The D.C. Circuit Court of Appeals last week rejected rehearing requests from Missouri River Energy Services (MRES) following the court’s earlier determination that SPP could charge the utility for certain transmission fees (18-1166).
MRES, an organization of 61 municipal utilities in the upper Midwest, appealed the ruling, saying the court had committed multiple errors in its decision. It said the opinion “directly conflicts” with a 2007 decision by the court involving Wisconsin Public Power and FERC.
In that case, “FERC agreed with [MISO] that imposing significant changes in scheduling practices between parties to pre-existing agreements would amount to ‘significant changes’ … affect[ing] the bargain between the parties,’” MRES said in its appeal.
Quoting the 2007 panel, the organization said, “Not carving out this narrow class of [grandfathered agreements] would modify them, thereby triggering application of Mobile-Sierra’s public interest standard.”
In rejecting MRES’ original argument in March, the court said SPP “did not seek to impose congestion and marginal loss charges on the 1977 reservation until Missouri River subsequently came within the pool’s footprint.”
FERC in 2017 ruled that the SPP members were ineligible for “carve-out treatment” under the SPP Tariff and a 1977 transmission service contract between Nebraska Public Power District and Basin Electric Power Cooperative.
The 1977 contract arose from construction of NPPD transmission needed to deliver power to the Western Area Power Administration’s Upper Great Plains region and Lincoln Electric System from the Missouri Basin Power Project — a venture owned by six public power and cooperative utilities that includes the 1,710-MW Laramie River coal-fired generator, the Grayrocks Dam and reservoir, and more than 500 miles of extra-high-voltage transmission.
ISO-NE on Thursday proposed a “hybrid” filing Section 205 of the Federal Power Act to allow some generators to recover the costs of NERC critical infrastructure protection (CIP) requirements, but Eversource Energy suggested alternatives, saying it doesn’t want the costs collected as part of its transmission rates.
The RTO’s Jonathan Lowell made the proposal at a meeting of the New England Power Pool’s Transmission Committee on Thursday. It would allow cost recovery for generators designated by the RTO as “critical” to the determination of interconnection reliability operating limits (IROLs), which have higher CIP standards than other generators.
Violations of IROLs can lead to instability, uncontrolled separation and outages cascading into neighboring regions. Generators are designated as IROL-critical because of their characteristics and locations relative to other control areas, the RTO said.
ISO-NE says it has about as many IROLs as all other ISOs and RTOs together. “Because New England is at the eastern end of the Eastern Interconnection, a contingency in New England can have significant reliability impacts on systems to the west,” explained ISO-NE spokeswoman Marcia Blomberg. “Many interconnection reliability operating limits have been identified in New England to avoid creating those impacts, and many facilities have been determined to be critical to the determination of those limits.”
The RTO is proposing to make a Section 205 filing with FERC to add a new OATT Schedule 17 for the billing and collection of FERC-approved IROL-CIP costs, with the RTO serving as billing agent. It would be based on a formula rate template listing recurring and nonrecurring costs.
The initial filing will “facilitate a smooth and efficient FERC review of the Section 205 formula rate filing by having resolved most controversies in advance,” the RTO said in a presentation.
Critical generators and similarly situated transmission facilities would then make their own Section 205 filings itemizing their costs for FERC review and approval.
ISO-NE said the two-step filing is necessary because the RTO cannot be responsible for supporting the costs of individual facilities.
‘Inappropriate’
But Cal Bowie, representing Eversource, told the committee in a presentation that it is “inappropriate” for generators to recover expenses through regional network load transmission charges. “Transmission charges should primarily reflect the costs of building, operating, maintaining and ensuring the reliability of the transmission system,” Eversource said.
The company said the RTO should instead consider collecting the costs under its capacity load obligation (used to recover the “missing money” not recovered by generators in the energy market) or real-time non-coincident peak load obligations (Schedule 3 reliability administration service costs). Eversource also said the RTO should create a separate billing item for CIP costs to make them transparent.
According to the New England States Committee on Electricity, transmission costs are between 11 and 18% of total electric bills for residential customers in the region. Total transmission charges have risen from about $869 million in 2008 to $2.25 billion in 2018, NESCOE says.
Asked whether ISO-NE could accommodate Eversource’s proposal, Blomberg said the RTO believes its cost-allocation plan “is the most appropriate solution to ensure compensation” for the NERC compliance requirement.
“The ISO is continuing to listen and discuss this issue with stakeholders,” she added.
In a presentation to the Transmission Committee on March 27, ISO-NE had proposed a cost-of-service reimbursement method, saying a 2017 effort to create a formula rate failed because the RTO was unable to identify a methodology to determine an IROL-critical “proxy” generator or estimate reasonable costs for compliance with the NERC standard.
ISO-NE says the lack of “clear and precise CIP requirements” in standard CIP-002-5.1a Attachment 1 may lead generators to differing interpretations on what steps they need to take. The RTO said costs disclosed by the operators of seven IROL-critical generating stations showed both one-time capital costs and recurring O&M expenses. There was no obvious correlation between costs and generator size, type or vintage, ISO-NE said.
Blomberg said a formula rate is not the same as a proxy rate approach. “Under a formula rate approach, the facility submits its specific costs for approval. A proxy rate is an estimate of the costs of a generic, but similar, facility without consideration of the actual costs. IROL-CIP facilities all have different characteristics, which make proxy rate approach extremely challenging.”
ISO-NE said IROL-CIP costs should be allocated to regional network service and through or out service because accurate IROLs allow the RTO to maximize use of the transmission system.
Lowell told the committee at the March meeting that the ISO-NE would consider alternatives to the cost-of-service proposal if it had broad support within NEPOOL and had a cost estimation methodology the RTO could defend as just and reasonable.
NERC spokesman Martin Coyne declined to comment on the RTO’s characterization of the CIP requirements.
“[We] can’t comment on a presentation that’s not ours or for security purposes discuss details on critical facilities,” he said.
He added: “It is common for entities to seek information from NERC on how specific requirements in our stakeholder consensus-based standards apply to them.”
Business Procedure Change Approved
In other matters, the committee approved ISO-NE’s proposal to make administrative changes to Ancillary Service Schedule 2 of Section II of the Tariff and the VAR Business Procedure, along with revisions to accommodate electric storage reactive resources. The changes move requirements from the Business Procedure into the Tariff and incorporate electric storage facility language into the Schedule 2 capacity cost compensation program.
The RTO said the changes were related to FERC’s Feb. 25 approval of revisions to Section II that created multiple constructs for storage devices to participate in the RTO’s day-ahead and real-time energy markets (ER19-84). (See FERC Accepts ISO-NE Storage Tariff Revisions.)
FERC last week proposed adopting the North American Energy Standards Board’s (NAESB) Standards for Business Practices and Communication Protocols for Public Utilities, which implement the commission’s requirements under the pro forma Open Access Transmission Tariff (RM05-5-027).
Version 003.2, approved by NAESB’s Wholesale Electric Quadrant, includes changes from WEQ Version 003.1, which were the subject of an earlier FERC Notice of Proposed Rulemaking that was never completed (RM05-5-025).
WEQ Version 003.2 also includes changes to make it consistent with NERC reliability standards regarding dynamic tagging and pseudo-ties, and the transition of NERC’s electric industry registry tool to NAESB.
NAESB is an industry forum that develops standards for the wholesale and retail natural gas and electricity industries. | NAESB
The NOPR does not include NAESB’s WEQ-023 Modeling Business Practice Standards, which govern the calculation of available transfer capability for transmission, which is the subject of a separate rulemaking (RM05-5-025). It also has issued a separate NOPR proposing the retirement of the WEQ-006 Time Error Correction Business Practice Standards (RM05-5-026).
The commission also declined to incorporate into its regulations the Standards of Conduct for Electric Transmission Providers (WEQ-009); Contracts Related Standards (WEQ-010); and WEQ/WGQ eTariff Related Standards (WEQ-014).
NAESB’s voluntary standards become mandatory for FERC-regulated public utilities after they are incorporated into the commission’s regulations.
Redirects
FERC said it would not incorporate the preamble to WEQ 001-9 “because it leaves the implication that a transmission operator could adopt a ‘transmission provider-specific business practice’ that is at odds with the reason for establishing common business practices standards under the NAESB standards development process.”
The commission’s 2002 Dynegy decision set its policy on a customer’s right to keep the contractual rights to firm transmission service it had reserved while the customer’s request for a redirect was pending (EL01-104).
The commission said a transmission customer submitting a redirect request does not lose its rights to its original path until the redirect request is accepted by the transmission provider, confirmed by the transmission customer and passes the conditional reservation deadline under the transmission provider’s OATT.
In declining to adopt the preamble, the commission rejected arguments by the Edison Electric Institute, Public Utility District No. 1 of Snohomish County, Wash., and the city of Tacoma, Wash.’s Department of Public Utilities that the commission should allow redirects from a conditional parent reservation on a case-by-case basis, calling it “antithetical to the NAESB standards development process.”
MISO last week shut down the prospect of allowing non-transmission owners to operate storage-as-transmission assets (SATA) in the RTO’s initial ruleset for the resources, just as a new poll revealed that most stakeholders want to devote more time to weighing the possibility.
Planning Advisory Committee sectors last month voted via email in favor of further discussion on a DTE Energy proposal that MISO’s first SATA rules include a path for non-TOs — as well as TOs — to own and operate SATA. (See MISO Floats Draft Storage-as-Tx Rules.)
The motion passed with 5.5 votes in support, 2.5 votes in opposition and two abstentions from MISO’s Coordination Member and State Regulatory Authorities sectors. Opposition votes came from the Transmission Owner and Eligible End-User Customers sectors, with the transmission developer sector splitting its vote. MISO’s 10 sectors can divide their single vote to reflect differing opinions within a sector. Results were revealed during a special May 15 conference call of the PAC.
MISO determined earlier this year that only registered TOs would be eligible to own SATA in order to avoid introducing complexities around cost recovery, particularly related to how non-TOs would be compensated for providing transmission services.
DTE has said non-TO SATA should be permitted to bypass the interconnection queue and connect to MISO’s transmission system through newly conceived storage interconnection agreements. Absent that provision, DTE has said MISO’s SATA ruleset would create preferential treatment for TOs and create barriers to entry for storage.
Still, MISO is staying course that SATA should only be developed by existing or eligible new TOs, with staff explaining that non-TO-owned SATA is simply too complicated to introduce.
“While we appreciate the idea and the effort that DTE and other stakeholders have put into this … we simply don’t accept this proposal,” MISO Director of Planning Jeff Webb said.
Webb said MISO’s upcoming filing will detail the discussion the PAC has held on the possibility of non-TO SATA. However, he said the RTO has a “fundamental disagreement” that an asset used exclusively to address a transmission issue and is connected to the transmission system can simultaneously be a non-transmission asset.
“We think FERC’s been pretty clear that storage should exist within current generation, transmission and distribution [classifications],” Webb said.
“Obviously there will be some sectors that are disappointed in this result, especially with the PAC vote,” DTE’s Nick Griffin said.
MISO still maintains that non-TO-owned storage can already enter the transmission planning process under the non-transmission alternatives (NTAs) provision (BPM 020), which allows generation and demand-side resources to serve as alternatives to transmission proposals and be studied under the annual Transmission Expansion Plan (MTEP). However, NTAs must either scale the interconnection queue or connect via the distribution system. Under the proposed SATA rules, a transmission system connection without a queue requirement would be reserved only for TOs that operate SATA.
Stakeholders criticized the NTA provision as being seldom used. Griffin said it is essentially “there for show, but not for use.”
Webb agreed that the NTA process could use modeling improvements.
Invenergy also repeated criticisms that MISO’s first SATA rules are too narrow, are discriminatory and were crafted in a “deficient stakeholder process.”
But MISO said it created rules “appropriate in addressing storage as transmission.”
“We do not agree that treatment of storage as a transmission asset is discriminatory, nor that the nearly yearlong stakeholder process has been deficient,” the RTO said.
MISO Manager of Expansion Planning Lynn Hecker said staff are still working through how to estimate the useful life, degradation and lifetime cost of ever-evolving storage technologies to be able to evaluate them against traditional wires in the MTEP.
The RTO plans to make its first SATA filing with FERC in late June. Webb said he would return to the June PAC meeting with a final proposal.
Stressing the importance of being efficient and effective, the Texas Reliability Entity’s Derrick Davis last week shared with his Board of Directors a new process to help the regional entity devote more time to its ERO responsibilities.
“I’m going to say more efficient and more effective 1,000 times,” said Davis, director of enforcement, reliability standards and registration, during the board’s Wednesday meeting.
Davis told the board that the RE’s new mitigation verification sampling process will be, of course, “more efficient and more effective” in resolving smaller issues, freeing up staff to perform other tasks.
TRE staff will verify mitigation for compliance exceptions on a sample basis. Registered entities will be required to provide an affidavit identifying the details of mitigation activities and source documents. Entities will hold the mitigating evidence for 18 months after being notified of compliance exception treatment or upon completion of mitigation activities, whichever is later.
Staff have also begun using a new triage process to obtain disposition information faster. Davis said enforcement staff will ask for “pertinent disposition information” earlier in the process than before, leading to quicker validations.
“In the past, we haven’t had an answer for an entity that self-reports and waits for the enforcement group to get with them,” he said. “We’re going to get to you faster now, so that we can close these out.”
2020 Risk Elements Focus on Resource Adequacy
Staff have proposed three regional risk elements to focus on for 2020: data integrity and situational awareness; resource adequacy; and insufficient dynamic performance and loadability by transmission and generation providers.
Risk Assessment Manager Jeff Hargis told directors that risk elements are translated into audit scopes. These specific, defined risks are determined on an annual basis, he said.
“We live in the future,” Hargis said.
He said the resource adequacy risk is not a result of ERCOT’s slim summer reserve margins, but whether or not resources adequately support frequency and voltage and stay online during transient events. Multiple resource failures can lead to system instability or a significant loss of generation, Hargis said.
Texas Tops Other REs in Effectiveness Survey
COO Jim Albright told directors that TRE bested all other REs on NERC’s 2018 ERO effectiveness survey. The Texas RE registered an average score of 3.91, based on a 5-point scale; the Florida Reliability Coordinating Council came in second, with an average score of 3.88.
TRE received its highest score (4.23) for its business planning and budgeting process, which stakeholders found provide reasonable opportunities for input and offer sufficient information, Albright said. It was also rated highly for its audit reports and audit process (4.19 and 4.14, respectively) and for enforcement (4.13).
The organization fared poorest in enforcement and standards, with no score higher than 3.77. Still, it was rated highest among the regions for its regional reliability standards addressing risk in a cost-effective manner.
2018 ERO effectiveness survey: overall averages by region | Texas RE
Respondents favorably commented on the “competent” compliance monitoring and enforcement staff and found the organization’s self-certification process to be an “effective engagement method.” However, they dinged TRE for a lack of transparency and consistency on the penalty and internal risk assessment processes.
“When you look at the number of penalties we actually had, it’s a small number,” Albright said, noting TRE has only assessed “six or seven” penalties in recent years. “The opportunities to be transparent are few and far between.”
The ERO effectiveness survey, composed of 76 questions across five topic areas, is conducted every two years. TRE received 92 responses in 2018, up from the 54 it received in 2016. It has 222 entities registered in its region.
2018 ERO effectiveness survey: topic areas | Texas RE
“We’re reaching more people, which is a good thing,” Albright said.
He also said TRE’s certification process has received a clean report from NERC.
Board Approves 2018 Budget, Audit
The directors approved the RE’s 2020 business plan and budget of $13.8 million, a 5.8% increase over the current budget. The approval is subject to “no material changes,” as NERC has not completed its review of the budget.
The Member Representatives Committee approved the budget May 3.
The board also approved accounting and advisory firm BKD’s 2018 financial audit report, which had no reported findings, and accepted its financial statements for the same year.
VALLEY FORGE, Pa. — The PJM Public Power Coalition will draft a problem statement and issue charge that examines capacity interconnection rights in the wake of a new rule permitting the RTO to take them from generators under certain circumstances.
Carl Johnson, representative for the coalition, said his group wants a broader discussion about CIRs and whether the current structure makes sense.
“The reason I want to have a broader conversation is so that we can get to some sort of agreement about what those rights are,” he said. “We argue a little about what those rights represent.”
The decision came after stakeholders debated whether to revise the existing must-offer exception process problem statement to address CIR relinquishment, or create an entirely new document for approval during Wednesday’s Market Implementation Committee meeting. Stakeholders at both the MIC and the Markets and Reliability Committee have expressed concern over a joint plan from PJM and the Independent Market Monitor that revokes CIRs from generators without plans to become Capacity Performance-capable after seeking a must-offer exception. (See Load Interests Endorse PJM-IMM Must-offer Proposal.)
The new rule, however, doesn’t apply to renewable resources because those generators don’t have a must-offer requirement. The Monitor said it will prevent others from “hoarding” CIRs indefinitely.
“All resources should not be able to hoard CIRs,” David “Scarp” Scarpignato of Calpine said Wednesday. “If you are going to have a rule like that, it should apply to everyone.”
Sharon Midgley, Exelon’s director of wholesale development, argued the conversation can move forward but with its own approved problem statement and issue charge. Exelon lobbied against the mandatory revocation of CIRs during the stakeholder process, including the presentation of its own proposal to do exactly that. Despite earning a majority of MIC support in March, the PJM/IMM plan won out at the April MRC meeting.
“They should define the problem and not try to piggyback off this process, which was supposed to deal with a very narrow administrative issue,” she said.
PJM Offers Peek at Carbon Pricing Study
PJM’s Gary Helm offered stakeholders a peek inside the RTO’s methodology for its ongoing internal carbon pricing study and said staff chose the social cost of carbon (SCC) as a simulation metric.
“We don’t care what the price is; we just want a significant price for simulation,” Helm said of the choice, noting a number of states have been using the SCC since August 2016. “[The Regional Greenhouse Gas Initiative] is a few dollars, so it’s not really impacting dispatch. What if we have a carbon price that is such a level that it impacts dispatch?”
PJM’s simulation will observe the impacts of a $52.79/ton price on the market, including cases where prices rise or fall within 25% of that baseline.
Helm said one simulation will divide PJM into a non-carbon zone and a carbon zone — Maryland, Delaware and New Jersey, the three states the RTO expects to be participating in RGGI. Another simulation will measure a regionwide carbon price, ultimately considered the simplest policy to accommodate.
Staff will research the effects of one-way and two-way border adjustments to minimize both environmental and economic leakage between the regions.
Stakeholders Lukewarm on Revisiting Market Seller Offer Cap
As members await a FERC ruling on PJM’s market seller offer cap (MSOC), the RTO said it would consider alternative measurements for performance assessment hours (PAHs) — if stakeholders want to revisit negotiations.
The change of heart comes after PJM asked FERC to dismiss the Monitor’s complaint that its default MSOC was overstated, arguing that a lack of stakeholder consensus and prior commission approval of CP proved otherwise. (See PJM: Dismiss Monitor’s Offer Cap Complaint.)
In August, the Monitor concluded that ratepayers were overcharged by $2.7 billion (41.5%) in the 2018 Base Residual Auction because of economic withholding encouraged by the inflated MSOC.
The timespan for measuring performance was changed from PAHs to five-minute performance assessment intervals (PAIs) in compliance with FERC Order 825 in 2018. PJM triggers a PAI when it determines a supply reliability issue exists, providing credits for generators that overperform their capacity commitments and penalties for those that underperform.
So far, only one load shed event has occurred within PJM since the CP overhaul in 2015. The event spurred stakeholder action to revise the MSOC calculation, with four proposals failing to garner enough support for inclusion in the Tariff. PJM subsequently dropped the issue, insisting no further investigation was required. (See Monitor Defends Offer Cap Complaint.)
Stakeholders, however, expressed a mix of appreciation and hesitation on Wednesday at the offer to reopen negotiations.
“Does PJM believe in its heart of hearts that its answer is where we should be or is PJM open to other constructs?” Johnson said. “If we are just going to have the same conversation we had last year, then I think we are just better letting the complaint play out at FERC.”
“We don’t want to rehash the stakeholder process and use time to discuss matters that have already been discussed,” said Jason Barker of Exelon. “We keep having the conversation go around and around. I think we should get guidance from the commission first.”
Monitor Presents Updated 5-Minute Dispatch Problem Statement
The Monitor presented a revised problem statement about review processes for real-time security-constrained economic dispatch (RT SCED) and market pricing that PJM uses to send dispatch signals to generators and calculate LMPs.
Siva Josyula of Monitoring Analytics said a publishing price delay on April 8 — as well as a July 10, 2018, low area control error (ACE) event and corresponding Manual 11 revisions — call into question the transparency of PJM’s RT SCED processes.
The Monitor added work activities to the issue charge that ask the MIC to review the triggers for price-bounding violations and the timeline of publishing LMPs, as well as potential updates to LMP thresholds and procedures for validation checks and publishing prices. Stakeholders must also identify metrics for operator actions, including — but not limited to — biasing in the intermediate-term SCED, RT SCED and locational price calculator.
Double Payments Extend Beyond Fast-start
Adam Keech, executive director of PJM’s market operations, said a recent FERC order saying that current accounting practices provide double payments to fast-start resources puts the RTO in a difficult position.
“The issue is more of a day-ahead uplift issue,” he said. “We are left in this issue of how do we address it. If we just apply it to fast-start, it could be conceived as discriminatory. If we apply it everywhere else, it could be out of scope.”
The problem arises when PJM pays a generator for uplift in the day-ahead market but then dispatches that same resource in real time at a higher commitment. The generator has the ability to recover uplift costs PJM already paid it for a day earlier — except the issue is far broader than just fast-start resources.
Keech presented the issue as the first of several MIC educational sessions about the impacts of FERC’s recent order on the RTO’s fast-start pricing rules. (See FERC Orders Fast-start Rules for NYISO, PJM.) The RTO loses “tens of millions” annually on double payments — a relatively small problem by PJM’s standards, he said.
FERC wants PJM to address this matter in a compliance filing due July 31, as well as an informational report due Aug. 30 about how the new rules don’t raise market power concerns.
The New York Public Service Commission on Thursday continued to tweak compensation and billing for distributed energy resources, adjusting the structure of existing standby and buyback service rates and extending standby rate exemptions for two years (Case 15-E-0751).
The PSC held its regular monthly session in Albany on May 16.
The PSC’s order modifies rates “to more accurately reflect costs and benefits and to ensure that those rates are available to all interested ratepayers.”
Ted Kelly
“Standby service rates generally apply to customers who have on-site generation that serves much of their load but still depend on the utility to provide partial or backup service,” said Ted Kelly, assistant counsel for the Department of Public Service. The buyback rates determine the price customers receive for selling excess energy back into the grid.
“With interval metering becoming much more widely available due to the rollout of advanced metering infrastructure (AMI) throughout New York state, mass market standby service rates no longer need to be limited to flat fees and volumetric energy usage,” the PSC said. “Rather, rates for mass-market standby service can be measured and billed on the basis of demand in the same manner as the standby service rates applicable to larger customers.”
The order requires that all customers be eligible to opt into a demand-based rate option, irrespective of whether they have on-site DERs. It also requires greater granularity by using off-peak, on-peak and super-peak charge components, and allows the load of multiple customers in multiple buildings to be offset by a common generator.
John Rhodes
“This is obviously a complex topic,” PSC Chair John Rhodes said. “Though a complicated subject, this is a very practical approach going forward.”
Commissioner Gregg Sayre said he was “comfortable establishing a rate design that more closely tracks the cost of service.”
Diane Burman
“Standby rates have been controversial and hotly debated,” said Commissioner Diane Burman, who concurred in the approval. “I do think we were overly ambitious in 2015 in thinking that it could happen overnight and that the signal was we were ready to go.”
The order also modifies the design and administration of buyback service tariffs to eliminate or reduce barriers to deployment of DERs, and clarifies the application of grid access demand charges for energy storage systems.
Gregg Sayre
The commission also voted unanimously to continue existing statewide exemptions from standby rates, and to extend the in-service date deadline for eligible DERs until May 31, 2021 (Case 19-E-0079).
These exemptions apply to certain DERs with a capacity of 1 MW or less, including fuel cells, wind, solar thermal, solar photovoltaic, biomass, tidal, geothermal, methane waste-powered resources, and efficient combined heat and power projects, the order said.
New York utilities must implement the rule changes effective July 1.
Grid Prepared for Summer
DPS staff presented the commission a report on summer electricity preparedness that forecasts a 1 to 3% decline in energy prices compared with last summer, depending on load zone and weather conditions.
“This is very comforting for New Yorkers,” Rhodes said.
The state bases its energy price forecasts on futures trading at the New York Mercantile Exchange, and the commission said that financial hedging by utilities will also reduce any price increases this summer.
Warren Myers
“The big driving factor of course is ICAP [installed capacity], which tends to be fairly stably high in the summer downstate and, year after year, quite low upstate,” said Warren Myers, DPS director of market and regulatory economics. “And with respect to delivery charges, those, by their design through rate cases, are very stable.”
New York has sufficient generating capacity resources to supply expected customer demands and all of the state’s electric utilities are prepared to serve those expected customer demands, the report said. Peak load this summer is forecast to be 32,382 MW, down slightly from last year.
FERC on Thursday granted LS Power Grid New York’s (LSPG-NY) request for an abandoned plant incentive for a transmission project approved by NYISO (EL19-30).
| LSPG-NY
LSPG-NY (formerly known as North American Transmission) had partnered with the New York Power Authority to jointly propose two 345-kV transmission projects to address capacity shortfalls at the Central East (Segment A) electrical interface and Upstate New York/Southeast New York (Segment B) interface.
NYISO’s Management Committee had backed both projects — part of the broader AC Public Policy Transmission Project — but the ISO’s Board of Directors in April selected only one of them, awarding Segment B to a competing proposal by National Grid and New York Transco. (See NYISO Board Selects 2 AC Public Policy Tx Projects.)
“In particular, we find that LSPG-NY’s Segment A project is entitled to the rebuttable presumption that it meets [Federal Power Act] Section 219’s requirement that the project will ensure reliability and/or reduce congestion because it has been approved through a relevant regional transmission planning process,” the commission said.
LSPG-NY said in its petition that NYISO estimated that Segment A will cost $750 million (in 2018 dollars, including 30% contingency).
The commission rejected LSPG-NY’s request for the incentive for its Segment B project, as NYISO did not select it. The company filed its request in January.
Stressing the importance of being efficient and effective, the Texas Reliability Entity’s Derrick Davis last week shared with his Board of Directors a new process to help the regional entity devote more time to its ERO responsibilities.
“I’m going to say more efficient and more effective 1,000 times,” said Davis, director of enforcement, reliability standards and registration, during the board’s Wednesday meeting.
Davis told the board that the RE’s new mitigation verification sampling process will be, of course, “more efficient and more effective” in resolving smaller issues, freeing up staff to perform other tasks.
TRE staff will verify mitigation for compliance exceptions on a sample basis. Registered entities will be required to provide an affidavit identifying the details of mitigation activities and source documents. Entities will hold the mitigating evidence for 18 months after being notified of compliance exception treatment or upon completion of mitigation activities, whichever is later.
Staff have also begun using a new triage process to obtain disposition information faster. Davis said enforcement staff will ask for “pertinent disposition information” earlier in the process than before, leading to quicker validations.
“In the past, we haven’t had an answer for an entity that self-reports and waits for the enforcement group to get with them,” he said. “We’re going to get to you faster now, so that we can close these out.”
2020 Risk Elements Focus on Resource Adequacy
Staff have proposed three regional risk elements to focus on for 2020: data integrity and situational awareness; resource adequacy; and insufficient dynamic performance and loadability by transmission and generation providers.
Risk Assessment Manager Jeff Hargis told directors that risk elements are translated into audit scopes. These specific, defined risks are determined on an annual basis, he said.
“We live in the future,” Hargis said.
He said the resource adequacy risk is not a result of ERCOT’s slim summer reserve margins, but whether or not resources adequately support frequency and voltage and stay online during transient events. Multiple resource failures can lead to system instability or a significant loss of generation, Hargis said.
Texas Tops Other REs in Effectiveness Survey
COO Jim Albright told directors that TRE bested all other REs on NERC’s 2018 ERO effectiveness survey. The Texas RE registered an average score of 3.91, based on a 5-point scale; the Florida Reliability Coordinating Council came in second, with an average score of 3.88.
TRE received its highest score (4.23) for its business planning and budgeting process, which stakeholders found provide reasonable opportunities for input and offer sufficient information, Albright said. It was also rated highly for its audit reports and audit process (4.19 and 4.14, respectively) and for enforcement (4.13).
The organization fared poorest in enforcement and standards, with no score higher than 3.77. Still, it was rated highest among the regions for its regional reliability standards addressing risk in a cost-effective manner.
Respondents favorably commented on the “competent” compliance monitoring and enforcement staff and found the organization’s self-certification process to be an “effective engagement method.” However, they dinged TRE for a lack of transparency and consistency on the penalty and internal risk assessment processes.
“When you look at the number of penalties we actually had, it’s a small number,” Albright said, noting TRE has only assessed “six or seven” penalties in recent years. “The opportunities to be transparent are few and far between.”
The ERO effectiveness survey, composed of 76 questions across five topic areas, is conducted every two years. TRE received 92 responses in 2018, up from the 54 it received in 2016. It has 222 entities registered in its region.
“We’re reaching more people, which is a good thing,” Albright said.
He also said TRE’s certification process has received a clean report from NERC.
Board Approves 2018 Budget, Audit
The directors approved the RE’s 2020 business plan and budget of $13.8 million, a 5.8% increase over the current budget. The approval is subject to “no material changes,” as NERC has not completed its review of the budget.
The Member Representatives Committee approved the budget May 3.
The board also approved accounting and advisory firm BKD’s 2018 financial audit report, which had no reported findings, and accepted its financial statements for the same year.
FERC on Thursday rejected multiple requests to reconsider its landmark electric storage order, prompting a partial dissent from Commissioner Bernard McNamee over requests to allow states to opt out (RM16-23-001, AD16-20-001, Order No. 841-A).
The majority rejected requests that it allow relevant electric retail regulatory authorities (RERRAs) the ability to opt out of its storage provisions, as the commission did for demand response under Order 719. The commissioners also rebuffed questions about their authority to require that power sold by RTO markets to an electric storage resource (ESR) for resale be at the wholesale LMP.
| SDG&E
Dissent
McNamee’s 13-page dissent said the majority “fails to recognize the states’ interests in ESRs located behind a retail meter (behind-the-meter) or connected to distribution facilities.”
“I believe Order Nos. 841 and 841-A are on solid footing when they deal with ESRs connected to the transmission system and how ESRs may participate in the wholesale market, and I concur in those aspects of today’s order. I am troubled, however, that the storage orders do not fully respect or consider the impact they may have on local distribution systems, the states that regulate those local distributions systems and local retail customers,” McNamee wrote.
McNamee said he would have reconsidered the commission’s finding that it has jurisdiction over whether ESRs located behind the meter or on a local distribution system are permitted to participate in the RTO/ISO markets through the ESR participation model, and its refusal to provide states the opportunity to opt out of the participation model.
But the majority said the Federal Power Act gives FERC clear jurisdiction over storage.
It cited the Supreme Court’s 2016 EPSA ruling, which upheld FERC’s jurisdiction over the participation in RTO markets of DR resources, which are generally located on the distribution system. “The court did not find the commission’s authority to be lessened by the location of demand response resources behind the retail customer meter,” the commission said.
“We disagree with assertions by petitioners and the dissent that, unless the commission adopts an opt-out, the commission’s regulation of the RTO/ISO market participation of distribution-connected and behind-the-meter electric storage resources violates FPA Section 201. We find that the Supreme Court’s jurisdictional findings in EPSA regarding wholesale demand response apply with at least as much force to participation in RTO/ISO markets by electric storage resources engaged in wholesale sales in interstate commerce, even where those resources are interconnected on a distribution system or located behind a retail meter.”
The majority also rejected assertions that states can dictate whether resources can participate in the RTO markets through conditions on the receipt of retail service. “We acknowledge that states have the authority to include conditions in their own retail distributed energy resource or retail electric storage resource programs that prohibit any participating resources from also selling into the RTO/ISO markets. In that scenario, the owner of a resource has a choice between participating in the retail market or wholesale market. However, states may not take away that choice by broadly prohibiting all retail customers from participating in RTO/ISO markets.”
The commissioners said McNamee incorrectly suggested that the commission had required that storage “be permitted to use distribution facilities so that they may access the wholesale market.”
“Although Order No. 841 provides that states may not prohibit electric storage resources from participating in wholesale markets, that requirement does not amount to an effective right of access to the distribution system itself. As noted, Order No. 841 does not modify states’ authority to regulate the distribution system, including the terms of access, provided that they do not ‘aim directly at the RTO/ISO markets.’”
Participation Model
FERC also rejected AES’ request for rehearing over the use of a single participation model for storage.
“While we agree … that the various technologies that qualify as an electric storage resource under the definition that the commission adopted in the final rule may have different operating characteristics and that new electric storage technologies will likely emerge, we continue to find that a single participation model can be designed to be flexible enough to accommodate any type of electric storage resource,” it said.
FERC said AES had mischaracterized Order 841 as requiring that storage resources seeking to participate in RTO markets be available to RTOs as dispatchable resources. But the commission said it would change its regulations to clarify that dispatchable storage must be permitted by RTOs to participate in that manner and be eligible to set clearing prices.
RTO Requests
The commission granted SPP’s request for clarification, saying RTOs without capacity markets do not have to create such a product to comply with Order 841. “However, to the extent that an RTO/ISO has a resource adequacy construct, the RTO/ISO must demonstrate on compliance that the existing market rules governing its resource adequacy construct provide a means for electric storage resources to participate in that construct if electric storage resources are technically capable of doing so,” it said.
It rejected a clarification request by MISO, reiterating that RTOs must allow storage resources the same ability to self-schedule as other market participants.
In response to another MISO request, FERC clarified that the RTO may propose in its compliance filing a requirement that a storage resource submit its forecasted state of charge at the beginning of any market interval in which it intends to participate. “With that said, we make no findings on the proposal that MISO outlines in its request for clarification,” it added.
Minimum Size Requirement
FERC rejected the Edison Electric Institute’s request for rehearing on Order 841’s directive that RTOs establish a minimum size requirement not to exceed 100 kW, saying the threshold “balances the benefits of increased competition with the potential need to update RTO/ISO market clearing software to effectively model and dispatch smaller resources.”
It also rejected MISO’s request to phase in the minimum size requirement. “We continue to believe that, given the record showing that all RTOs/ISOs are already accommodating the participation of smaller resources in their markets and the commission’s willingness to consider requests to increase the minimum size requirement in the future, we are providing the RTOs/ISOs with adequate time to develop the requisite tariff language and update their modeling and dispatch software to comply with Order No. 841,” it said.
Charging Energy
Pacific Gas and Electric asked the commission to acknowledge that states have jurisdiction to determine how power flowing from distribution lines into the storage located behind the customer meter is split between retail consumption and wholesale charging for later discharge into the wholesale markets.
“The sale of energy from the grid that is used to charge electric storage resources for later resale into the energy or ancillary service markets constitutes a sale for resale in interstate commerce,” the commission said. “As such, the just and reasonable rate for that wholesale sale of energy used to charge that electric storage resource is the RTO/ISO market’s wholesale LMP.”
It said CAISO’s request for clarification that storage resources participating as transmission resources should not incur transmission charges for charging demand is premature, noting the ISO “has not yet filed a proposal to allow electric storage resources to provide transmission or reliability services.”
In response to another issue raised by CAISO, the commission clarified that “the RTO/ISO itself does not need to be the entity that directly meters electric storage resources.”
“We also … clarify that an RTO/ISO could require verification from the host distribution utility that it is unable or unwilling to net wholesale demand from retail settlement before the RTO/ISO ceases to settle an electric storage resource’s wholesale demand at the wholesale LMP. While Order No. 841 stated that each RTO/ISO must prevent electric storage resources from paying twice for the same charging energy, it did not specify how each RTO/ISO must implement this requirement.”
FERC rejected requests to change the compliance deadlines it set in Order 841, insisting “the timeline for compliance and implementation is reasonable.” In April, FERC issued deficiency letters to all six jurisdictional RTOs and ISOs over their compliance filings, pressing for definitions, tariff citations and other details. (See FERC Asks RTOs for more Details on Storage Rules.)
Reaction
The National Rural Electric Cooperative Association said FERC “side-stepped” the FPA in its jurisdictional ruling.
“The commission has dealt a blow to consumers and dramatically expanded its authority by giving itself the discretion to decide which distributed and behind-the-meter energy storage resources can participate in wholesale electricity markets,” NRECA CEO Jim Matheson said in a statement. “In doing so, FERC has undermined the ability of local utilities and regulatory authorities to manage these resources for the benefit of consumers.”
Jeff Dennis, general counsel for Advanced Energy Economy, praised the ruling. “We applaud FERC for upholding Order No. 841, recognizing the benefits to consumers and the grid of giving all energy storage resources, including those located on the distribution grid or behind the meter, an opportunity to participate in wholesale markets,” he said.
“We also appreciate Chairman [Neil] Chatterjee’s focus on FERC’s continued efforts to remove the barriers that keep advanced energy technologies from participating in wholesale markets. Energy storage is just one of the technologies that face barriers to entry. We urge FERC to finalize a similar rule to permit aggregations of distributed energy resources to participate in wholesale markets, utilizing the same legally sound approach taken in today’s order.”
