair Audrey Zibelman and New York’s energy team have made our state a national and global model for the 21st century energy grid. Her leadership in reforming utility regulation, the promotion of distributed generation and public participation testify to her lasting contribution. Her departure will be a real loss for New York state,” Reynolds said. “But Gov. Cuomo has a very strong energy team and vision, and we assume the administration’s sharp focus on modernizing and decarbonizing the grid will continue with Audrey’s replacement.”
Her departure leaves the PSC even more short-handed than it already is.
Former Chair Garry Brown left the commission in February 2015 and was not replaced. Last month, longtime commissioner and former chair Patricia Acampora said she would retire after the Feb. 16 commission meeting.
That would leave only two current members, Gregg Sayre and Diane Burman on the five-member panel. Their terms expire Feb. 1, 2018.
Sayre, a former telecommunications assistant general counsel from the Rochester area, was appointed in 2012.
Burman, chief counsel to the New York State Senate Republican Conference before her appointment to the PSC in 2013, is often the lone dissenting vote in commission meetings.
Rocco LaDuca, spokesman for Senate Energy and Telecommunications Committee Chair Joseph Griffo, said the senator is aware of the pending vacancies. “The [Republican caucus] will be having discussions in the days and weeks ahead to determine how to move forward. They are mindful of the commission’s responsibility to conduct its business, but there’s still time until March to address this issue,” he said.
Commissioners are appointed to six-year terms and are paid $109,800 annually. The chair has a $127,000 salary.
WASHINGTON — FERC last week proposed regulations intended to reduce uplift, allocate it more accurately and increase transparency (RM17-2).
The Notice of Proposed Rulemaking — the fourth issued by the commission in its ongoing price formation initiative — is premised on a preliminary finding that current RTO and ISO practices regarding reporting of uplift payments and operator-initiated commitments are unjust and unreasonable.
“The allocation of uplift costs should, to the extent possible, encourage behavior that will reduce the need for uplift-creating actions and avoid discouraging market participant behavior that lowers total production costs (i.e., enhances efficiency),” the commission said.
Lack of Transparency
“The lack of transparency regarding uplift and operator-initiated commitments, which can cause uplift, hinders market participants’ ability to plan and efficiently respond to system needs,” the commission said. “Market participants may lack the information necessary to evaluate the need for and value of additional investment, such as transmission upgrades or new generation. Also, without sufficient transparency, market participants may not be able to assess each RTO’s/ISO’s operator-initiated commitment practices and raise any issues of concern through the stakeholder process.”
Generators receive uplift payments when their production costs exceed their energy and ancillary services revenues. Last week’s order focuses on one of the main causes of uplift: deviations between the day-ahead and real-time market that can force operators to commit additional units. This can result from generators delivering less energy in real time than their day-ahead offers or real-time loads exceeding expectations.
Balancing charges (canceled resources, generators, imports, load response, local constraints control and lost opportunity cost) were responsible for 59% of all uplift in the first nine months of 2016 in PJM. The top 10 generators received 35.4% of all uplift and the top 10 organizations received 77% during the period. PJM’s Independent Market Monitor has long advocated disclosing the recipients of uplift payments, something that FERC’s recent NOPR would require monthly.
Although all RTOs and ISOs use some form of beneficiary pays or cost-causation principles to allocate uplift, their methods “vary significantly, both in terms of granularity and the exemption of certain types of transactions,” the commission said. “The definition of what precisely constitutes a deviation also varies across RTOs/ISOs.”
Some RTOs also fail to consider how deviations affect uplift costs. “Deviations from day-ahead market schedules that create the need for additional resource commitments in real-time tend to increase real-time uplift costs. On the other hand, deviations can also contribute to the convergence of the day-ahead and real-time markets,” the commission said.
“Allocating costs to deviations that did not cause the costs to be incurred may inappropriately penalize certain types of transactions that are beneficial to price formation,” the Office of Energy Policy and Innovation’s Stanley Wolf said in a presentation at Thursday’s commission meeting, which was closed to the public because of concerns about disruptions by anti-pipeline activists.
‘Helping’ and ‘Harming’ Deviations
The NOPR requires RTOs and ISOs to separate uplift costs assigned to deviations into at least two categories based on their causes: congestion management or systemwide capacity, a catch-all for any other deviations made to meet the system’s energy needs. The commission said categorization would ensure the costs are allocated more precisely to the participants that caused the uplift. The NOPR gives RTOs flexibility to create additional categories.
Grid operators would also be required to distinguish between deviations that help or harm their systems. Generators would be assigned uplift costs based on the net of their “harming” deviations — the total amount of deviations minus their “helping” deviations.
FERC said that any actions generators take in response to dispatch instructions should not be considered deviations. Also excluded would be transactions economically evaluated by RTOs in real time, such as the coordinated transaction scheduling between PJM and its neighbors NYISO and MISO.
The commissioners said they were inclined to exclude instructed deviations from the “help” category but asked for stakeholders’ comments on the issue.
RTO Requirements
The commission also proposed several requirements to increase transparency into uplift cost allocation and the decision-making of grid operators, noting that while all RTOs and ISOs release some information, “there is significant variation in the timing, granularity and types of data released.”
RTOs and ISOs would be required to:
Report total uplift payments for each transmission zone, separated by day and uplift category;
Report total uplift payments for each resource monthly;
Report megawatts of operator-initiated commitments in or near real time and after the close of the day-ahead market, broken out by transmission zone and the reason for the commitment; and
Define in their tariffs the transmission constraint penalty factors, how those factors can set LMPs and the process by which they can be changed. Transmission constraint penalty factors are the values at which an RTO will relax the flow-based limit on a transmission element to relieve a constraint rather than re-dispatch resources.
“The proposed transparency reforms will help market participants understand the operational constraints on the system, plan and efficiently respond to system needs, and evaluate the need for and value of additional investment,” FERC said.
“While uplift is not constituting a large proportion of total costs and is unavoidable to some extent, I think RTO/ISO stakeholders and the commission should strive to minimize uplift when and where possible because uplift is unhedgeable, lacks transparency and, if not allocated properly, can encourage inefficient behavior,” Chairman Norman Bay said.
The NOPR only addresses uplift costs incurred because of deviations. RTOs may also pay uplift for reliability reasons, such as stand-by costs, or inaccurate load forecasting.
“We note that the commission is not proposing to require RTOs/ISOs to allocate any amount of uplift costs to deviations; rather we are simply proposing reforms to uplift cost allocation to deviations to the extent an RTO/ISO chooses to allocate some uplift costs to deviations,” FERC said.
Comments on the NOPR are due no later than 60 days after its publication in the Federal Register.
Previous orders in the commission’s price formation initiative concerned fast-start resources, shortage pricing and the alignment of settlement and dispatch intervals and a doubling of the “hard” energy offer cap. (See FERC: Let Fast-Start Resources Set Prices.)
WASHINGTON — Energy storage facilities should be permitted to provide multiple services and earn both cost- and market-based revenue streams, FERC said last week in a policy statement clarifying its prior rulings on the issue.
AES Laurel Mountain in Elkins, WV | AES
“Enabling electric storage resources to provide multiple services (including both cost-based and market-based services) ensures that the full capabilities of these resources can be realized, thereby maximizing their efficiency and value for the system and to consumers,” the commission said in the statement, which was approved on a 2-1 vote (PL17-2).
The commission said that storage resources, which can switch from providing one service to another almost instantaneously, may not be cost competitive without multiple revenue streams.
Chairman Norman Bay and Commissioner Colette Honorable said their position is supported by most of those who testified at the commission’s technical conference Nov. 9 or provided comments afterward. “Commenters believe that the key question is not whether to allow multiple-use applications for electric storage resources but how to allow and enable such applications,” they said. (See FERC Panelists Debate Storage Uses, Compensation.)
Bay and Honorable said the statement was needed to address “potential confusion” over FERC precedent in two previous rulings.
Commissioner Cheryl LaFleur dissented. LaFleur wrote that she agreed that the “commission should be flexible and open to proposals that go beyond the model contemplated” in the prior orders but said the issue should have been considered as part of the Notice of Proposed Rulemaking the commission issued Nov. 14. (See FERC Rule Would Boost Energy Storage, DER.)
Precedents
In the 2008 Nevada Hydro case, the commission rejected a request by the owner of the Lake Elsinore Advanced Pumped Storage project that its resource be classified as a transmission facility under CAISO’s control, with its costs recovered through the ISO’s transmission access charge (ER06-278, et al.).
The commission sided with the ISO, which said that its independence would be compromised because it would have to decide when the facility would operate, how much energy it would produce and when it would operate the pumps to store water.
In the 2010 Western Grid ruling, the commission allowed storage facilities to be classified as transmission assets receiving cost-based rates for providing CAISO voltage support and thermal overload protection. The ruling was conditioned on the operator’s promise to forego any sales into the ISO’s wholesale electric markets (EL10-19).
The commission noted in its ruling that Western Grid would be responsible for maintaining the state-of-charge on the projects. CAISO’s independence would be maintained because it would not be responsible for buying power to energize the projects or for operating the charge and discharge of the batteries, the commission ruled.
“That order was limited to the facts that Western Grid presented to the commission,” FERC said last week. “Thus, that order should not be read to require other entities to forgo market sales as Western Grid proposed. We clarify that there may be approaches different from Western Grid’s approach under which an electric storage resource may receive cost-based rate recovery and, if technically capable, provide market-based services that may address these concerns.”
Implementation Issues
This commission said the policy statement “is not intended to resolve the detailed implementation issues surrounding how an electric storage resource may concurrently provide services at cost- and market-based rates. Rather, it is intended to clarify that providing services at both cost- and market-based rates is permissible as a matter of policy, provide guidance on some of the details and allow entities to address these issues through stakeholder processes and in filings before the commission.”
It said future requests by storage operators must ensure that:
Storage resources receiving cost- and market-based rates do not over-recover their costs at the expense of ratepayers;
Storage resources earning cost-based rates do not suppress competitive prices in the wholesale markets, which could harm competitors without cost-based revenues; and
The RTO/ISO’s level of control of the storage resource does not jeopardize its independence from market participants.
Double Recovery
The commission said concerns over double recovery can be addressed by crediting cost-based ratepayers for market-based revenues. It said the commission’s accounting rule in Order 784 and the requirement to submit Electric Quarterly Reports “provide sufficient transparency to allow effective oversight for any needed revenue crediting.”
As an alternative, the commission said, a resource’s market-based revenues could reduce the revenue requirement used in its cost-based rate.
Protecting Competition
Bay and Honorable said they did not share the concern of commenters who fear that allowing storage to receive multiple revenue streams could suppress market prices and undermine competition. They noted that some generators with market-based rates also receive cost-based rates for providing reactive service.
“Similarly, some vertically integrated public utilities make cost-based rate sales to captive wholesale requirements customers such as transmission-dependent utilities while also making off-system market-based rate sales to others,” the commission said. “If we were to deny electric storage resources the possibility of earning cost-based and market-based revenues on the theory that having dual revenue streams undermines competition, we would need to revisit years of precedent allowing such concurrent cost-based and market-based sales to occur.”
In her dissent, LaFleur said she disagreed with Bay and Honorable’s “sweeping conclusions.”
“The policy statement summarily dismisses concerns regarding the impact of such arrangements on market competition and leaves far more than just ‘implementation details’ to be worked out,” she wrote. “Indeed, the policy statement provides no guidance on how the commission could evaluate whether a particular filing under Section 205 of the Federal Power Act successfully avoids adverse market impacts.”
RTO Independence
The commissioners acknowledged that storage resources must maintain the necessary state of charge to provide their cost-based services when called on by the RTO.
“But, assuming this priority need is reasonably predictable as to size and the time it will arise each day, the electric storage resource should be permitted to deviate from this state of charge at other times of the day in order to provide other, market-based rate services,” the statement said. “In situations where this premise does not hold … the cost-based rate service may be the only service that the electric storage resource could provide.”
The statement also said that RTO dispatch of storage resources to provide cost-based service should take priority over the resource’s provision of market-based services. Performance penalties could be imposed on resources that fail to deliver when called on, it said.
“We further provide guidance that the provision of market-based rate services should be under the control of the electric storage resource owner or operator, rather than the RTO/ISO, to ensure RTO/ISO independence. In other words, while the RTO/ISO always performs the actual optimization of resources participating in the organized wholesale electric markets, during periods when the electric storage resource is not needed for the separate service compensated at cost-based rates, the RTO/ISO would rely on offer parameters provided by the electric storage resource owner or operator for such operation, just as the RTO/ISO does with other market participants.”
LaFleur’s Concerns
In addition to her procedural concerns, LaFleur said she worried that the policy statement “could be read to reflect the commission’s views about the impact of multiple payment streams on market pricing more generally, thus implicating broader regional discussions on state policy initiatives and their interaction with competitive markets.”
“These issues, which are currently being discussed by several RTO/ISOs and their stakeholders, will require careful and holistic consideration to ensure that policy advancements can be achieved while the benefits of competition are preserved for customers,” she said.
“Storage is an important and promising resource that warrants commission attention to ensure that our markets are appropriately adapted to recognize storage’s unique characteristics and contributions. However, efforts to accommodate these resources should not come at the expense of careful market design after full public participation.”
FERC on Thursday approved a final rule on recovering from balancing contingency events and proposed a second rule to ensure that remedial action schemes do not compromise reliability.
Recovery from a Balancing Event
The final rule approves NERC reliability standard BAL-002-2, which seeks to ensure that balancing authorities and reserve sharing groups can use reserves to balance resources and demand to recover from system contingencies and restore their area control error (ACE) to pre-contingency levels (RM16-7).
| MISO
In response to opposition from NERC, the Edison Electric Institute and most RTOs and ISOs, the commission backed off from a proposal that would have required reliability coordinators to authorize extensions of the 15-minute ACE recovery period.
In its Notice of Proposed Rulemaking in May, the commission said it was unclear how an entity would prepare for a second contingency during the extension under NERC’s proposal. A balancing authority operating out-of-balance for an extended period of time is “leaning on the system” by relying on external resources, which could affect other entities within an interconnection, the commission said.
EEI and the RTOs said that the requirement “would result in unnecessary duplication of requirements adding no tangible benefit to reliability while needlessly increasing the compliance burden.”
Instead, the commission’s final rule adopts a proposal by Arizona Public Service requiring only that an entity that is unable to recover ACE because of a second disturbance inform the reliability coordinator and provide it with a recovery plan.
The commission also approved NERC’s proposal that demand-side resources that are technically capable be included as contingency reserves.
Remedial Action Schemes NOPR
The commission also approved a NOPR backing NERC reliability standard PRC-012-2, which is designed to ensure that remedial action schemes (RAS) do not introduce “unintentional or unacceptable” reliability risks (RM16-20).
The standard defines an RAS as a plan to detect abnormal system conditions and automatically take corrective actions — such as tripping generation or load, or reconfiguring a system — to maintain stability and limit the impact of cascading events.
The NOPR also would withdraw pending standards PRC-012-1, PRC-013-1 and PRC-014-1 and retire standards PRC-015-1 and PRC-016-1.
The commission solicited comment on a proposed clarification that the new standard will not supersede system performance obligations under reliability standard TPL-001-4, which limits “non-consequential load loss” to 75 MW for certain contingencies.
Rehearing Denied on GMD Rule
FERC also rejected rehearing requests by EEI and others on its September order requiring grid operators to assess and protect against the threat of geomagnetic disturbances (RM15-11-001). (See FERC Approves GMD Reliability Standard.)
EEI had challenged the standard’s (TPL-007-1) implementation plan, saying it failed to account for the impacts of changes to the definition of a benchmark GMD event.
The commission said EEI’s concern was “premature.”
“At this time, the commission has no way of knowing what impacts the modified benchmark GMD event definition may have on the approved implementation plan because NERC has not yet developed or proposed a revised” definition, FERC said. It added that NERC may propose a longer implementation plan if needed as a result of a revised definition.
In FCA 10 last year, ISO-NE used two zones: Rest of Pool, which comprises Connecticut, Vermont, New Hampshire, Maine, and western and central Massachusetts; and Southeastern New England (SENE), which includes Northeast Massachusetts/Greater Boston and Southeast Massachusetts/Rhode Island.
FCA 11 (2020/21) and FCA 12 (2021/21) will be conducted in four zones: Southeast Massachusetts/Rhode Island, which includes Greater Boston; Northern New England, which includes Maine, New Hampshire and Vermont; Connecticut; and Rest of Pool, generally central and western Massachusetts.
“Most major transmission projects are already certified,” Al McBride, director of transmission strategies and services, told the Planning Advisory Committee last week, meaning the RTO has determined they will be operational in time for the capacity commitment period.
As they go into service, additional portions of the Greater Hartford/Central Connecticut and Southwest Connecticut transmission project will be included in the Connecticut zone. The project is expected to be completed in 2019.
Likewise, resource retirements are unlikely to have significant impact on the zones. “Our modeling show that even if they occur, it is not likely to change the boundaries,” he said.
New Study Looks at Less Maine Wind, More Offshore
Integrating renewable resources close to load centers in the Southeast Massachusetts/Rhode Island area could be more cost effective than tapping large volumes of wind in Maine, according to a new high-level transmission cost analysis presented to PAC members last week.
Renewable energy advocacy group RENEW requested an additional analysis in which large amounts of renewable resources, primarily onshore wind in Maine as outlined in scenario 2, were changed to incorporate a more diverse mix of renewable resources spread over wider geographic areas.
Under scenario 2, Maine wind injections were assumed to be 12,872 MW in 2030, with 1,219 MW of offshore wind in Southeast Massachusetts and Rhode Island. In scenario 6, the Maine wind has been cut by more than half to 5,959 MW, with offshore wind boosted to 5,370 MW.
Even that smaller amount of Maine wind could require a complete overhaul of the AC power system, system planner Marianne Perben said.
Instead, renewable resources would be tied directly into several HVDC connectors connecting the wind integrator system to a hub in Millbury, Mass. Scenario 2 assumes a need for 9,043 MW of congestion relief, while scenario 6 envisions a need for 3,596 MW.
Splitting offshore wind resources between Connecticut, Rhode Island and Southeast Massachusetts could alleviate the need for a congestion relief system for those resources, planners said.
The analysis found that offshore wind could be imported without the need for congestion relief if it were sited off of Connecticut, Rhode Island and Southeast Massachusetts. That would allow the resources to take advantage of interconnections vacated by about 4,400 MW of resources close to the coastline that are expected to be retired by 2030: the Pilgrim nuclear plan, Millstone Unit 1, Montville Units 5 and 6, Brayton Point Units 1 through 4, and Canal Units 1 and 2.
“Under this … assumption, the cost to integrate renewable resources (excluding plant collector and interconnection system costs) in scenario 6 would be driven exclusively by the cost of integrating Maine onshore wind resources and would be significantly reduced, as compared to scenario 2,” the RTO said.
Renewable collector and interconnection system (left) and approximate path of HVDC congestion relief system (right). | ISO-NE
In scenario 2, the total Maine congestion relief system would cost an estimated $20 billion; in scenario 6, the price tag is estimated at $8 billion.
The estimates do not account for individual plants’ interconnection costs or potential costs from the challenge of managing large volumes of renewables during off-peak periods, the RTO said.
ISO-NE Recommends Against Keene Road Project
Staff told the PAC it is recommending the RTO not move forward on the Keene Road transmission project.
In December, staff told the committee that increasing export limits from the current 165 MW to 195 MW would save only $1.35 million to $1.38 million (2015 $) in energy production costs. (See ISO-NE Study Sees Little Savings from Keene Road Tx Upgrade.)
Written comments are due to PACmatters@iso-ne.com by Feb. 17. The RTO will report its final decision at the March or April PAC meetings.
Streamlined Regional System Plan due this Summer
ISO-NE staff is preparing a streamlined regional system plan for unveiling in the summer.
The document, which had become an unwieldy 200 pages, will come in at about 50 pages, said Michael Henderson, director of regional planning and coordination. Instead of duplicating sections of other RTO documents, links will be provided.
In response to stakeholder feedback, the plan will be produced every other year. It had formerly been produced annually.
It will include forecasts of gross load, energy efficiency and behind-the-meter photovoltaics and projections of systemwide need for capacity and reserves, along with transmission system needs.
A draft will be posted for PAC review on July 7, with comments and reviews scheduled throughout the summer. The final document will be presented at a public meeting on Sept. 14.
FERC on Thursday granted a complaint by New England generators that a penalty imposed during a summer heat wave proved that a rule intended to punish resource withholding is unjust and unreasonable (EL16-120).
The commission agreed with the New England Power Generators Association that the peak energy rent adjustment should be raised. (See Generators: ‘Unjust’ Rule Cost $100M in New England Heat Wave.) But it ordered that the amount of increase should be determined in an evidentiary proceeding if stakeholders cannot reach a settlement.
“NEPGA has demonstrated that, as a result of the new reserve constraint penalty factors, the relationship between the amount of compensation that suppliers receive for energy in scarcity periods, and the amount that suppliers must rebate as a result of the operation of the PER mechanism, has rendered the existing PER mechanism unjust and unreasonable,” the commission wrote.
“We agree with NEPGA that for the time period in question, capacity resources were unable to anticipate a future increase in reserve constraint penalty factors and, accordingly, were unable to reflect a corresponding increase in their capacity offers.
“We additionally find that, as NEPGA has suggested, this problem can be remedied by raising the PER strike price. Doing so would return the PER rebate to an amount that more closely reflects the expectations of the parties at the time of the seventh and eighth Forward Capacity Auctions in February 2013 and 2014, respectively, the commission wrote. The higher penalty factors were ordered by the commission in May 2014.
NEPGA said the adjustment created “absurd” results during a six-hour period of intense heat on Aug. 11 that featured unexpected outages and high prices.
The PER adjustment reduces capacity suppliers’ monthly capacity payments by an amount that approximates the “peak energy rents” earned by a hypothetical generator in the real-time energy market.
When the hourly real-time energy market price exceeds a predetermined “strike price,” the RTO calculates an “hourly PER” value that roughly equals the difference between the real-time clearing price and the strike price. These monthly values are added for the month, averaged over a rolling 12-month period and then deducted from suppliers’ monthly capacity payments.
NEPGA requested that the PER strike price be increased by $250/MWh, the same change ISO-NE proposed to stakeholders in 2014. “We note that, while ISO-NE may have found this to be a reasonable increase previously, recent market developments may justify a different increase,” the commission wrote.
FERC last year approved a Tariff change submitted by ISO-NE that eliminates the PER adjustment on June 1, 2018, at the start of the ninth capacity commitment period. The RTO said reforms in the day-ahead energy market and the Pay-for-Performance program that starts on the date have made the rule unnecessary.
FERC on Thursday accepted a settlement that replaces the New York Power Authority’s stated transmission rates with a cost-of-service formula including a base return on equity of 8.95%. NYPA will receive an additional 50 basis points for its participation in NYISO (ER16-835).
Lineman on transmission pole | New York Power Authority
The organization will receive a 50-basis-point “congestion relief adder” for the Marcy South Series Compensation project in Delaware County for the original $55.7 million cost of the project. Costs exceeding the cap will revert to the base ROE.
NYISO filed the request on NYPA’s behalf in January 2016, with the commission ordering a settlement proceeding in March. The settlement, which was not contested, was supported by FERC trial staff. The commission said the rate formula became effective April 1, 2016.
NYPA was ordered to file an amended Tariff within 30 days.
The organization last January said it needed to convert to a formula rate because it anticipates spending approximately $726 million in its transmission life extension and modernization program through 2025. Some assets are more than 70 years old, NYPA said.
FERC last week rejected PJM’s proposal for revising how it implements its financial transmission rights forfeiture rule, ordering the RTO to instead adopt a portfolio approach suggested by the Independent Market Monitor (EL14-37).
The commission, however, declined to order any refunds.
The ruling was the result of a Section 206 proceeding ordered in 2014 to determine whether the RTO was improperly treating up-to-congestion trades (UTCs) differently than increment offers (INCs) and decrement bids (DECs).
Up-to-congestion transactions, which fell sharply following a FERC order setting Sept. 8, 2014 as the effective date for potential uplift charges, rebounded after the 15-month refund period expired.
The order says the forfeiture rule should be applied to UTCs as well as INCs and DECs. The order did not address whether uplift — currently assessed on INCs and DECs — should also be applied to UTCs. Instead, it said that issue would be considered in broader Notice of Proposed Rulemaking on uplift cost allocation. (See related story, FERC Proposes More Transparency, Cost Causation on Uplift.)
The forfeiture rule was implemented in 2000 to prevent market participants from using virtual transactions to create congestion that benefits their FTR positions. The FTR holder forfeits the profit from its FTR when it submits an INC or a DEC at or near an FTR location that results in a higher LMP spread in the day-ahead market than in real time.
The commission ordered the 206 investigation after PJM proposed redefining UTCs as virtual transactions and making them subject to the forfeiture rule, which had previously been applied only to INCs and DECs. (See FERC Orders Review of UTC Rules.)
Worst-Case Scenario
The current rule evaluates virtual transactions individually against the “worst-case” bus — the location at which the transaction has the biggest impact on congestion. A forfeiture is triggered if at least 75% of the energy flowing between the transaction bus and the worst-case bus is reflected in the constraint.
PJM had proposed continuing to evaluate transactions individually but replacing the worst-case bus technique with a generation-weighted reference bus to evaluate DECs and a load-weighted reference bus to evaluate INCs.
Under the worst-case approach, one trader’s INC (an offer to sell energy at a specified source location in the day-ahead market) may be paired with a different market participant’s DEC (a bid to purchase energy at a specified sink location day ahead). PJM said that can result in forfeitures occurring when they should not.
False Positives, Negatives
But the commission ruled that the RTO’s proposed fix didn’t go far enough, saying the individual transaction approach does not capture the impact of a market participant’s overall portfolio of virtual transactions on a constraint.
“This may lead to forfeitures from some participants who have offsetting positions elsewhere and thus whose virtual transactions did not actually impact the constraint. Likewise, the rule may fail to invoke forfeiture on some participants who do not impact the constraint with a single transaction but have additive positions elsewhere that, on net, do impact the constraint significantly,” the commission said.
It ordered PJM to adopt the Monitor’s proposal to evaluate the net effect of a participant’s entire virtual portfolio — INCs, DECs and UTCs — on the constraint.
A UTC would be included in the portfolio as an INC at its source point and as a DEC at its sink. Because UTCs include both source and sink, there is no corresponding worst-case bus with which to compare it. (In a related order, the commission also accepted a PJM compliance filing establishing the criteria for determining the source-sink paths for UTCs (ER13-1654-001, ER13-1654-002)).
FERC also ruled that PJM must evaluate power flows using a load-weighted reference bus, which PJM already uses to calculate certain components of LMP, instead of the worst-case bus. As a result, the commission said, the 75% trigger should be replaced with one based on a percentage of the total binding megawatt limit of the constraint related to the FTR path.
“Specifically, to trigger a forfeiture, the net flow across a given constraint attributable to a participant’s portfolio of virtual transactions must meet two criteria: (1) The net flow must be in the direction to increase the value of an FTR; and (2) the net flow must exceed a certain percentage of the physical limit of a binding constraint,” the commission explained. “Although any volume can cause congestion, this second condition recognizes that increased volumes relative to the binding limit are more symptomatic of transactions that increase the value of an FTR.”
It noted that CAISO uses a such a method in its congestion revenue rights settlements. The ISO determines that congestion has been significantly impacted if a CRR holder’s entire portfolio exceeds 10% of the constraint’s flow limit.
The commission said eliminating the worst-case bus would increase the transparency of the forfeiture methodology, allowing market participants to monitor their own activity to determine if they are significantly impacting constraints related to their FTRs.
Compliance Filing
FERC ordered PJM to submit a compliance filing within 90 days to modify its Tariff to incorporate the new approach.
It rejected concerns that the portfolio approach would discourage transactions at liquid trading spots such as zones, hubs and interfaces, saying transactions at those locations should be included in the forfeiture evaluation.
It also ruled that counterflow FTRs and virtual transactions that relieve congestion should no longer be exempt from the forfeiture rule. “Holders of counterflow FTRs are able to manipulate congestion to benefit their FTR position,” the commission said.
The commission rejected calls from some trading firms to eliminate the forfeiture rule, saying that the requests were outside the scope of the proceeding and that the rule was necessary to deter cross-product manipulation.
Despite finding the current methodology not just and reasonable, FERC said refunds were “not appropriate.”
“As some parties have indicated, they have based market decisions on the current Tariff rules that cannot now be revisited, and the commission has not always ordered refunds when market decisions are affected. Moreover, while market participants were on notice that the FTR forfeiture rule might change, the nature of any change was uncertain. The bids, offers and decisions market participants made could have been different had they been aware of the nature of the revised FTR forfeiture rule.”
The RTO had requested the waiver in response to a federal court ruling vacating an EPA rule that would have allowed greater use of emergency generators. FERC granted the waiver in August, effective June 21, 2016.
Real-time emergency generators are distributed generation limited by air quality permits to operating when ISO-NE implements voltage reductions of 5%. They must be able to go into operation within 30 minutes of the RTO’s dispatch instructions.
The waiver was prompted by a May 2015 ruling by the D.C. Circuit Court of Appeals reversing an EPA exemption that allowed the generators to operate 100 hours a year for emergency demand response.
“Because the court vacated the EPA rules that allowed emergency generators to respond to a 5% voltage reduction, [real-time] emergency generation resources can no longer operate when ISO-NE implements voltage reductions and can only operate when their host facilities lose off-site power, unless they are retrofitted to comply with the EPA’s National Emissions Standards,” FERC wrote.
The waiver allowed such generators to change their resource type to real-time DR within a timeframe that otherwise would not be possible, permitting them to participate as DR in the February 2017 Forward Capacity Auction.
Enerwise Global Technologies’ CPower sought rehearing, contending the waiver did not fully address the problems caused by the D.C. Circuit ruling. It sought additional relief, arguing that emergency generator holders of capacity obligations would suffer financial penalties because they would not be able to convert all their assets to DR resources or shed their supply obligations in time for the 2017/18 capacity commitment period that starts in June.
FERC said that CPower’s proposed relief was “in effect, a separate request for waiver of an additional Tariff provision” and thus beyond the scope of ISO-NE’s request. Last week’s order clarifies that it was dismissing CPower’s proposal without prejudice, meaning the company could file a new request under a separate docket.
FERC on Thursday approved CAISO’s agreements to procure frequency response from the Bonneville Power Administration (ER17-408) and Seattle City Light (ER17-411).
The contracts are intended to help the ISO comply with NERC reliability standard BAL-003-1, which requires each balancing authority area to carry sufficient capability to respond to a frequency event. System operators must maintain the grid at a frequency of 60 Hz or risk instability that could lead to cascading blackouts.
CAISO signed the deals after conducting a competitive solicitation that examined each bidder’s previous frequency response performance as well as comparing the costs of procuring transferred capacity against those for obtaining regulation-up service within the ISO’s market. The commission agreed with the ISO’s finding that transfers represented the lowest-cost option.
Rich in fast-ramping hydroelectric resources, BPA and City Light are both well-positioned to provide frequency response capacity to third parties.
Under the agreements, BPA and City Light will provide CAISO with frequency response and document their performance with NERC for the compliance year beginning Dec. 1, 2016. In the event of nonperformance, either entity will be liable for covering any fines levied against the ISO.
FERC’s acceptance of the agreements is subject to the clarification of a September order in which the commission approved the ISO’s competitive solicitation process.
CAISO sought clarification on whether the commission would recognize contracts that allow a counterparty balancing area to provide transferred frequency response to it based on the ISO’s annual frequency response obligation under the NERC standard (ER16-1438).
Without that clarification, the ISO contended, counterparties could interpret the decision as requiring them to maintain a net actual interchange measure in response to every single frequency disturbance event.
“Such a requirement would make it virtually impossible for the CAISO to contract for transferred frequency response quantities because balancing authorities cannot assure such a measure in response to every disturbance event,” the ISO said in its request for clarification.
