In an announcement rich with symbolism, transmission developer Anbaric said it will spend $650 million to build a delivery hub for offshore wind at Brayton Point, the former site of New England’s largest coal-fired plant.
Anbaric said it will spend $250 million on a 1,200-MW HVDC converter to receive offshore wind power and another $400 million on 400 MW of battery storage at what it is calling the Anbaric Renewable Energy Center. The May 13 announcement by Anbaric and Commercial Development Co., the owner of the 307-acre site in Somerset, Mass., came just days after the former coal plant’s 500-foot cooling towers were imploded.
Terms of the lease between the two companies were not released, but CDC Executive Vice President Stephen Collins said the lease is “very long.”
Artist’s depiction shows Anbaric’s planned HVDC and battery storage project and other potential offshore wind facilities, including space for storing turbine components on land that was once covered with coal piles. | Anbaric
Anbaric CEO Edward Krapels said the project is part of his company’s plan for its Massachusetts OceanGrid to bring wind power from projects off southeastern Massachusetts, Cape Cod, Nantucket and Martha’s Vineyard to ISO-NE.
Stephen Conant, an Anbaric partner and project manager for the Brayton Point project, said construction could begin as early as 2021, depending on how soon Anbaric signs up generation to use the facilities.
Anbaric is counting in part on Massachusetts’ 2016 directive ordering Eversource, National Grid and Unitil to procure 1,600 MW of offshore wind.
Conant said his company will partner with an unnamed generator to bid for an 800-MW OSW solicitation the utilities are expected to issue later this month. But he said Anbaric is “open to working with any and all” OSW generators, including those off of Rhode Island and Connecticut.
“It’s a very attractive site,” he said, noting the 1,600-MW interconnection from the old coal plant. “It’s the best interconnection facility on the south coast” of Massachusetts.
U.S. Rep. Joseph Kennedy III (D-Mass.) spoke at an announcement of the Anbaric lease. | Rep. Joseph Kennedy III
Anbaric filed a 1,200-MW interconnection request with ISO-NE in March, and Conant said the company could seek to increase that to 2,400 MW with upgrades.
The company received FERC approval in February 2018 to conduct an “open season” bidding process for OSW developers to use its Massachusetts OceanGrid to deliver OSW power to ISO-NE (ER18–435).
Anbaric said it expects its project to create 300-400 construction jobs over a two-year period, with five to 10 full-time employees running the center once completed.
“It’s certainly not going to replace the number of jobs lost at the coal plant,” which employed about 250, Conant acknowledged. But he said the “real jobs are going to come from the growth of offshore wind … and well-developed infrastructure will make that happen.”
Conn. Adding 2,000 MW?
Connecticut and Rhode Island have agreed to purchase 700 MW of OSW from Eversource’s and Ørsted’s Revolution Wind project between Martha’s Vineyard and Block Island.
In addition, the Connecticut House of Representatives on Tuesday approved legislation that would authorize Eversource and Avangrid subsidiary United Illuminating to procure an additional 2,000 MW of offshore wind. The bill, which is headed to the state Senate, calls for the issuance of a solicitation within two weeks of passage to take advantage of expiring federal tax credits, Conant said.
But Connecticut officials have their own plans for capitalizing on their procurements, earlier this month announcing agreement on a $93 million public-private partnership to make State Pier in New London an OSW hub.
Other Tenants?
Anbaric’s project will take only 20 acres of the former power plant’s 300-acre site, which CDC has renamed Brayton Point Commerce Center.
Collins said the company is “actively engaged” with about a half-dozen additional potential tenants interested in the site and its 34-foot deep port, some of them also in offshore wind or energy. “There’s an enormous amount of interest at this site,” he said. “I’ve had five meetings in the last two days.”
Bay State Wind announced a year ago it would build turbine foundations at the site if it won Massachusetts’ first 800-MW OSW solicitation, but that contract was snagged by Vineyard Wind. Collins said Vineyard Wind has talked about bringing work on the “transition piece” between the turbines’ monopole and nacelle to Brayton Point.
Brayton Point before the demolition of the cooling towers | Commercial Development Co.
Anbaric has partnered with Vineyard on the Liberty Wind project in New York but was not part of its initial Massachusetts bid.
CDC purchased Brayton Point from Dynegy in early 2018 after the 1,600-MW plant, Massachusetts’ last coal generator, shut down in May 2017 after more than 50 years of operation.
Before imploding the cooling towers last month, CDC had sold much of the plant’s equipment and machinery, begun demolishing fuel oil tanks and power plant buildings and conducted asbestos abatement and other environmental remediation.
[Editor’s Note: An earlier version of this story incorrectly stated the Connecticut House passed a bill regarding offshore wind procurement on Wednesday (May 15). The bill was passed Tuesday, May 14.]
NYISO’s Business Issues Committee on Monday approved a proposed Tariff revision that redefines acceptable collateral for foreign market participants, largely to head off cumbersome bankruptcy proceedings in foreign jurisdictions.
Sheri Prevratil, the ISO’s manager of corporate credit, presented analysis on the proposal to allow only entities formed or incorporated in the U.S. or Canada to post cash collateral.
The changes modify Section 26.6.1 of the Services Tariff and affect only four market participants, she said.
NYISO currently allows market participants to post either unsecured or secured credit, with participants not meeting unsecured credit standards required to provide secured credit.
The ISO is seeking the change to avoid the potential costs required to secure and use collateral in the case of a foreign bankruptcy. Given the potential number of jurisdictions at issue worldwide, it is not feasible for the ISO to evaluate laws in all jurisdictions to ensure its interest in cash collateral would be adequately protected, Prevratil said.
State of the Market: Peak Load Up 7%
Rising natural gas costs and increased load levels were the two key factors that drove up NYISO electricity prices by 23% to 36% in 2018, Pallas LeeVanSchaick of the Market Monitor told the BIC while presenting a summary of the 2018 State of the Market Report.
The report showed peak load up 7% last year — “quite a large increase,” LeeVanSchaick said.
Average gas prices rose 21% to 47% across the state, with much of the increase caused by a cold spell in early January, while gas price spreads between western and eastern New York fell, leading to less west-to-east transmission congestion, LeeVanSchaick said.
The state’s electricity consumption rose from low levels seen in 2017, with average load up 3% and higher congestion occurring within New York City and Long Island.
“These factors also increased day-ahead congestion revenues, which we saw go up by 21% to just over $500 million in 2018,” LeeVanSchaick said.
Declining gas price spreads helped to reduce NYISO’s west-to-east transmission congestion in 2018, the Monitor found. | Potomac Economics
LeeVanSchaick said the current capacity market produces prices for only the four modeled capacity regions and may produce incentives for excessive investment in some export-constrained areas and insufficient price signals for investment in import-constrained load pockets or in areas that improve reliability elsewhere, such as Long Island.
The four-zone model may not allow prices to change efficiently as units retire and enter, or transmission is built, and incentive issues become more acute with anticipated policy-induced retirements and new resource additions, as well as resource retention necessary to support local reliability in NYC load pockets, he said.
Based on those considerations, the Monitor recommends implementing a more granular locational capacity pricing mechanism, LeeVanSchaick said.
Included among the multiple policies aimed at removing capacity sources are the Indian Point nuclear plant retirement, coal plant retirements and the state’s Department of Environmental Conservation proposal to curb emissions from peaker plants. (See NY DEC Kicks off Peaker Emissions Limits Hearings.)
LeeVanSchaick said retirement of inflexible generation is needed to make room for state-sponsored resources and flexible resources that help integrate them, and that requires efficient market incentives.
“Even if those [public policy] resources are not justified based on economics and competitive entry, there is still an opportunity to get an exemption through a Part A test … which in New York City essentially allows for 6% excess capacity,” LeeVanSchaick said. The Monitor’s Part A test is intended to exempt from mitigation any resource deemed to be economic compared with a NYISO forecast, allowing that resource to bid into the capacity market on the same basis as other resources.
The Monitor contends that NYISO’s four-zone capacity market may not be granular enough to send appropriate price signals to constrained regions that need new resources. | Potomac Economics
Updates to Economic Planning Process Manual
The BIC approved limited updates to the Economic Planning Process (EPP) Manual, the first since February 2016, modifying the description of historic congestion data reporting.
Timothy Duffy, the ISO’s manager of economic planning, delivered a summary of the changes, providing a brief overview of the separate generation deactivation process outlined in the overview section of the Comprehensive System Planning Process (CSPP).
The changes correct NYISO web links and make ministerial revisions for user readability, standardization of tariff references, inappropriate capitalizations and use of Tariff-defined terms, Duffy said.
NYISO-PJM JOA Revisions
The BIC approved NYISO-PJM joint operating agreement revisions, which the Management Committee will consider on May 20, and if approved, will go to the Board of Directors in June, ahead of a joint NYISO-PJM FERC filing.
Total redispatch settlement last year was “very small,” said Cameron McPherson, NYISO operations analysis and services analyst.
NYISO and PJM last September filed with FERC a joint request for waiver of their joint operating agreement to permit them to add the East Towanda-Hillside tie line as a market-to-market (M2M) flowgate. (See “NYISO, PJM Revising JOA for Tie Line Issues” in NYISO Business Issues Committee Briefs: March 13, 2019.)
Robert Pike, NYISO director for market design and product management, presented the monthly Broader Regional Markets report and highlighted the ongoing work to revise the JOA to address coordination on flowgates similar to the East Towanda-Hillside Tie Line.
Pike also highlighted continued stakeholder discussions regarding deliverability requirements for external capacity suppliers, including new rules such as those approved at the April BIC. (See “New External SRE Penalty” in NYISO Business Issues Committee Briefs: April 17, 2019.)
The requirements relate to New York capacity market eligibility, and the objective of the effort is to better understand any obstacles preventing external resources from delivering capacity-backed energy to the New York Control Area border.
Under the new proposal, any external resource that fails to meet the criteria will be subject to the penalty, which is equal to 1.5 times the applicable spot price multiplied by the number of megawatts of shortfall and the percentage of the SRE call hours to which a supplier fails to respond.
In a separate matter, the ISO is reviving its Metering Working Group, with meetings starting in July on technical issues around metering infrastructure for distributed energy resources and storage.
LBMPs Drop 25% in April
NYISO locational-based marginal prices averaged $28.01/MWh in April, down about 25% from March and the same month a year ago, Pike said in delivering the monthly operations report. Year-to-date monthly energy prices averaged $40.12/MWh, a 27% decrease from a year ago.
Day-ahead and real-time load-weighted LBMPs came in lower compared to March. Average daily sendout was 371 GWh/day in April, lower than 411 GWh/day in March and 390 GWh/day in the same month a year ago.
Transco Z6 hub natural gas prices averaged $2.37/MMBtu for the month, down 24% from March and 15.1% from a year ago.
Distillate prices were down 1.5% year over year and up slightly from the previous month, with Jet Kerosene Gulf Coast averaging $14.63/MMBtu, compared to $14.18/MMBtu in March, while Ultra-low Sulfur No. 2 Diesel NY Harbor rose to $14.72/MMBtu from $14.18/MMBtu in March.
April uplift increased to -$0.15/MWh from -$0.33/MWh in March, while total uplift costs, excluding the ISO’s cost of operations, came in higher than those of the previous month.
The ISO’s $0.20/MWh local reliability share in April was down from $0.31/MWh the previous month, while the statewide share climbed to -$0.35/MWh from -$0.64/MWh in March.
The Thunderstorm Alert cost was $0.01/MWh, unchanged from March.
ST. LOUIS — Below is a summary of the NERC Board of Directors Technology & Security Committee meeting Wednesday.
Australia and New Zealand to Join in GridEx V
GridEx V will see increased international participation, including the possible use of “active injects” from Australia and New Zealand to simulate a “worldwide assault … on Western civilization,” Chief Security Officer Bill Lawrence said.
The exercise, scheduled for Nov. 13-14, also will see increased participation by the natural gas industry, he said.
The “executive tabletop” portion of the exercise, formerly constructed as a continent-wide attack, will this time affect a “specific region with severe electric and natural gas impacts,” Lawrence said. The targets will no longer be CEOs but the “operational level: the COO, CSOs, etc.”
They will discuss what they learned from “a bad, bad day on the grid in hopes, and active preparations, that it wouldn’t happen for real,” he explained.
“GridEx is a lot about information sharing and some analysis, but really it’s the engagement opportunity. It’s building those trade routes [to industry and government] that will be of particular value,” he said.
Lawrence said he was encouraged to have the participation of Australia and New Zealand, who are members of U.S.’ Five Eyes intelligence alliance, along with the U.K. and Canada. He recalled the worldwide preparations for Y2K, when it was feared that legacy computer systems that represented four-digit years with only the final two digits would be flummoxed by the change from 1999 to 2000. “We were able to see New Zealand and Australia stay lit up [on Jan. 1, 2000,] and have a much higher confidence that North America was going to be good to go as well,” he said.
E-ISAC Continues Growth
Lawrence gave the committee an update on growth plans for the Electricity Information Sharing and Analysis Center (E-ISAC), which is expected to triple in size by the end of 2022 from the 20 staffers it had at the end of 2017.
The 2020 organization chart shows a staff of 47, an increase of seven full-time equivalents for analytics, watch operations and engagement, and three for corporate support. 2020 will be the third year of a five-year strategic plan that has already seen NERC add 19 FTEs.
The ISAC plans another 14 hires for 2021 and 2022 to enable 24/7 watch operations and support investments in technology and collaboration with strategic partners.
Lawrence said the E-ISAC is using consultants to help develop policies, such as information sharing protocols, that are “repeatable and scalable as we grow our team.”
“The E-ISAC is not as mature as we should be for a 20-year-old organization,” he said.
Lawrence said the move to a 24/7 watch operation was prompted by stakeholder input. “They want somebody who is awake at the phone. Right now, we do have 24/7 coverage but it’s with duty officers with a phone by the nightstand.”
The ISAC will initiate 24/5 operations this year with 24/7 staffing in 2020.
Lawrence praised the infrastructure support NERC is providing the ISAC. “It means that I don’t need to build my own IT, HR, legal [and] external affairs [capabilities], and I can focus on the analysts that are going to provide … value.”
Lawrence Downplays Denial of Service Incident
Lawrence decried media reports characterizing a denial of service incident involving a WECC member in March as a cyberattack, saying there has been no evidence of malicious involvement.
“It was a denial of service. So, something happened to — in this case — a piece of … communications technology — routers — that for about five minutes acted like a deer in the headlights. They went offline, causing a brief breach of communications” between the control center and generation.
The unnamed company disclosed the March 5 incident to the Department of Energy in an electric emergency and disturbance report (OE-417) that said it affected Kern and Los Angeles counties in California; Salt Lake County, Utah; and Converse County, Wyo.
Lawrence said the incident led to a “leap to conclusions” that it was caused by hackers.
“But in this case, it might have been that or something as simple as a scan that detected this certain vulnerability that’s known about these routers. So, you update them with a patch and they’re good to go against that vulnerability,” he explained. “It’s not a distributed denial of service where somebody is just slamming against the firewall and keeping the communication systems down. It’s a hiccup, and they come back on and we gain visibility.
“There was no generation loss; no customers lost service,” he said, adding that a root-cause analysis is being conducted. “Calling it a cyberattack stretches the definition of cyberattack.”
The following day, however, FERC Commissioner Bernard McNamee described the incident as an “attack” during remarks to the Board of Trustees. McNamee said afterward he was speaking based on media accounts and not information shared with FERC.
ST. LOUIS — The NERC Board of Trustees voted Thursday to approve a supply chain report and a new standard on third-party transient electronic devices while eliminating 84 reliability requirements. Below is a summary of the actions on, and discussions of, standards at the May 8-9 meetings of the Trustees and the Member Representatives Committee (MRC).
Standards Efficiency Review Retirements OK’d
Completing Phase 1 of the Standards Efficiency Review (SER) project begun in 2017, the trustees approved the complete retirement of 10 standards and the elimination of some requirements for seven standards.
NERC also approved the withdrawal of MOD-001-2, which has been awaiting FERC approval since February 2014 (RM14-7). It was intended to ensure that calculations of available transmission system capability support reliability and that the methodology and data behind the calculations are disclosed to applicable registered entities. The standards authorization request (SAR) said the standard was no longer needed because other standards, including subsequent improvements to transmission operator rules, ensure that real-time operations observe system operation limits.
Each of the changes received 87 to 97% approval on balloting that closed May 2, said Howard Gugel, director of engineering and standards. (See NERC Standards Retirements Go to Final Ballot.)
In total, 77 requirements and part of one requirement are being retired in addition to the six MOD requirements being withdrawn.
The seven standards for which only some of the requirements were eliminated were given updated version numbers reflecting the revisions:
FAC-008-4 – Facility Ratings
INT-006-5 – Evaluation of Interchange Transactions
INT-009-3 – Implementation of Interchange
IRO-002-7 – Reliability Coordination – Monitoring and Analysis (reflecting the retirement of Requirement R1 and a variance for reliability coordinators in WECC; see below.)
PRC-004-6 – Protection System Misoperation Identification and Correction
TOP-001-5 – Transmission Operations
VAR-001-6 – Voltage and Reactive Control
Gugel said FERC staff have expressed concerns over a few of the retirements but that NERC staff agree with the rationale provided by the standards development team and are confident that the retirements will not cause any vulnerabilities. “When we file this with FERC, we will provide additional supporting arguments and lay out how all these standards requirements hold together to bridge any potential gap,” he said in response to a question from Chair Roy Thilly.
| NERC
Team Reviewing Feedback on SER Phase 2
Phase 2 of the Standards Efficiency Review is considering changes in six areas of the organization’s operations and planning (O&P) and critical infrastructure protection (CIP) standards.
John Allen, chair of SER Phase 2, briefed the MRC on the results of the industry survey that ended March 22 with submissions from 75 participants. (See “Chair Urges Comments on Standards Efficiency Review,” NERC Standards Committee Briefs: March 20, 2019.)
Participants were asked to indicate via a 1-10 scale how much they supported each of six concepts.
Changes to the evidence-retention rules, which vary by standard, ranked highest at 8.12, said Allen, manager of reliability compliance for the City Utilities of Springfield (Mo.). It was closely followed by consolidating information/data exchange requirements (8.11); moving requirements to guidance (7.85; and developing a risk-based standards template (7.78).
Less popular were relocating competency-based requirements to the certification program/controls review process (6.85) and consolidating and simplifying training requirements (6.19).
The Phase 2 team will use the feedback to evaluate and prioritize the concepts for potential action.
Trustees OK WECC Variance; Questions on Gen-only RC, Calif.-Ariz. Seam
The trustees approved reliability standard IRO-002-6 (Reliability Coordination – Monitoring and Analysis), which adds a variance for the WECC region to address its transition to multiple reliability coordinators (RCs) with the demise of Peak Reliability. (It was immediately supplanted by IRO-002-7, reflecting the retirement of Requirement 1 from SER Phase 1.)
The variance requires each RC to develop a “common interconnection-wide modeling and monitoring methodology” for use in operational planning analysis and real-time assessments, including facility ratings, thermal limits and steady state voltage limits.
“Actions that happen up in the Northwest can impact the Southwest, so for us it’s important to have that coordination across the entire model,” David Godfrey, WECC’s vice president of reliability and security oversight, told the board in an update on the RC transition.
The Eastern Interconnection, which has 16 RCs, has not asked for the standardization requirement WECC sought, Gugel said.
“In the Eastern Interconnection, there’s a lot of coordination that occurs there, but the geographic spread and regional diversity there sometimes doesn’t lend itself to requiring a common model,” he said. “Something going on in Florida for an operation situation may not be necessary for the folks up in Manitoba. It does seem to be necessary out in the Western Interconnection, but we’re continuing to evaluate whether it would be necessary in the East.”
Godfrey’s presentation included a map showing most of the West has chosen CAISO’s or SPP’s RC services but that several generation-only balancing areas — wind, solar and gas units — have selected Gridforce Energy Management.
Western Interconnection reliability coordinator footprints, with GridForce RC marked as red dots. | WECC
“This will fit within our certification criteria?” Thilly asked.
“We’re early in that part of the process,” responded NERC General Counsel Charlie Berardesco. “I would ask a little patience as we consider the application and the actual technical details. … We haven’t made a determination on anybody yet.”
CEO Jim Robb said the transmission operators and balancing authorities are accountable for ensuring they have an accredited RC.
“We’ve made it very clear when this whole regime change started to occur a year-and-a-half ago that if — by the time Peak winds down — there aren’t certified reliability coordinators in place, we pull out heavy-duty enforcement actions,” Robb said.
He also said he was concerned about the seam between Arizona and California, noting “that’s been a corridor where bad things have happened in the past.”
“Are we pretty confident that seams agreements that are being developed will provide for fairly seamless operations on those paths?” he asked Godfrey.
Godfrey said he was, adding, “We will continue to monitor that to make sure that [the agreements are] enforced.”
NERC Task Force to Build on EPRI EMP Study
Mark Lauby, NERC senior vice president and chief reliability officer, told the MRC that the organization is launching a task force in response to the Electric Power Research Institute’s April report on the threat of electromagnetic pulses.
The EPRI report concluded a high-altitude nuclear explosion could cause a multistate electric outage but not the nationwide, monthslong blackout some observers have warned of. (See EPRI Report Downplays Worst-Case EMP Scenario.)
Lauby said the task force will review the EPRI report to identify additional research needs and best practices and potential reliability standards for mitigating the impacts. He noted that the report did not look at the impacts on generation.
The group is expected to begin work this month and present any SARs to the Standards Committee, if needed, in the fourth quarter.
“This is not to relitigate the research results,” Lauby said. “But rather, now with what we’ve learned from those results … we are better informed to understand exactly what makes sense from a guideline perspective or standard perspective.”
Robb told the Board of Trustees on Thursday that Lauby has laid out an “aggressive” timeline.
“We now understand the science,” he said. “So we can galvanize our resources, and industry’s, to start to think through, ‘OK, what sort of response is required here?’”
The trustees accepted staff’s Supply Chain report, which recommends revising the supply chain standards to address electronic access control or monitoring systems (EACMS) and physical access control systems (PACS) to high and medium impact bulk electric system cyber systems. Monitoring, alarming and logging systems would be excluded.
FERC ordered NERC to expand protections to EACMS last October, when it approved the organization’s supply chain standards: CIP-013-1 and modifications in CIP-005-6 and CIP-010-3 (RM17-13, Order 850). (See FERC Finalizes Supply Chain Standards.)
Among the best practices cited in the report are use of “well-known, trusted and established vendors” and those with third-party accreditations or self-certification of their supply chain practices.
“We stand ready to facilitate; we don’t intend to be the accreditor but do want to be a part of the process,” Gugel told the MRC on Wednesday.
The report did not recommend including all low-impact BES cyber systems in the standards but called for additional study on whether low-impact systems with external routable connectivity should be covered. Staff are working on a data request under Section 1600 of the NERC Rules of Procedure to obtain additional information on the subject. It also will continue monitoring the issue through questionnaires and surveys.
To address potential risks to such systems in the interim, staff will work with the Critical Infrastructure Protection Committee (CIPC) Supply Chain Working Group to develop guidelines to help entities evaluate their protected cyber assets on a case-by-case basis. The report also recommends that entities refer to best practices of the North American Transmission Forum, North American Generation Forum, National Rural Electric Cooperative Association and the American Public Power Association.
CIP Standard Approved
The trustees approved CIP-003-8 (Cyber Security – Security Management Controls) in response to FERC’s April 2018 order approving CIP-003-7 and directing NERC to modify it to “mitigate the risk of malicious code that could result from third-party transient electronic devices.”
Section 5.2.1 in Attachment 1 of CIP-003-7 requires the use of at least one safeguard before connecting a transient cyber asset to a low-impact BES cyber system, including reviews of antivirus updates and application whitelisting.
The revision adds a new section 5.2.2 to ensure that the entity acts to mitigate any risks identified in the reviews from Section 5.2.1. It requires entities to “determine whether any additional mitigation actions are necessary and implement such actions prior to connecting the transient cyber asset” (Project 2016-02).
The evidence that entities can provide of compliance include documentation from change management systems, email and contracts that identify a review.
FERC Briefing
Andy Dodge, director of FERC’s Office of Electric Reliability, provided the MRC an update on two reliability standards pending before the commission:
Comments are due June 24 on FERC’s April 18 Notice of Proposed Rulemaking proposing to adopt CIP-012-1 (Cyber Security – Communications between Control Centers), which would require protections for communication links and data communicated between BES control centers and clarify the types of data that must be protected (RM18-20). (See FERC Proposes Revisions to NERC CIP Standard.)
Also pending is CIP-008-6 (Cyber Security Incident Reporting), which NERC filed on March 7 in response to a July 2018 FERC order (RM18-2). The commission called for expanded reporting of cybersecurity incidents, saying attempts not currently reported could lead to bigger, more successful attacks. The standard would expand mandatory reporting to include actual or attempted compromises of an entity’s electronic security perimeter (ESP) or associated EACMS. (See FERC Orders Expanded Cybersecurity Reporting.)
Dodge also mentioned FERC staff’s March 29 report on lessons learned from commission-led CIP audits in fiscal 2018. The second in what is intended as an annual report, it includes the results of the audits by the Office of Electric Reliability and input from the Office of Enforcement and Office of Energy Infrastructure Security.
The report makes 13 recommendations, including implementing valid security certificates within BES cyber systems; using strong encryption for interactive remote access; and replacing or upgrading “end-of-life” system components of cyber assets.
ST. LOUIS — Below is a summary of operational issues and personnel changes discussed at meetings of the NERC Member Representatives Committee (MRC) and Board of Trustees on May 8 and 9.
The board approved the filing of NERC’s Five–Year Performance Assessment with FERC, NERC’s argument for why it and the regional entities should be recertified as the Electric Reliability Organization under the Energy Policy Act of 2005.
In renewing NERC as the ERO in November 2014, FERC ordered it to continue to improve consistency and developing performance and reliability metrics (RR14-5). It also directed NERC to compare actual project completion times with estimated times and begin analyzing repeat violations by registered entities.
After NERC files the assessment, FERC will open a docket to invite public comment on the ERO’s performance.
Among the accomplishments NERC cited during the 2014-2018 assessment period:
The use of assessments and events analysis to identify, prioritize and mitigate risks to the bulk power system.
The enactment of reliability standards on cybersecurity, physical security and planning risks.
“Enhancements” to NERC’s Compliance Monitoring and Enforcement Program (CMEP) and its Electricity Information Sharing and Analysis Center (E-ISAC).
Improved efficiency by increasing the “alignment” of NERC and its REs.
Potential Change to Committee Structure
NERC is considering a restructuring of its Operating, Planning and Critical Infrastructure Protection committees to address the increasing overlap in their activities, Mark Lauby, NERC senior vice president and chief reliability officer, told the MRC.
Lauby said the current committee structure, which has been in place for more than a decade, is “expensive and time-consuming for NERC members.”
The accelerating speed of change is causing a “blurring” of the committee silos and requires “cross-cutting [and] rethinking of many utility paradigms,” he said, noting that several REs have changed their committee models.
Because each of the three “technical” committees “identify and assess risk,” Lauby said, a “stakeholder engagement team” that includes Lauby, MRC Chair Greg Ford and Trustees Ken DeFontes and Fred Gorbet, has been working since January on potential changes. The team is considering two alternatives:
Retaining the three committees while adding an Oversight Committee to coordinate their work; or
Replacing the three committees with a new Reliability Council reporting to the board.
The team will refine its proposal through July 18, when it plans a webinar to outline its plan. It is scheduled to be presented to the MRC about Aug. 15 and the board Nov. 6, with implementation in January.
Lauby said NERC’s “advisory” committees (Compliance Certification, Standards and Personnel Certification Governance) have “distinct” missions and are not part of the review. Also exempt is the Reliability Issues Steering Committee, which Lauby said “has a unique charge and participation model.”
On Thursday, the trustees approved amendments to the Standards Committee Charter to streamline it, clarify responsibilities and eliminate content discussed in other NERC governing documents, including provisions regarding Canadian representation and field tests. The charter was last changed in 2015.
Changes to State of Reliability Report
John Moura, NERC director of reliability assessment, said the organization is changing the format of its annual State of Reliability Report, reducing its length from more than 200 pages to less than 50 and replacing some tables with infographics. The report is intended to identify system performance trends and reliability risks, and measure the health of the grid and the success of mitigation measures.
Moura said the change in format resulted from a decision to make the report more useful to regulators and industry leaders.
Before, “the audience was everybody: It was engineers, policymakers; it was anyone who wanted to know something about reliability. And if it’s for everybody, it’s for no one,” he said. “So, we were really focused on, who was our target audience? And then that really kind of set the stage for everything else. I asked the question[s]: ‘What does [PJM CEO] Andy Ott want to know about this? What does [FERC Chair] Neil Chatterjee want to know?’”
The draft was circulated to the Operating and Planning committees for comment last week.
The board will review and approve the release of the report in mid-June, with a target release date of June 19, before FERC’s June 27 reliability technical conference.
Members Cautioned on Public Statements
General Counsel Charlie Berardesco disclosed that NERC’s Feb. 22 revision to its Participant Conduct Policy resulted from a Wall Street Journal op-ed whose author cited his NERC affiliation.
Although Berardesco did not identify the author, it was an apparent reference to a Feb. 20 op-ed by Robert Blohm that said renewable energy can’t consistently balance power supply with demand. Blohm, a managing director at consultancy Keen Resources, was identified in the article as “an elected member of the Operating Committee and the Standards Committee” of NERC.
In a letter to the editor in response, Michael Goggin, vice president of consultant Grid Strategies, was likewise identified as “an elected member” of NERC’s Planning Committee.
NERC’s revised policy states: “Unless authorized by an appropriate NERC officer, individuals participating in NERC activities are not authorized to speak on behalf of NERC or to indicate their views represent the views of NERC, and should provide such a disclaimer if identifying themselves as a participant in a NERC activity to the press, at speaking engagements or through other public communications.”
“We understand that people want to be involved and work in the arena of advocacy,” Berardesco said. “But NERC has to have the ability to control the message on behalf of NERC.”
“If you are doing an op-ed … best not to reference NERC at all because it’s confusing,” Chairman Roy Thilly added.
Trustees’ Pay Unchanged
Trustee DeFontes told the board’s Corporate Governance and Human Resources Committee that NERC will not be changing the trustees’ salaries, which were last increased in August 2018. The board agreed then to increase the annual retainer by $15,000 to $127,500 in three $5,000 steps between 2019 and Jan. 1, 2021. The board chair’s retainer is being raised to $175,000 in three steps over the same time period. Committee chairs receive an additional $10,000 and vice chairs are paid $5,000 annually.
Budget Updates
The ERO expects to end the current fiscal year about $3 million (1.5%) over budget, largely because of SERC Reliability’s expansion into Florida, NERC Controller Andy Sharp told the board’s Finance & Audit Committee on Wednesday.
SERC is projected to run $5.1 million over budget because of its absorption of the Florida Reliability Coordinating Council, which expects to run $1.6 million below budget, a net increase of $3.5 million.
NERC and the remaining REs are expected to be at or near budget for the year, Sharp said.
Through March 31, the “ERO Enterprise” was $2.9M (5.9%) under budget for expenses and capital spending.
Chief Financial and Administrative Officer Scott Jones gave the committee a preview of the proposed 2020 budget, which anticipates a 3.8% increase after a 9.5% increase in 2019.
The projected assessment for 2020 is $72 million (+4.5%) from 2019, which was itself up 9.5% from 2018.
Costs for the E-ISAC are growing 13.3% while the rest of NERC will be flat to lower, Jones said.
Jones said “inflationary pressures on pay,” especially for technical roles, have forced NERC to boost its annual salary increases to 3.5% from a historical 3%.
Jones said NERC has had to become “more flexible” on pay ranges because of the competition for talent. “We’ve had a history of being very rigid on the pay side. When we budget something … we sort of box ourselves in a little bit for that particular role,” he said. “When we find good people, especially on the ISAC side, we want to negotiate hard and fair, but we also want to make sure we get good people.”
First drafts of the budget are expected to be posted about May 17, with comments due June 28. The final draft will be posted July 15, with comments due July 31.
Personnel Changes
The meetings included several personnel matters:
CEO Jim Robb announced the appointment by the board of new vice presidents Mechelle Thomas, chief compliance officer, and Howard Gugel, head of standards and engineering.
Nominating Committee Chair George Hawkins announced that the committee agreed to renominate Thilly and Trustee Suzanne Keenan to new terms and has hired executive search firm Leadership Lyceum to seek a new candidate to replace Janice Case, who will end her final term in February 2020. The trustees will review candidates at their next quarterly meeting in August. (The board increased to 12 members with the election in February of Colleen Sidford, representing Canada. It will drop back to 11 in February 2020 following the departure of Case and Frederick W. Gorbet.)
The trustees also approved the following committee appointments:
Critical Infrastructure Protection Committee: John Greaves, Georgia Power, replaces Brian Harrell, formerly of Duke Energy as SERC’s representative. Doug Currie, Hydro One, replaces Francis Bradley of the Canadian Electricity Association as the CEA representative.
Reliability Issues Steering Committee: Woody Rickerson, ERCOT, replaces Dave Osburn, Oklahoma Municipal Power Authority, for a term ending Jan. 31, 2020.
Compliance and Certification Committee: Appointed Nicole Mosher, Nova Scotia Power, representing the Northeast Power Coordinating Council. Reappointed Gregory Campoli, NYISO, representing ISOs/RTOs; Ted Hobson, JEA, representing FRCC until its dissolution; Jim Stanton, SOS International, representing Small End-Use Electricity Generators.
Planning Committee: Appointed Richard Kowalski, ISO-NE, as an ISO/RTO representative for the remainder of the 2018-2020 term. Kowalski will fill a vacancy resulting from the passing of Dana Walters of NYISO.
CAMBRIDGE, Md. — Most of PJM’s recent market rule changes — including those still pending before FERC — came and went too quickly for the liking of advocate groups, though their desire for deceleration stops at an overhaul of financial transmission rights.
“Getting oversight is critical,” said Ruth Ann Price, Delaware Deputy Public Advocate, during the Public Interest & Environmental Organizations User Group’s meeting with the RTO last week. “PJM must decide with some urgency whether it wants to create a department internally [to oversee] FTRs or have this function go outside to a third party.”
Restructuring FTR rules remains a paramount stakeholder task after an independent probe identified the shortcomings in PJM’s market design and internal culture that allowed a small trading shop, GreenHat Energy, to amass the largest portfolio of FTRs in PJM history without the collateral to back it up. (See Report: ‘Naive’ PJM Underestimated GreenHat Risks.) The 890 million MWh default could wind up costing PJM more than $430 million, former CFO Suzanne Daugherty told stakeholders in January. (See PJM: FERC Order Could Boost GreenHat Default by $300M.)
“This is something that is totally out of the realm of consumers, but yet and still, they will pay the burden of this debacle,” Price said. “For PJM to continue this market, there need to be cultural changes in PJM that understand the oversight necessary.”
Price emphasized the need to fill Daughtery’s vacant CFO position and find a qualified chief risk officer — as recommended in the GreenHat report — sooner rather than later, preferably before the August capacity auction. She also encouraged PJM to expand the Independent Market Monitor’s authority to include regulation and monitoring of FTRs.
CEO Andy Ott said during his keynote address at PJM’s Annual Meeting last week that he continues working hard to implement staffing changes as quickly as possible, though finding qualified candidates to manage the RTO’s FTR market rule changes takes time.
Transmission Wave
The Consumer Advocates of PJM States advised the RTO to “follow the money” as it navigates transmission planning and the anticipated wave of new projects in the coming decades.
“We appreciate the commitment to ensuring competition on the market side,” said Mike Gahimer of the Indiana Office of Utility Consumer Counselor. “We’d like for that same focus to occur on the transmission side.”
Advocates agree that while PJM lacks jurisdiction over supplemental projects — those proposed by transmission owners and identified as not necessary for reliability, operational performance or economic criteria — the growing share of such projects also lacks federal and state oversight.
The transparency of PJM transmission planning has long been a topic of debate among stakeholders, with several expressing concern that the ballooning share of supplementals — $5.7 billion in 2018, according to CAPS — may displace the priority of baseline projects, which only totaled just over $2 billion that same year. PJM is currently in the midst of a special Planning Committee process to revise existing manual language that details the intersection of these projects. (See “RTEP Removal Language Vote Deferred, Again,” PJM MRC/MC Briefs: April 25, 2019.)
“What PJM is saying is, ‘Trust us we got this’,” Gahimer said. “I’m more of a trust-then-verify guy, and I don’t think PJM has got this.”
PJM Should Prioritize Costs, Too
Advocates want PJM to care about project costs as much as they do, said Erik Heinle of the D.C. Office of the People’s Counsel.
“PJM has an obligation to be honest and transparent about the potential costs of any initiative at the beginning and throughout the stakeholder process,” he said, noting that inaccurate modeling and a failure to recognize the interplay of markets often leaves consumers paying twice.
The rushing to file market changes — including proposals for fuel cost policy, distributed energy resources, storage and black start resources — leaves some stakeholder groups unable to analyze the true impact of the proposals and provide valuable feedback.
“Adequate stakeholder review is not just a courtesy, but ensures the impacts of changes are fully vetted and lessens the chances of design flaws,” he said.
The advocates proposed the formation of a Strategic Planning Committee to meet four or six times a year to better inform the transmission planning process and ensure that costs and market impacts are fully understood.
CARMEL, Ind. — MISO is seeking to improve how owners of load-modifying resources interact with a key communications system that some market participants think hampered the RTO’s response to a grid emergency this past winter.
Stakeholders have criticized the nonpublic MISO Communications System (MCS) webpage — where LMR owners update their availability — as being difficult to navigate, with some suggesting it hinders clear communication during grid emergencies. The RTO is in the process of upgrading the system to a more updated format.
MISO control room | MISO
Speaking at a Resource Adequacy Subcommittee meeting Wednesday, Customized Energy Solutions’ Ted Kuhn said the MCS may have contributed to confusion during the Jan. 30 maximum generation event, for which the RTO issued about $2 million in penalties for LMR underperformance. (See “MISO: $2 Million in Penalties for Jan. 30 LMR Underperformance,” MISO Reliability Subcommittee Briefs: May 2, 2019.)
“There was a lot of misunderstanding about what was going on. There were people that were getting, in my opinion, poor information from the MCS. … Things are not set up the way they should be,” Kuhn said.
In April, Consumers Energy’s Jeff Beattie asked if MISO had considered that it was working on improvements to the MCS at the time of the January emergency before it issued penalties. Beattie said some market participants may have misconstrued the timing of the request for LMRs as being across peak hours instead of just during the emergency.
MISO Director of Resource Adequacy Coordination Laura Rauch said the RTO has reached out to LMR owners to talk about how to improve communication protocols. MISO is also creating additional training classes for owners of LMRs.
CARMEL, Ind. — MISO last week proposed to change the deadlines and deliverability requirements for next year’s Planning Resource Auction as it continued to release detailed data from this year’s event.
At a Resource Adequacy Subcommittee meeting Wednesday, MISO Manager of Capacity Market Administration Eric Thoms kicked off his presentations on a lighthearted note as his team continues to break down the auction results.
“There’s a common term floating around: post-PRA hangover,” Thoms joked. “A lot of caffeine helps.”
Last month, MISO’s annual capacity auction cleared at $2.99/MW-day in all zones but Lower Michigan’s Zone 7, which cleared at $24.30/MW-day. Prices declined sharply compared with last year’s nearly uniform $10 clearing price. Altogether, the RTO committed 134.7 GW worth of capacity for the 2019/20 planning year beginning June 1. (See Most MISO Zones Clear at $3/MW-day in 2019/20 PRA.)
MISO is still releasing more detailed data on this year’s auction.
Thoms said multiple zones in MISO contained marginal resources that set the $2.99/MW-day price.
This year’s auction was the first to include external resource zones based on external balancing authorities. As a result, MISO cleared about 1,533 MW from SPP, PJM, Ohio Valley Electric Corp., LG&E Energy Transmission Services, Associated Electric Cooperative Inc., Southwestern Power Administration and the Tennessee Valley Authority.
MISO said the auction results were generally consistent with its loss-of-load expectation (LOLE) study, though LOLE load forecasts were slightly higher than those submitted by load-serving entities. The PRA’s system coincident peak of about 124.9 GW was slightly lower than the LOLE study prediction of 125.5 GW.
Timeline Change Next Year
MISO is considering changing some timelines before for the 2020/21 PRA, including deadlines for demand response testing, submission of generator verification testing data, behind-the-meter registration, unforced capacity values and the posting of preliminary auction data. In most cases, the various deadlines would be extended into the winter instead of late fall.
MISO is also proposing to open and close the offer window during “normal business hours.”
“My staff doesn’t like getting up at 12:01 a.m. to open the offer window and close it at 11:59 p.m. on a Friday night,” Thoms said.
The RTO would like to open the PRA’s four-day offer window at 8 a.m. ET and close at 6 p.m. Currently, the offer window runs from 12:01 a.m. on the first day of the auction through 11:59 p.m. on the fourth day.
“We’ve never received any offers at 2 a.m.,” Thoms added.
MISO said it may make a Tariff filing in summer to alter the PRA timeline.
New Deliverability Rules
MISO will also require that its traditional resources be deliverable to their full installed capacity (ICAP) values by the 2020/21 planning year auction.
The capacity deliverability rules will apply to resources with both network resource interconnection service (NRIS) and energy resource interconnection service (ERIS). However, the rules will not apply to intermittent resources — including wind, solar and storage devices — whose deliverability requirements will be based on some sort of historical or average output. The exact process has yet to be proposed.
Darrin Landstrom, MISO resource forecasting adviser, said the change in deliverability requirements won’t have a big impact on cleared megawatts in the auction. He said some generators may have to request broader transmission service, which could take up to a maximum of 105 days for study and approval. MISO estimates that about 1.4 GW of capacity clearing this year’s auction may not be deliverable to installed capacity levels.
Both the Independent Market Monitor and the Coalition of Midwest Power Producers (COMPP) have contended that MISO doesn’t properly account for deliverability because its LOLE study assumes that all capacity resources are fully deliverable on an ICAP basis. However, the RTO allows resources to demonstrate deliverability only up to the unforced capacity (UCAP) levels, which tend to be about 5 to 10% below full ICAP levels. FERC: No Merit in MISO Deliverability Complaint.)
MISO requires capacity resources to demonstrate deliverability either by having NRIS, which stipulates that the entire ICAP be deliverable, or ERIS, which requires that firm transmission service be reserved up to the UCAP level.
The RTO has said it doesn’t hold capacity resources to different standards because it doesn’t require NRIS resources to perform to ICAP levels, instead requiring both to demonstrate deliverability up to their UCAP levels for the purposes of the capacity auction. But the RTO is now proposing to require ICAP-level performance across the board beginning with the 2020/21 auction.
MISO is seeking stakeholder opinions and suggestions on the new deliverability requirement through the end of the month. The RTO said it may make changes to its Business Practices Manuals.
COMPP’s Mark Volpe said he thought the changes might constitute a new “condition of service” that would require parallel changes to the Tariff as well as the BPMs.
MISO General Counsel Michael Kessler responded that the RTO’s legal team would monitor the proposal to see if it requires a Tariff revision.
Seasonal Plans
MISO is meanwhile still making plans to adopt a seasonal component for its capacity auction but will hold the proposal until the 2021/22 planning year. (See MISO Gives Tentative Nod to Seasonal Capacity Design.) RTO staff are currently conducting analyses on introducing a seasonal construct.
HOUSTON — During a recent workshop on the Mexican power market, Tenaska’s Bob Anderson ran through the litany of woes wrought on the market since President Andrés Manuel López Obrador took power last year.
The canceled power auctions, the gutting of the regulatory commission, the reconstitution of the state-run electric business — the government’s heavy hand in creating more uncertainty in an already fragile market.
Still, Anderson said, Tenaska’s vice president of business development, you will find some investors willing to take a chance in the Mexican market.
“It won’t be Tenaska,” he said. “We at Tenaska are not speculative traders.”
“I am a bit more sanguine about this,” Que Advisors’ Peter Nance said. “My experience in Latin America tells me that rules will change, but there will still be opportunities for private capital. Nevertheless, the new situation may be considerably different than the old, and there may be certain participants that are disadvantaged by the changes.”
“It’s a real-life three-ring circus, but the clowns are in charge,” said a more sardonic Mannti Cummins, who is working to develop a wind farm in Baja California Sur. (See Land Rights a Challenge to Mexico Tx Developers.)
José María Lujambio Irazábal, who heads the energy practice for Mexican law firm Cacheaux Cavazos & Newton, said the changes will result in a stronger state-run utility (the Federal Electricity Commission (CFE)), a weaker regulatory body (the Energy Regulatory Commission (CRE)) and a neutered Ministry of Energy (SENER).
A former member of President Felipe Calderon’s administration (2006-2012), Lujambio Irazábal said CFE will enjoy a “privileged position” under the new administration. Its octogenarian CEO Manuel Bartlett Díaz is determined to “Make CFE Great Again,” Anderson said, having felt insulted by the 2014 reforms designed to open up Mexico’s electricity market. “He will tell you the ignorant ways that was done,” he said.
Cummins called it a back-to-the-future agenda, designed to strengthen CFE by reconsolidating the various generation businesses created by the reform. The focus is now on maintaining the utility’s aging fossil plants, as that will mean jobs.
“Any unit that CFE has that can run, should run. You’re talking about 500 different maintenance jobs to prepare for this summer,” Anderson said, noting the upgrades will make about 4 GW of additional capacity available this summer.
That should be a welcome development for the Mexican grid, which has seen its reserve margin drop from about 6% last year to less than 2% this year, said Rebecca Bollenbach of Essentia Advisory Partners. She said Mexico suffered through 44 cases of “emergency situations” and more than 1,000 alerts last year.
“Six percent is [grid operator] CENACE’s happy place right now,” Bollenbach said. “When ERCOT looks at a 6%, 7% reserve margin, everyone gets real nervous.”
Already this year, the Yucatan Peninsula has been twice hit with major power outages, leaving millions of people across three states in the dark for more than an hour.
Perhaps that’s why in April, CFE’s board approved an expansion plan to develop 13 GW of new facilities, all owned and operated by the utility. The first major projects involve five combined cycle gas-fired plants with an aggregate capacity of 2.76 GW, at a cost of $2.4 billion.
“That’s a substantial shift from the last administration,” Nance said.
‘Real Doozies’
In the meantime, López Obrador’s administration canceled a long-term auction, the fourth in a series, planned for last December. Bartlett Díaz has said there will be no more power auctions.
“Why should we buy electricity when we can produce it ourselves?” he told El Financiero, a business publication. “We are not going to discuss this; the CFE is not a company that buys electricity. It is a company that produces and distributes electricity. Why should anyone force us to buy electricity?”
It apparently won’t be the CRE, which had its budget reduced by 31.1% in December and then fired about 60% of its workforce.
“That’s a great amount of technical and intellectual capital out the door,” Anderson said.
López Obrador was also able to fill four vacancies among the seven CRE commissioners, appointing them himself when he was unable to gain approval from the Mexican Senate. All four newcomers come from petrochemical backgrounds.
“Some real doozies,” Cummins said. “Heavy on state control, lacking orientation of any sort to electrical markets.”
“Some of them are not real experts,” said Lujambio Irazábal, a former general counsel at CRE. “Who will regulate the market and impose sanctions when needed?”
Lujambio Irazábal said SENER, Mexico’s counterpart to the Department of Energy, is facing many of the same issues.
“With no undersecretary of electricity appointed, a dramatic lack of expertise and no political commitment to keep promoting new developments in the market, who will design and implement electricity policy?”
López Obrador himself has been all over the map. He initially promised new coal plants, thus reducing Mexico’s dependence on U.S. gas, before April’s announcement of five combined cycle projects. He has talked about repowering the country’s hydro installations, and the administration has publicly announced a goal of 100,000 solar rooftop installations by 2024.
“If you want to make jobs, many jobs can result from installing stuff on rooftops,” Nance said.
Mexico’s demand for power continues to grow at an annual rate of 2 to 3%. While the country has 75 GW of capacity on the grid, about a third of it is aging and unreliable or dependent on similarly aging transmission lines. Demand is expected to hit 50 GW for the first time this year.
In addition to canceling remaining power auctions, the López Obrador administration also pulled tenders for two major transmission projects up for international bids: the $1.2 billion, 870-mile, 500-kV connection between Mexicali in Baja California and Hermosillo, Sonora, in northwestern Mexico; and the $1.7 billion, 1,000-mile, 500-kV Oaxaca project between Mexico City and Veracruz.
The projects were “not a priority for the government,” Bollenbach said.
“You still have 3% growth nationwide. How are you going to meet that demand?” Nance questioned. “In an operational sense, there’s a very, very low reserve margin for certain hours of the year. Eventually, someone has to build something.”
Anderson called the language private investors hear “very aggressive … so most of us just back away.”
He said the market needs to express why the reforms are so important. “It wasn’t to tip the scale for private companies. It was to create market efficiencies,” Anderson said.
Foreign investment is not dead, however. Spain’s Iberdrola recently said it plans to spend $1.3 billion in five new generation plants — two combined heat and power, two wind farms and a combined cycle plant — as part of an initiative to invest $5 billion in Mexico over the next six years. The power will be marketed to “private enterprise” as part of an agreement with the Confederation of Industrial Chambers.
“There’s still room for international capital. My view is that it will just be put to work in different ways,” Nance said. “With the pending CFE restructuring, you could have a separate business unit focused on new technologies that could partner with other firms. That might be where development takes place. Improved partnerships with CFE might be a more expected and typical outcome of all this.”
CARMEL, Ind. — MISO last week said it now plans to have a market participation model for energy storage resources in place by early 2021, having filed a request for delay of FERC’s fourth-quarter compliance deadline.
Director of Market Design Kevin Vannoy confirmed the proposed timeline at a Market Subcommittee meeting Thursday.
MISO announced in April that it would seek at least another year to comply with More Info Needed on MISO Storage Participation Plan.) Vannoy said MISO’s filing focused more on providing explanation about the proposal instead of altering it.
Vannoy said when considering the “70-odd” requirements in FERC’s storage rule, some aspects of MISO’s plan make sense to RTO staff, but not third parties reviewing the proposal.
MISO now seeks an order on the storage participation plan by July. The RTO was originally beholden to a Dec. 3 go-live date for compliance with the storage order.
In the filing, MISO said the “complexity and expense” of its storage participation plan would negatively affect its ongoing effort to replace its aging market platform.
Vannoy said not receiving a FERC order on its proposal by April further backlogged “an already stressed schedule,” bogged down by the market platform replacement and a higher-than-expected cost to implement the storage plan with a third-party vendor.
MISO’s recent filing defined the phrase “very small” electric storage resources as those under 1 MW, answering one of FERC’s questions. The RTO has requested limiting participation of very small storage resources to 50 in the first year of compliance and 150 in the second year. FERC’s rule directed that all storage devices 100 kW and larger be allowed the opportunity to participate in RTO markets.
Vannoy said the limit on small storage devices is necessary to limit “administrative processes for the paperwork and modeling that can be somewhat burdensome.”
MISO also clarified that market participants will be responsible for maintaining their state of charge and updated an attached agreement on distribution-connected storage to clarify that storage owners will have to make metering arrangements.
At last month’s Informational Forum, CEO John Bear said MISO staff are currently studying energy storage case studies, including the Hornsdale Power Reserve in Australia, to determine how storage will fit into long-term planning.
Vannoy promised to return to the Market Subcommittee this summer to update stakeholders.
