FERC on Thursday denied rehearing of its October 2018 order accepting NYISO’s revisions to the methodology it uses to determine locational minimum installed capacity requirements (LCRs), rejecting every one of the more than two dozen arguments made by the Long Island Power Authority (LIPA) and its subsidiary, Power Supply Long Island (ER18-1743-002).
NYISO’s installed capacity (ICAP) market rules require all load-serving entities to purchase a specified amount of capacity to count toward the statewide minimum installed reserve margin (IRM), based on each LSE’s coincident peak load. LSEs with customers in certain transmission-constrained areas, defined as “localities,” must fulfill a portion of their respective purchase obligations from capacity resources electrically located within those areas.
| NYISO
NYISO has designated three such localities: G-J, which is composed of load zones G, H, I and J in the Lower Hudson Valley; New York City (Zone J), which is nested within G-J; and Long Island (Zone K).
With the creation of the G-J locality, NYISO supplemented its former method, which recognized that the loss-of-load-expectation (LOLE) reliability standard used in setting the IRM may be achieved by carrying many different combinations of ICAP in various locations. The ISO now takes steps to calculate the LCR for the G-J locality.
In Thursday’s order, the commission found that the ISO’s alternative LCR methodology satisfies the 0.1-days/year LOLE reliability standard, which LIPA asserted was insufficiently demonstrated or certified.
“NYISO presented sufficient record evidence in this proceeding to support its claim that the alternative LCR methodology will meet the 0.1-days/year LOLE reliability standard,” the commission said. “Moreover, LIPA has not provided evidence that would persuade us otherwise.”
The commission also rejected LIPA’s request for additional technical details in the Tariff.
“We find unpersuasive arguments that the commission failed to address … NYISO’s alleged failure to model and analyze ‘known’ likely future system conditions; and the sensitivity of the alternative LCR methodology to actions, such as election of unforced deliverability rights, taken in Zone J that adversely affect Zone K,” the commission said. “LIPA’s arguments reduce to a disagreement with NYISO regarding the number and type of sensitivity analyses” that need to be performed.
FERC on Thursday approved NYISO’s proposal to allow aggregations of distributed energy resources to participate in its markets.
The commission said the proposed model enhances competition “while also providing DERs with appropriate flexibility to meet various needs both within and outside the NYISO-administered wholesale markets” (ER19-2276).
“Among other considerations, NYISO’s filing facilitates the participation of DERs and other aggregations of resources in its wholesale markets by enabling heterogenous groups of technologies to aggregate and be compensated for services that they are collectively capable of providing,” FERC said.
A group of stakeholders — Advanced Energy Management Alliance, Advanced Energy Economy, Consumer Power Advocates, Energy Spectrum, Natural Resources Defense Council and the New York Battery and Energy Storage Technology Consortium — jointly contested the Tariff revisions regarding dual participation, metering and telemetry, installed capacity market requirements, and buyer-side mitigation.
Concept for DER coordination entity aggregation (DCEA) in energy, operating reserves and regulation markets | NYISO DER Roadmap
But the commission disagreed with their concern that NYISO’s requirement that market participants must “bid in a manner that ensures they will be dispatched by the ISO for the market intervals consistent with the manner in which the resource operates to meet such obligation(s)” creates a barrier to entry.
“We find that this proposed requirement appropriately balances any additional burden placed on market participants in determining their bids against the need for NYISO’s system operators and dispatch software to account accurately for the operation of dual participating facilities,” the commission said.
It also noted that the ISO did not propose any substantive changes to its market power mitigation provisions and, therefore, it found protests of the group, the New York State Energy Research and Development Authority and the state Public Service Commission to be beyond the scope of the proceeding. The protesters had contended that application of NYISO’s existing buyer-side market power mitigation rules to DER aggregations could result in over-mitigation of the resources.
FERC also on Thursday dismissed NRG Curtailment Solutions’ complaint over NYISO’s metering requirements, saying it had been rendered moot by its approval of the ISO’s DER aggregation model (EL18-188). The commission had granted NRG’s complaint in part in 2018 and establishing a paper hearing to determine an appropriate remedy.
NextEra Energy CEO Jim Robo said Friday that battery-backed “near firm” wind and solar power will be increasingly competitive by 2025.
Speaking during NextEra’s quarterly and year-end earnings call with financial analysts, Robo predicted that new near firm wind will be a $20 to $30/MWh product and near firm solar a $30 to $40/MWh product in five years.
“At these prices, new near firm renewables will be cheaper than the operating cost of most existing coal, nuclear and less efficient oil- and gas-fired generation units,” he said. “We will be at the vanguard of building a sustainable energy era that is both clean and affordable, and we are driving very hard to continue to be at the forefront of the disruption that is occurring within the energy sector.”
Robo said his company is poised to take advantage of the “enormous disruption” taking place within the nation’s generating fleet.
“Our confidence in renewables being the low-cost generation alternative in the middle of this decade remains stronger than ever,” Robo said. “We expect the disruptive nature of renewables to be terrific for customers, terrific for the environment and terrific for shareholders by helping to drive tremendous growth for this company over the next decade.”
The Florida-based company fell short of analysts’ expectations by reporting fourth-quarter earnings of $975 million ($1.99/share). Although that more than doubled 2018’s fourth-quarter earnings of $422 million ($0.88/share), NextEra’s adjusted earnings of $706 million ($1.44/share) came in below Zacks Investment Research’s consensus estimate of $1.54/share.
The company reported year-end earnings of $3.8 billion ($7.76/share), down from $6.6 billion ($13.88/share), in 2018. NextEra also reaffirmed a 6 to 8% growth rate in adjusted earnings per share through 2021.
Robo said NextEra’s performance “was strong both financially and operationally, and we had outstanding execution on our initiatives to continue to drive future growth across the company.” Wall Street sided with Robo, driving the stock price up $6.38 shortly after market open to close at $263.70.
Renewable energy will play a major role in NextEra’s ongoing performance. The company said NextEra Energy Resources, its wholesale electricity supplier, added more than 5.8 GW to its contracted renewables backlog and commissioned another 2.7 GW of wind and solar projects. More than half of the solar additions included a battery storage component, Robo said.
Fresh off the approval of their first interregional transmission project, MISO and PJM are now contemplating a new study this year and asking stakeholders what direction it might take.
Staff from both RTOs laid out the possible options in a conference call of the MISO-PJM Interregional Planning Stakeholder Advisory Committee (IPSAC) on Friday.
PJM’s Alex Worcester said the study could take the shape of a targeted market efficiency project (TMEP) study, a special targeted ad hoc study or a two-year coordinated system plan, the last of which could culminate in the RTOs’ second-ever large interregional market efficiency project (IMEP).
Worcester asked stakeholders to submit ideas on the options by Feb. 26.
“What we’re looking for here is specific study suggestions,” Worcester said. He asked that stakeholders identify specific constraints or flowgates that could use analysis. “Saying there’s lot of congestion to be studied doesn’t really provide us a lot of direction.”
In December, the RTOs finished a data exchange on regional issues, newly approved projects near the seam and the latest historical market-to-market congestion information. They reviewed each other’s information over January.
The RTOs will hold another IPSAC meeting March 27 to explore the need for a new study. By mid-May, the Joint Regional Planning Committee — composed of planning staff from both RTOs — will render the final verdict.
During the call, a few stakeholders said they would be interested in the RTOs working on another TMEP. The two decided against conducting a third TMEP study process in 2019 after determining that only one year of additional historical data would be available coming on the heels of the 2018 study.
A TMEP must cost less than $20 million, completely cover its installed capital cost within four years of service and be in service by the third summer peak from its approval. The process has a shorter outlook than the RTOs’ IMEP process, which evaluates projects over a 15-year timeline.
Similarly, MISO and SPP will evaluate the need for a 2020 interregional study at their IPSAC meeting March 10.
The project needs MISO to implement cost allocation rules before it can proceed. MISO last week filed a plan with FERC to allocate interregional economic project costs to benefiting transmission pricing zones.
PJM members endorsed a resolution Thursday that objects to a Tariff attachment pending before FERC that would create a new confidential process to mitigate critical infrastructure on NERC’s CIP-014-2 list.
The unusual step came less than a week after a group of transmission owners submitted the proposal to the commission following several tense conversations dating back to August that left other sectors wary of its vague details.
LS Power, author of the resolution, argues that incumbent TOs don’t get exclusive rights to handling critical infrastructure on the list. Because the projects could carry significant regional implications, the company believes PJM should plan their mitigation — a point other stakeholders echoed during the Members Committee meeting on Thursday. (See PJM TO Filing Stirs Up Transparency Concerns.)
The Members Committee on Jan. 23 debates a resolution from LS Power opposing a Tariff filing that would mitigate critical infrastructure projects.
“We feel strongly that PJM should have stepped up and taken this issue under its wing as a reliability issue,” said Carl Johnson of the PJM Public Power Coalition. “It would have saved us a lot of trouble.”
The resolution alleges that the filing also conflicts with the Operating Agreement because mitigating these critical assets — which count as a subset of supplemental projects — must involve an open and transparent discussion with stakeholders. But doing so, the TOs contend, poses the dilemma that the highly secretive location of these facilities could be revealed. (See “Critical Infrastructure Resolution,” PJM MRC/MC Briefs: Dec. 5, 2019.)
The TOs also point out that NERC’s confidentiality standards — and their rights under PJM’s Attachment M-4 process — support their intention to file the mitigation plan at FERC without consent from other sectors.
In an effort to quell rising concerns, TOs collected questions from other stakeholders and hosted a webinar in November to answer some of them publicly. The two-hour meeting, however, left many issues unresolved. Seemingly frustrated by the unfolding process, the Planning Committee endorsed an issue charge in December to consider whether PJM must develop governing document language to deal with the mitigation of existing and future critical infrastructure on the list. (See “Critical Infrastructure Mitigation,” PJM PC/TEAC Briefs: Dec. 12, 2019.)
Top-secret Cost
PJM has refused to take sides in the debate, despite protests from stakeholders that mitigating the facilities presents risks to reliability that the RTO should handle. It’s a decision staff now question, Vice President of Planning Ken Seiler said. (See PJM Remains Neutral in CIP-014 Debate.)
“I agree, we could have done things differently,” he said, noting that a rough estimate of the cost to remove these assets from the list would total much less than $1 billion.
When stakeholders pressed for a more accurate cost estimate — key information many said may make them more comfortable with the Tariff filing — Seiler declined.
“We’ve looked at what the potential solutions would be and most of them are fairly simple,” he said. “Line rerouting, substation reconfiguration, very minor things that would keep the cost at a reduced rate for everybody … we are nowhere near into the billions of dollars on this.”
Sharon Segner, vice president of LS Power, said that although Seiler’s feedback was “encouraging,” there’s nothing in the Tariff proposal that caps costs.
“What would encourage my company even more would be for PJM to be in charge of these top-secret projects,” she said. “If PJM were to be in charge, then this language would go in the OA and not the Tariff. If it’s in the Tariff, at the end of the day, the TOs are in charge. There’s nothing in this language that provides cost containment. There’s a finite number of projects, but there is no restriction on cost.”
PJM Board of Managers member Susan Riley — who last month encouraged TOs and PJM to tally a cost for projects on the list — pushed back against sentiments that the RTO should have greater authority over the process.
“We’ve agreed to have an oversight role,” she said. “TOs have ultimate authority. I know the costs have been moving around, but they are moving down. We are reasonably confident that it won’t be more than $1 billion and won’t be more than 20 projects. We are committed in a very public way. Whether or not there wasn’t enough discussion, that’s up to you. I think there was.”
The MC endorsed the resolution in a sector-weighted vote of 3.83 to 1.17. Segner said LS Power intends to submit the resolution as part of its protest against the TO proposal. Comments on the filing are due within 21 days, Segner said, hence the timing of the vote.
FERC said Thursday it will hold PJM’s fast-start pricing compliance filing in abeyance until July 31 in order to give the RTO enough time to resolve pricing and dispatch misalignment issues currently under review by stakeholders (ER19-2722).
In April, the commission ordered PJM and NYISO to revise their tariffs to allow fast-start resources to set clearing prices, saying their current rules are not just and reasonable. (See FERC Orders Fast-start Rules for NYISO, PJM.) PJM submitted a compliance filing in July that the Independent Market Monitor, state commissions and consumer advocates argued didn’t provide clear evidence that it would implement fast-start pricing correctly.
Specifically, the groups said that PJM uses different market intervals to calculate prices and dispatch instructions, suggesting that resources’ compensation doesn’t correspond to their dispatch instructions.
PJM control room | PJM
As part of its April order, FERC directed PJM to alter its real-time energy market clearing process to consider fast-start resources “in a way that is consistent with minimizing production costs.” The process requires PJM to first execute a cost-minimizing dispatch run, followed “by a pricing run where integer relaxation for fast-start resources allows them to set price.” The use of integer relaxation is intended to pinpoint a unit’s commitment costs in the pricing run and allow for their recovery through a market process rather than administrative methods.
“However, PJM may not be able to implement these separate dispatch and pricing runs in a way that is just and reasonable without first resolving the pricing and dispatch misalignment problem,” FERC said Thursday. “If fast-start resources dispatched in a given market interval could be compensated with a price from a different market interval, prices may not accurately reflect the marginal cost of serving load.
“Moreover, implementing fast-start pricing as directed … could exacerbate the pricing and dispatch misalignment issue because the lost opportunity cost payments … may be calculated based on inaccurate prices and, therefore, may not correctly compensate opportunity costs.”
FERC said implementing fast-start pricing now could also render lost opportunity cost payments ineffective “because they may not provide correct incentives to follow dispatch.”
PJM’s stakeholder process to fix the issue remains ongoing, with plans to conclude the effort by May.
FERC on Thursday granted Helix Ravenswood a limited waiver of the three-year limit under NYISO’s Tariff to retain its capacity resource interconnection service (CRIS) rights for deactivated generation facilities in New York City (ER20-323).
The commission’s order gives the company until Dec. 31, 2022, to transfer 129 MW of its existing CRIS rights from its deactivated gas turbine facilities to its proposed energy storage resources on the same site.
The state’s Public Service Commission in October approved construction of what will be New York’s largest battery storage facility, the 316-MW Ravenswood facility to be built on the Ravenswood Generating Station property in Long Island City, Queens (19-E-0122). (See “Largest Storage Project in New York,” NYPSC Projects Lower Winter Energy Prices.)
Ravenswood Generating Station
The storage facility will displace some out-of-service peaker units on the property and will provide peak capacity, energy and ancillary services; offset more carbon-intensive peak generation with power stored during the off-peak period; and enhance grid reliability in New York City.
NYISO neither opposed nor supported the waiver request but did suggest alternate paths for Ravenswood to obtain CRIS status. For example, the ISO asserted that the company could request CRIS rights in the 2019 class year study, of which the storage project is already a member.
Ravenswood has already submitted a CRIS request for such an evaluation in the current class year study, according to the ISO.
In the order, the commission rebuffed Ravenswood’s request to extend the requested waiver beyond Dec. 21, 2022, should the replacement project not be completed by that date, ruling that the request was not limited enough in scope.
Bill Lawrence, who had served as director of the Electricity Information Sharing and Analysis Center (E-ISAC) since 2018, has returned to NERC in a new role after an unexplained three-month absence.
NERC CEO Jim Robb announced Tuesday that he had appointed Lawrence as vice president of the ERO Enterprise Security Initiative, with a mandate to develop and promote physical- and cybersecurity efforts, including sharing best practices and developing security training. He will provide support for the implementation of priorities recommended by the Reliability Issues Steering Committee (RISC) and report to Mark Lauby, NERC senior vice president and chief engineer.
“It is clear to me that cyber and physical demands on the electric sector continue to challenge the reliability of the North American grid,” Robb said in a press release. “Therefore, I am asking Vice President Bill Lawrence to take the lead in working with the regional entities to engage stakeholders in more meaningful education in this challenging arena.”
Lawrence was quoted as welcoming the new role. “I enjoyed the opportunity to direct the E-ISAC and am proud of the foundation the team has built there,” he said.
Lawrence, formerly chief security officer, was mysteriously absent in October at GridSecCon, E-ISAC’s annual conference. Robb said then that Lawrence was “taking some time off” but expected him to return. He had not returned to work as of early January.
His new post was announced two days before FERC on Thursday ordered NERC to develop performance metrics and improve oversight of the E-ISAC.
Earlier in January, NERC announced the appointment of Manny Cancel, former chief information officer for Consolidated Edison, as senior vice president and chief executive officer of the E-ISAC. (See Former Con Ed Exec to Lead E-ISAC.)
NERC said Friday “there is no relation” between FERC’s criticism and its personnel moves regarding the E-ISAC.
ATLANTA — The standards drafting team revising the requirements for determining and communicating system operating limits (SOLs) is making steady progress toward posting the standard for industry comment by March (Project 2015-09: FAC-010, FAC-011, FAC-014).
At the SDT’s meeting Tuesday, team members focused on the proposed logging and communication requirements that form the primary unresolved topic for developing the rule. Former SDT Chair Vic Howell told NERC’s Standards Committee in November that the team had “come up with something” that would balance the desire of NERC Standards Committee Briefs: Nov. 20, 2019.)
Still at issue are questions about how often utilities should be required to check for SOL exceedances. Several industry representatives at the meeting pointed out that utilities may see small exceedances during regular operations that pose no concern for safety as they can be easily absorbed by expected demand increases. Nevertheless, an overly aggressive monitoring requirement could force providers to devote resources to logging and reporting that could be better spent elsewhere.
Another topic of disagreement is the “connection between determination of SOL exceedances and communication that exists in the standards today.” Chair Dean LaForest, of ISO-NE, who was appointed to replace Howell in December, said the current wording had led to comments from “both within the group and from [industry] participants” that defining the reporting and determination process in the same section could cause unnecessary confusion.
The inclusion of reporting requirements in the SOL determination methodology was part of the proposed compromise in November, but in light of these objections, the team is now considering whether to separate the description of the reporting process into a separate section.
Despite these areas of continued debate, LaForest told ERO Insider he is confident that the momentum of the development process has picked up and the standard will be ready for comment by March, with a final ballot expected by May.
“My favorite two words in the world [are] ‘cognitive blindness,’ which means we don’t know what we don’t know,” says David Goulding, who retired from NERC’s Board of Trustees this month after serving for nearly a decade. (See Former Con Ed Exec to Lead E-ISAC.) “And that has come to hit us many times along the way as NERC has developed.”
Recalling his more than 35 years associated with NERC, Goulding frequently returns to this theme of making the best of limited knowledge. Many of his efforts with the organization have been focused on driving home to stakeholders the importance of understanding their own limitations and accepting advice from others, and he believes this will continue to be one of the industry’s biggest challenges going forward.
Goulding’s experience with the energy industry goes back to his native England. Although his family had no electricity for the first 10 years of his life, growing up next to a coal mine and near a generating station gave Goulding a keen understanding of the importance of energy to everyday life. After graduating from the University of Bradford, he joined the U.K.’s Central Electricity Generating Board, where he worked in transmission and generation construction, operations and maintenance for several years. This hands-on role gave him a unique perspective among many of his peers.
“Where I come from is a little different from most people you find in senior positions in this industry today,” Goulding says. “I come from the coalface, if you like — almost literally, since five generations in my family did work at the coalface.”
“At the coalface” is a British idiom, similar in meaning to “on the front line” or “in the trenches,” with the “coalface” being the part of the mine from which the coal is actually dug.
“So I look at everything from that perspective … and think to myself, ‘How does that work at the coalface? What do the people have to do in the generating stations … and the control rooms, in order to maintain reliability?’”
Continuing his climb in the industry, Goulding came to Canada in 1977 to take a role with Ontario Hydro. Through that position he first began attending meetings of NERC, which at the time was still struggling to define its role relative to federal authorities and industry operators. In those days, the board was entirely composed of industry stakeholders, and the organization was “an instrument of the regions,” as Goulding recalls, with little outside input into its standards and limited enforcement ability.
Stronger Role, Growing Threats
Expanding the authority of the board was a major interest of Goulding’s early involvement with NERC. Over the years, he and others pushed to revamp the regional coordinators’ delegation agreements with the national body to give NERC a greater role in information sharing and the ability to penalize noncompliance. A panel on which Goulding served in the 1990s led to key changes, including a requirement for nine independent board members to balance the 37 industry stakeholders and provide a much needed outside perspective.
“We really didn’t see some of the challenges that were coming down the line. We didn’t see that [the] industry itself was going to get fragmented, with some companies going bankrupt [and] some companies taking over others,” he says. “Our big challenge back then was to recognize that things … were going to change.”
Change continues to be a major theme for the industry. Since joining the NERC board in 2009, Goulding’s biggest concern has been the growing threat from cyberwarfare, which in recent years has seen sophisticated attacks emerge from state actors including Russia and Iran. (See Report: Oil, Gas Hackers Expanding to Grid.) He believes the threat will only grow as malicious actors find new ways around utilities’ defenses.
“It’s almost impossible to stay ahead of the threats. You’re almost chasing these people, because they come up with something different every day,” Goulding says. “Just at one station, they [may] get thousands of attacks in a month. Not in a year — a month. Trying to stay ahead of that in this business is a real challenge.”
Open Minds Essential
The cyber threat will remain a primary focus for NERC’s new Canadian trustee, but new challenges are bound to emerge that may be difficult to imagine today. No matter the background of his eventual replacement, Goulding says an ability to absorb the advice of others will be essential in responding to a changing landscape.
“[One] thing I’d say is very important … is: listen. Listen to the stakeholders; listen to the other board members,” Goulding says. “This is the most collegiate board I’ve ever worked on. … Everybody’s dedicated, [and] every new member coming along would be foolish if they didn’t take the opportunity to learn from those other board members.”
