The team working on NERC’s proposed standard for cold-weather preparedness is revising the draft standard authorization request (SAR) and expects to post the updated document for another round of comments by the middle of February (Project 2019-06).
Debate at this week’s standard drafting team meeting primarily revolved around the cool reception the proposal received last year, with Sam Dwyer of Ameren noting that about 60% of respondents felt a new standard was unnecessary. Even many of the commenters who supported requirements around cold-weather preparedness urged the team to re-evaluate its scope. (See Gen Operators Cool to Winter Preparedness Standard.)
Geographic Splits
The strongest opposition to the proposal came from operators in northern areas, who argued that they already prepare for extreme cold as a matter of course, and that only operators in areas where winters are typically mild need guidance on how to handle extreme events. This argument made little headway with the drafting team, although it acknowledged that regional variations would likely need to be written into the standard.
“My take on that would be that standards should always be stuff you’re already doing. So, to the extent that you’re already doing it, great — it shouldn’t be hard for you to meet the standard,” Kenneth Luebbert of Evergy said. “[On the other hand], I think it’s going to be key [to] allow a lot of variations. … The approach that different plants take will be quite a bit different, whatever requirement we put into place.”
Some members suggested that the team address the geography-based objections by expanding its focus beyond low temperatures to cover any kind of extreme weather such as droughts or hurricanes, with Don Urban of ReliabilityFirst calling the new standard a “golden opportunity” to consider the impact of extreme weather in general.
This idea had little support from the majority of the team, however. Chair Matthew Harward of SPP reminded members that the impetus for the project was a joint FERC-NERC report on the Jan. 17, 2018, cold-weather event in the South Central U.S. Harward warned that trying to tackle too wide a remit could bog down the team and prevent it from reaching a meaningful result.
At the same time, members backed off from attempts to narrow the scope too much, as with Luebbert’s suggestion to focus on coal- and natural gas-fired generators, which accounted for 97% of performance issues cited in the joint report. Michael Brytowski of Great River Energy pointed out that when temperatures in the Upper Midwest dropped to -30 degrees Fahrenheit in early 2019, MISO lost almost 10 GW of wind generating capacity for 36 hours because of cold hydraulics, indicating that any form of generator can suffer from extreme temperatures.
NERC Guidelines Debated
Another topic of disagreement was what role the existing NERC cold-weather guidelines should play in the SDT’s work. Several industry respondents had said that the guidelines were sufficient and that no further requirements were needed; several team members favored simply adopting the guidelines as the new standard in whole or in part.
However, others felt more work was needed. For example, NERC Senior Standards Developer Jordan Mallory observed that “out of the past 12 years, there have been six blackouts [from extreme cold] — that is a problem. … Obviously, the NERC guidelines may not be enough.”
Responding to Mallory, Venona Greaff of Occidental Chemical cautioned that extreme weather events, by definition, are hard to predict and that it is impossible for even the best standard to cover all conceivable scenarios.
“You can do everything right all the time … you [can] look at where the wind blows from [historically] and how low the temperature gets, [but] you can have a one-off [where] the wind blows from a different direction and your wind blocks aren’t there,” she said. Greaff added that issues are more likely to arise at backup facilities, which aren’t used often, than at baseload generators.
“It’s like if you have a car that sits for a month and doesn’t drive — there’s no guarantee it’s going to start when you need it to.”
Observers from FERC urged the team to making their recommendations with the actual working conditions that utilities deal with in mind. Even when generator owners can point to their own cold-weather preparedness plans, they must be prepared to follow through and execute on them, they said.
“They’ve all got plans, and they’re good. … The generator operators [and] owners are very professional about getting plans out,” said Nick Henry of FERC. “The issue would be, after a period of time with moderate winters, and then another one hits you about five or six years later — now your pants are back down around your ankles because you just quit executing.”
U.S. renewable investments jumped 28% to a record $55.5 billion in 2019, showing the clean energy revolution is thriving despite the federal government’s failure to enact climate policies.
“We’ve seen renewable energy capacity double [in the U.S.] since the beginning of the decade,” said Ethan Zindler, Americas chief for BloombergNEF (formerly Bloomberg New Energy Finance), who released the data during a webinar by the American Council on Renewable Energy (ACORE) on Wednesday. “Solar capacity is probably 40 times what it was a decade ago.”
Renewable generation has increased about 75% to 761 TWh in 2019. Renewables now represent 18% of U.S. generation nameplate capacity. Including nuclear power, 38% of the country’s generating capacity is carbon-free.
U.S. renewable investments 2004-19 | BloombergNEF
Zindler said the biggest reason for the results in the U.S. was “a bit of a frenzy ahead of [the] anticipated step downs in tax credits.”
Globally, investment grew to $282 billion, a $1 billion increase from 2018, as the U.S.’ strong performance overcame a slowdown in China. The peak was $315 billion spent in 2017.
Although global spending was virtually flat in 2019 from 2018, Zindler said, declining costs meant developers were able to add 180 GW of generating capacity, up about 20 GW from the prior year. Wind edged out solar slightly in total investment worldwide, rising 6% to $138 billon while solar dipped slightly to $131 billion.
Growth was fueled in part by corporate power purchases, which totaled 50 GW, most of them in the Americas. The RE100 — 221 companies that have committed to 100% renewable electricity — have total electric demand about equal to that of South Africa, Zindler said.
Zindler said Congress’ one-year extension of the production tax credit is likely to result in a 1.5- to 2-GW increase in wind growth through 2025. Bloomberg projects 28.5 GW of new renewables in 2020, which would be the largest ever “by a pretty decent amount,” Zindler said.
Separately Wednesday, the American Wind Energy Association reported that 2019 was the U.S. wind industry’s third strongest year, with developers adding 9,143 MW of capacity. An additional 44 GW of wind projects, totaling more than $62 billion, are under construction or in advanced development, AWEA said.
Global corporate purchase power agreements (2009-19) | BloombergNEF
Challenges
Other panelists on ACORE’s “Outlook for Growth & Investment in 2020” webinar discussed industry trends and challenges.
“The conversations taking place today are slightly different than they were a couple years ago,” said Craig Gordon, vice president of government and regulatory affairs for Invenergy. “Companies like Invenergy aren’t just doing wind. They’re doing wind, solar and storage in the renewables space.”
Gordon cited the challenges of developing new generation at a time of record low power prices and flat demand. “We’re pushing new megawatts onto a grid that’s already oversupplied. That’s very apparent in places like PJM,” he said.
New production tax credit (PTC) schedule for onshore wind projects | BloombergNEF
Gordon also complained of “regulatory uncertainty” in New York, citing Gov. Andrew Cuomo’s Jan. 24 budget address.
“He said he would like the state government to begin doing the siting and transmission and development and then bring in developers after the fact to build the projects that they’ve cleared the way for,” Gordon said. “That’s really not helpful in a state where we’ve already seen significant regulatory burdens in getting projects done.”
He also slammed FERC’s Dec. 19 order directing PJM to expand its minimum offer price rule.
“If FERC was really hoping to just allow coal, I think they miscalculated … big time,” he said. “I think they may have taken a sledgehammer when a scalpel would have been more appropriate to deal with the issues around the capacity market.”
On the one-year anniversary of its bankruptcy filing, Pacific Gas and Electric appeared to be closing in on its goal of exiting Chapter 11 reorganization, while lawyers representing shareholders, fire victims and the government wrangled in court to secure a share of the multibillion-dollar pot the utility will have to pay out.
At the same time, California Gov. Gavin Newsom persisted in his threats to take over PG&E if it doesn’t leave bankruptcy “transformed.”
“If PG&E can’t do it, we’ll do it for them,” Newsom told an audience at the Public Policy Institute of California in Sacramento on Wednesday.
In San Francisco, lawyers argued in U.S. Bankruptcy Court over the division of a $13.5 billion trust that PG&E has promised fire victims. Because the details of the trust have yet to be made public, some potential beneficiaries were concerned they might not get their share.
Santa Rosa’s Coffey Park neighborhood was leveled in the Tubbs Fire in October 2017.
Attorneys representing more than 1,000 victims of the Camp Fire — which killed 86 people and destroyed 18,800 structures in the town of Paradise in November 2018 — tried unsuccessfully to convince bankruptcy Judge Dennis Montali to unseal terms of PG&E’s settlement with some victims of the Tubbs Fire, which killed 22 people and leveled a large part of the city of Santa Rosa in October 2017.
The lawyers argued that the confidential settlement with 19 elderly and infirm victims of the Tubbs Fire could jeopardize payments to Camp Fire victims because all must draw on the same fixed amount that PG&E has promised to put in the trust account.
Camp Fire victims “will soon be asked to vote on a restructuring plan that purports to provide $13.5 billion in funds for wildfire victims, including themselves. But that $13.5 billion figure is literally meaningless if an outsized portion has already been set aside for a select few claimants, the lawyers argued in a court filing.
Montali overruled their objection Wednesday, saying it was outweighed by PG&E’s agreement to settle the entire Tubbs case, which otherwise had been set to go to trial this month with an uncertain outcome. State investigators found a private landowner’s faulty wiring, not PG&E equipment, had started the fire.
A group of PG&E shareholders who had filed a securities fraud class-action lawsuit against PG&E argued they had been denied sufficient notice of the claims procedure in the bankruptcy case. Montali seemed skeptical of the argument, while agreeing with PG&E attorney Stephen Karotkin that a decision in the shareholders’ favor could “gum up” the case.
Montali heard briefly from lawyers representing federal and state agencies that are trying to recoup nearly $4 billion in funds dispersed to deal with catastrophic fires ignited by PG&E equipment in recent years. The agencies, primarily the Federal Emergency Management Agency, are concerned that their payment may come from the $13.5 billion to be set aside for fire victims and are asking the judge to help sort out the situation. (See FEMA Wants $4 Billion from PG&E in Bankruptcy.)
Montali said he would hear more from the government lawyers at the next bankruptcy hearing Feb. 4.
Newsom Repeats Takeover Threat
As the bankruptcy hearing played out in San Francisco, Newsom repeated his threat of a state takeover and said he had been talking with legislative leaders, readying a plan, several news outlets reported.
“It has to be a completely reimagined, transformed company,” Newsom said, according to the Associated Press. “Its culture has to change; its mindset has to change; its framework away from short-termism and situational thinking has to be replaced with a culture that focuses on you and me, not just shareholders.”
The governor said his staff had been in talks with PG&E to work out a solution, Bloomberg reported. He has called for PG&E to replace its entire board, adding more Californians, and to provide the state a mechanism for a quick takeover, should it be needed.
If a deal can’t be reached within the next few weeks, Newsom said he will lay out a detailed plan for a takeover.
PG&E filed for bankruptcy on Jan. 29, 2019, following two years of devastating blazes caused by its equipment. In recent months, the company has reached settlement agreements with most fire victims, insurance companies and local governments.
The utility most recently settled with bondholders that had offered their own reorganization plan for PG&E, amounting to a hostile takeover bid. The bondholders, led by several hedge funds, agreed to drop their plan in exchange for PG&E agreeing to pay or refinance its long- and short-term debts. (See PG&E Settles with Bondholders; Governor Objects.)
SANTA FE, N.M. — The SPP Cost Allocation Working Group (CAWG), composed of regulatory staff from across the RTO’s footprint, told their state regulators Monday that they plan to establish a narrow byway facility cost allocation review process, rather than just evaluate the process as first directed.
CAWG Chair John Krajewski, a consultant with the Nebraska Power Review Board, explained to the Regional State Committee that the group determined the Holistic Integrated Tariff Team’s recommendation that it evaluate a process through which costs for specific 100- to 300-kV projects can be fully allocated on a regionwide basis was not sufficient.
“‘Evaluate’ really means ‘go out and do it,’” Krajewski said. “The consensus of the group was that HITT’s intention was for us to put together a process for how this will look.”
Krajewski said the CAWG is “working towards having language” the RSC can adopt in the form of a white paper. The HITT’s timeline has the group completing its work in July, a schedule he called “aggressive.”
The CAWG is also recommending that projects eligible for the byway cost-allocation review process should include both new and existing Schedule 11 facilities. The recommendation excludes directly assigned upgrades.
RSC Approves Renewables’ Capacity White Paper
The RSC unanimously approved a staff white paper proposing a methodology for prioritizing and allocating the available effective load-carrying capability (ELCC) from wind and solar generating facilities that qualify as capacity in SPP’s balancing authority area.
Staff last year completed the study, which revealed that while wind resources’ total capacity increased with penetration, the accredited percentage of capacity related to the nameplate of each individual resource decreased.
The committee also approved Landmark Certified Public Accountants’ selection to audit its 2019 financial statement and the Business Practices Working Group’s revisions (BPWG RR369) to a business practice (BP 7060) that establishes cost-estimating processes and reporting requirements if project costs are projected to go outside an established bandwidth.
The changes close oversight gaps for projects that receive base plan funding but are not issued a notification-to-construct; clarify when oversight begins; and provides that the project owner is required to submit certain information as part of closeout processes.
Louisiana PSC’s Francis Joins Committee
The meeting marked NPRB Member Dennis Grennan’s first as RSC president and Louisiana Public Service Commissioner Mike Francis’ first as a member. Francis replaces Foster Campbell, who made a memorable appearance during October’s RSC meeting in Little Rock, Ark. (See “Louisiana’s Campbell: SPP Spending ‘Extravagant’,” SPP Regional State Committee Briefs: Oct. 28, 2019.)
By Michael Kuser, Christen Smith and Rich Heidorn Jr.
Transmission owners this week defended PJM’s, ISO-NE’s and SPP’s designations of “immediate-need” reliability projects while state officials complained the grid operators are frustrating FERC Order 1000’s intent to open transmission construction to competition.
More than a dozen stakeholders and groups filed comments on the RTOs’ responses to FERC’s Oct. 17 orders opening investigations under Federal Power Act Section 206 into their use of Order 1000’s immediate-need exemption. The exemption allows the RTOs to assign projects to incumbent TOs. FERC said it was “concerned that the responding RTOs may be implementing the exemption in a manner that is inconsistent with or more expansive than what the commission directed, and therefore may be unjust and unreasonable.” (See FERC to Probe Order 1000 Competition Exemptions.)
The TOs agreed with ISO-NE (EL19-90), PJM (EL19-91) and SPP (EL19-92), which insisted in their Dec. 27 filings that they were following Order 1000 and that no changes to their transmission planning practices were warranted.
Exception ‘Swallowed’ the Rule
But state officials disagreed, with several New England state agencies saying, “the exception has swallowed the rule.”
“The three-year, immediate-need deadline is a fiction that has not been respected in theory or in practice in New England,” the Connecticut and Massachusetts attorneys general, Connecticut’s Department of Energy and Environmental Protection and Office of Consumer Counsel, and the Maine Office of Public Advocate said in a joint comment.
FERC should order ISO-NE to amend its Tariff and revise or eliminate the time-sensitive-needs exemption to encourage competition, they said.
The New Jersey Board of Public Utilities argued that PJM applies the exemptions too broadly, resulting in “increased transmission rates from projects not subject to competitive pressures.”
Ending the Federal ROFR
Order 1000 required RTOs to eliminate from their tariffs a federal right of first refusal for incumbent transmission developers for facilities selected for cost allocation in a regional transmission plan.
In allowing PJM, ISO-NE and SPP to create the exemptions, FERC set out five criteria, including that a project is needed in three years or less to solve reliability criteria violations. It also required the RTOs to post information about the exemptions to ensure transparency. (CAISO, MISO and NYISO did not seek such exemptions.)
The commission said “it is unclear how each responding RTO determines whether an immediate-need reliability project is needed in three years or less,” noting that PJM designated 19 immediate-need reliability projects between 2017 and 2018 with need-by dates prior to or in the year they were designated. In other cases, FERC found, the projects were projected to be in service after the need-by date.
The commission also faulted the RTOs for a lack of transparency, saying it was difficult to locate where they identify and post explanations of reliability violations and system conditions with time-sensitive needs.
It suggested potential changes, such as shortening the three-year rule for projects deemed immediate-need, approving exemptions based on the in-service date versus the need-by date, increasing transparency into how the RTO determines a competitive process is unfeasible and requiring more frequent project re-evaluations.
SPP: Small Share of Projects Exempted
FERC noted that SPP designated an immediate-need reliability project in December 2018 that is needed by June 1, 2020 but has an expected in-service date of June 30, 2023.
SPP said the five projects it designated as short-term reliability projects (STRPs) represented only 3.5% of 144 total reliability upgrades between 2015 and 2018.
Of the five, one was canceled, and two others designated in July 2016 and December 2018 have not yet been energized. Two projects designated in June 2015 were completed in June and November 2018.
The RTO said the process for designating STRPs “is working as intended” and that changes contemplated by FERC “would have very little impact on increasing the number of projects subject to competition and could increase reliability risks incurred due to delays in construction caused by implementing the competitive bidding process.”
American Electric Power defended both SPP and PJM in its filings, saying immediate-need reliability projects “are a necessary component of reliability” that allow RTOs to adapt to “retirement of conventional generation, the rapid addition of variable resources and the addition of block load, such as data centers and shale gas facilities.”
PJM Late to ID Needs?
In its critique of PJM, FERC had questioned the RTO’s approval of the Flint Run 500/138-kV substation upgrade as an immediate need, saying the size of the project — intended to serve load growth in the Marcellus Shale region in West Virginia — “raises questions about why PJM did not identify this need earlier.”
PJM’s 137-page response clarified that the number of immediate-need projects approved between 2015 and 2018 totaled 63, slightly more than a quarter of the 241 transmission proposals exempted from competition in that time frame.
The RTO said it arrived at the smaller number after sorting out projects that claimed other competitive exemptions, including the lower voltage threshold, thermal reliability violations solved with substation upgrades and Form 715 projects. It also argued that the relative size of the population it serves contributes to the number of immediate-need projects in its Regional Transmission Expansion Plan (RTEP) as compared to SPP and ISO-NE.
FERC questioned PJM’s approval of the Flint Run 500/138-kV substation project as an “immediate need” reliability project, saying the size of the project, to serve load growth in the Marcellus Shale region, “raises questions about why PJM did not identify this need earlier.” | PJM
FERC’s proposed changes, PJM said, ignore the unpredictable nature of the siting and eminent domain processes and would require RTO staff to “prognosticate” about complex government processes for which they lack expertise. Its existing practice of posting information about immediate-need projects online three days before the monthly Transmission Expansion Advisory Committee meeting gives stakeholders a chance to review and ask questions about the proposals, eliminating the need for greater transparency, PJM said. Further, mandated re-evaluations for projects that fail to meet a projected in-service date “would be highly disruptive and lead to further delays.”
“Thus, it is necessary that PJM continue to have the authority given the relevant facts and circumstances to direct transmission owners to resolve an immediate-need reliability issue when identified and that those entities designated responsibility to construct the project will have reasonable assurance of recovery if they proceed with the project as approved,” the RTO said.
TOs: No Changes Needed
In separate filings, Exelon, Old Dominion Electric Cooperative and AEP said that PJM’s response demonstrates effective implementation of the immediate-need exemption and supported no further policy changes.
“Exelon agrees with PJM that the additional conditions and restrictions on the use of the immediate-need reliability project exemption that the commission introduced in the show-cause order would either undermine the effectiveness of the immediate-need reliability project exemption or fail to meaningfully increase opportunities for nonincumbent transmission development,” Exelon wrote.
The New Jersey BPU took aim at PJM’s argument that its immediate-need projects were “artificially inflated,” noting that the subset still accounts for 13% of all baseline upgrades in the RTEP.
After the last of PJM’s competitive exemptions went into effect in 2017, more than $3 billion in transmission projects were planned “without the benefit of competition,” the BPU said. The issue hits close to home for New Jersey regulators, who have charged that more than a third of PJM’s transmission expansion has occurred within their state, increasing transmission rates 124% since 2013 for “certain customers.”
“Taken together, these facts undercut PJM’s use of other exemptions as support for the justness and reasonableness of its existing rules,” the BPU said. “To the contrary, the substantial portion of noncompetitive PJM transmission investment, particularly in New Jersey, confirms the commission’s concerns about the expanding scope of transmission exemptions.”
Because PJM has demonstrated the operational capability to maintain a reliable transmission system when construction on such projects extends beyond three years, competitive transmission developer LS Power said, the commission should eliminate the blanket immediate-need exemption and require the RTO to seek FERC approval of exemptions on a case-by-case.
LS Power said the total value of transmission additions classified as immediate-need exceeds $4.5 billion over the last six years — far beyond what the commission envisioned when it approved the “limited” exemption.
“The commission must require PJM to fully explain why this staggering amount of transmission spending in PJM is in immediate-need reliability exemption projects and why PJM’s planning process is insufficient to prevent this level of immediate-need reliability projects,” LS Power said. “Significant reform is warranted.”
American Municipal Power said PJM’s process for approving RTEP projects is flawed because incumbent TOs hold all the relevant information and don’t provide it to the RTO on a “timely basis.”
“The commission should direct PJM to improve the RTEP process to ensure that it has timely information from processes that feed into the PJM planning process to avoid immediate-need reliability projects resulting from changes in topology, facility rating methodologies or other modifications controlled by the PJM transmission owners,” AMP said.
ISO-NE’s Lack of Annual Tx Planning
FERC also was critical of ISO-NE, saying that because the RTO does not conduct an annual transmission planning process, and instead relies upon needs assessment studies, “it appears that all reliability needs in ISO-NE may be classified as immediate-need reliability projects.”
ISO-NE and New England TOs Avangrid, Eversource and National Grid stood alone in defending the RTO’s use of immediate-need exemptions, with most stakeholders urging FERC to curtail or abolish the exemption.
The RTO said it has 31 reliability projects for which the need-by date is earlier than the projected in-service date, all resulting from either its Boston 2028 or its Southeast Massachusetts/Rhode Island 2026 needs assessments.
“The solutions are addressing the time-sensitive needs described in the two assessments,” the RTO said. “ISO-NE believes that the exception is working as intended in the New England area and that no changes are necessary at this time.”
After the RTO in December issued its first competitive transmission solicitation — to address reliability concerns over the planned retirement of the Mystic Generating Station near Boston — it told the commission it “intends to conduct a ‘lessons learned’ process, during which time ISO-NE will revisit its processes to determine if overall improvements can be made.” (See ISO-NE Issues First Competitive Tx RFP.)
The New England Power Pool urged the commission to restrict the use of such exemptions “as much as possible, consistent with ensuring that reliability needs are met in a timely way.”
NEPOOL said it continues to support the immediate-need exemption for transmission facilities that are needed within three years of the identification of a reliability need. However, it “should be the exception and not the rule,” the organization said.
The New England state agencies said the “fiction” of the three-year immediate-need deadline is demonstrated by the data. Of 30 completed and ongoing immediate-need projects, they said, 24 (80%) were not completed within three years; 15 (50%) are expected to take at least five years; and 20 (67%) had need-by-dates predating the assessment study that identified the need. Another four had need-by-dates in the same year as the need was identified.
The New England States Committee on Electricity (NESCOE) said it is concerned that ISO-NE’s practices could cause all reliability needs to be met outside of the competitive process.
“Given the unique circumstances and system conditions giving rise to the identified need, the Boston [request for proposals] does not appear to signal a fundamental shift away from ISO-NE’s use of the exemption,” NESCOE said.
The limited competition in New England raises obvious questions about whether consumers are paying more than necessary for transmission, it said, noting that revenue requirements are forecast to increase from $2.1 billion in 2018 to $2.7 billion in 2023, a jump of more than 25%.
“Even before these increases take effect, an ISO-NE analysis shows that most residential retail electric customers in New England paid transmission costs representing 11 to 18% of their total retail rates,” NESCOE said. “If needs were classified as time-sensitive years ago but ISO-NE has not yet selected projects to meet those needs, it raises questions regarding whether the appropriate criteria is being used to assess the time-sensitivity of those needs.”
The Connecticut Public Utilities Regulatory Authority said, “Any competition is superior to no competition,” and that the RTO “appears to prefer not using the competitive process to address transmission needs and to being unable to identify any transmission need that is more than three years away.”
The PURA suggested limiting the percentage of transmission need projects that can have a noncompetitive solution, based on either the number of projects or on the dollar expense.
The agency “believes that 25% is the appropriate limit to place on the amount of dollars that can be spent on noncompetitive solutions. This percentage level ensures that the majority of dollars spent on transmission need solutions benefit from competitive forces, yet should be amply sufficient to handle those few occasions when reliability concerns arise and cannot be mitigated.”
To Proceed or not to Proceed
The immediate-need exemption has given incumbent TOs in New England exclusive rights to construct nearly all new transmission in the region, and they are at the same time “failing almost universally to complete or, in some cases, even commence projects on or before the need-by date,” Massachusetts Municipal Wholesale Electric Co. and New Hampshire Electric Cooperative said.
The immediate-need exemption is “out of step with its intended purpose and should be eliminated,” they said, suggesting a more streamlined competitive solicitation process.
ISO-NE asserts that in-service dates are based on realistic appraisals by the affected TOs of how long it is likely to take for the preferred solution. “But that does not advance the ball; it merely describes the problem,” the public systems said. “If the TO cannot build the project within the [RTO’s] need-by timeframe, then the project should be put out for bid.”
The public systems proposed a competitive solicitation process they said could be completed in less than half the time of the RTO’s method, “or just 279 days, compared to the 630-day time frame ISO-NE has established for the Boston 2028 RFP.”
Avangrid tried to parry the thrust of the commission, asserting that “a litigated proceeding based on a misunderstanding of need-by dates versus in-service dates does not signal to the industry that the commission intends on maintaining the reasonable balance struck between eliminating barriers to new entry and ensuring participating transmission owners are able to address immediate reliability needs on the New England transmission system without unnecessary delay.”
The company suggested giving up “a one-sided view of post-Order No. 1000 transmission planning measures” in favor of a technical conference as “the most transparent and balanced manner to manage this discussion.”
Eversource Energy said, “The benefits of adjusting the three-year exemption … to increase competition are minimal.”
ISO-NE independently determines what reliability needs to put out for competitive solicitation, and stakeholders can challenge its use of the three-year exemption, the company said.
There would be “little benefit to creating more process” for the kinds of projects that are needed within three years, which typically involve upgrades to TOs’ existing assets or on their rights of way, which FERC explicitly reserved for the public utility transmission provider, Eversource said.
“Near-term reliability should not be compromised for such little, if any, benefit. There is ample evidence for the record of the significant time needed to conduct competitive solicitations,” Eversource said.
National Grid reported nine of 13 immediate-need projects identified through the SEMA-RI report as “progressing satisfactorily against their key milestones,” with the remaining four “less advanced due to factors outside of National Grid’s control.”
Stakeholders disputed some of the analysis that PJM used to set soak time operating reserve credit rules and also raised concerns with the way the concept was being woven into energy offers.
The PJM Markets and Reliability Committee convened Jan. 23 at the Conference and Training Center in Valley Forge, Pa.
It’s the second time the MRC has deferred voting on the issue, after requesting a one-month delay in December. The committee instead endorsed two other recommendations from the Modeling Generation Senior Task Force that can be implemented in the near term while PJM focuses on completion of its next generation energy market (nGEM).
The Tariff and Operating Agreement revisions, which were also approved by the Members Committee, will increase the number of segments on the energy offer curve (effective in 2020) and introduce hourly differentiated segmented ramp rates (late 2020).
The task force, assembled in 2017, developed the solutions to improve resource modeling for “complex resources” in PJM’s market clearing engines, including combined cycle units, coal units with multiple mills and pumped hydro.
Primary Frequency Response Task Force Hiatus Extended
The committee agreed to keep the Primary Frequency Response Task Force on hiatus through the first half of 2020.
Primary frequency response (PFR) is the ability of generators to automatically change their output in five to 15 seconds when the grid’s frequency strays above or below 60 Hz. As more renewables enter the resource mix and coal plants retire, the grid can become more susceptible to these frequency swings, threatening system reliability.
The task force wrapped up its action last year and promised to update the Operating Committee on a quarterly basis of PJM’s performance. During the most recent update in October, PJM said 583 units with capacities of 50 MW or greater were evaluated for PFR across 10 events between March and September. The selected events for analysis met one of three qualifications: frequency goes outside the +/- 40-MHz deadband, frequency stays outside the +/- 40-MHz deadband for 60 continuous seconds or minimum/maximum frequency reaches +/- 53 MHz.
No more than 28 units provided PFR during any of the selected events. In some cases, no units responded. PJM said most critical load and black start units evaluated did not provide PFR because many were offline, operating at maximum capacity or had inconclusive results.
The task force will continue to update the OC on a quarterly basis of PFR results across the RTO.
Credit Risk Tariff Revisions on Hold
PJM Chief Risk Officer Nigeria Poole Bloczynski told the MRC that Tariff revisions that would update the RTO’s market participant risk profiles and expand updated credit rules to apply to all markets — not just the financial transmission rights market that was the subject of GreenHat Energy’s massive default — are on hold temporarily as stakeholders continuing reviewing the proposed language.
PJM CRO Nigeria Poole Bloczynski
“We’ve made significant progress, but we also acknowledge that we are moving a little fast,” she said. “Feedback internally has suggested we take our time to get this right.”
PJM hired Bloczynski in July after an independent probe of the GreenHat default found the RTO’s executive team lacked credit expertise. She said last month she’s hiring four additional staff in her department, including a manager of credit risk and trading risk, and challenging current employees to automate as many processes as possible.
In the meantime, Bloczynski encouraged leaders of PJM member companies to attend meetings of the Financial Risk Mitigation Senior Task Force, from which many of the Tariff changes originate.
On Friday, the ISO/RTO Council asked FERC to reject financial traders’ request for a rulemaking to update and standardize RTO credit policies nationwide, saying it would upset stakeholder proceedings on the issue. (See related story, RTO Council Balks at Credit Rulemaking.)
Later, the Members Committee approved revisions to the OA endorsed by the task force and MRC to hold five long-term FTR auctions a year, instead of three, to increase visibility into portfolio conditions so that more collateral can be collected if necessary. The revisions also would alter the structure of Balancing of Planning Period auctions so that participants can buy and sell in any month of the year, rather than being limited to a specific quarter. (See “FTR Credit Rules Endorsed,” PJM MRC Briefs: Dec. 19, 2019.) There were three objections to the vote, including from the Consumer Advocates of the PJM States and the PJM Industrial Customer Coalition.
Members Committee
PJM Annual Meeting Scheduled in Chicago
PJM will host its annual meeting at the Drake Hotel in Chicago on May 4-6. Registration for the event opens on Feb. 5 and will close April 29.
Member companies, voting proxies, state and federal employees, and event sponsors can attend free of charge. Otherwise, attendees must pay a $400 guest fee for media, spouses, children and others that covers all meals and one leisure activity.
Manual Revisions, Tariff Changes Endorsed
The MRC endorsed revisions to Manual 38: Operations Planning that included updates from the periodic cover-to-cover review and updated procedures.
The Members Committee endorsed:
revisions to the OA to changing the competitive transmission proposal fee structure. PJM will charge a $5,000 nonrefundable fee to all developers who submit competitive proposals. Itemized study costs will be added as necessary. RTO officials said the current tiered approach doesn’t account for the increased cost of the new comparison framework that involves an independent consultant’s review and legal and financial analyses. (See “Competitive Transmission Proposal Fee,” PJM MRC Briefs: Dec. 19, 2019.)
revisions to the Tariff and OA to align them with PJM’s actual implementation of market-based parameter-limited schedules. (See “Parameter-limited Scheduling Fix,” PJM MRC Briefs: Dec. 19, 2019.)
revisions to the OA clarifying the requirements for sharing forecasted unit commitment data to transmission owners for reliability studies, to ensure consistency with NERC standards and PJM manuals.
revisions that clarify that market sellers can only change the format of maintenance adders ($/MMBtu, $/MWh or $/start) during the annual review period for energy offer components. (See “Manual 15 Clarifications on VOM Costs,” PJM MRC/MC Briefs: Dec. 5, 2019.)
The ISO/RTO Council askedFERC on Friday to reject financial traders’ request for a rulemaking to update RTO credit policies, saying it would upset stakeholder proceedings on the issue.
The Energy Trading Institute asked the commission on Dec. 16 to schedule a technical conference by March 30 and convene a rulemaking to update FERC Order 741, its 2010 rulemaking on credit and risk management in the RTO/ISO markets (AD20-6).
Order 741 shortened settlement periods in the energy and ancillary services markets, reducing default exposure. ETI said the order— which also banned or limited unsecured credit and provided guidance on the use of netting and demanding additional collateral — was “appropriate at the time.”
GreenHat Concerns
“However, given the recent GreenHat default and the evolution of these markets over the last decade since the issuance of Order No. 741, ETI strongly believes that the commission and industry should engage in a dialogue to ensure that credit and risk management practices and procedures in the ISOs and RTOs are robust, do not create unnecessary barriers to entry or compliance burdens, and ensure that organized markets are secure in order to meet the commission’s goals of open access, competition and transparency.”
The group, whose members include Vitol, SESCO Enterprises and Appian Way Energy Partners, said FERC should insist that new policies are uniform across all markets. Allowing each grid operator to set its own minimum participation and risk policy requirements has created “a significant compliance burden” for market participants and resulted in a mix of policies that “are not effective in reducing exposure and detecting default risk,” ETI said.
“There should be one set of standards, one set of disclosures and one set of certificates for entities to comply with the commission’s rules,” ETI said.
IRC: Don’t Rush RTOs
The IRC, which includes the six FERC-jurisdictional RTOs/ISOs, did not challenge any of ETI’s criticisms in its filing Friday. Instead, it said FERC should allow the grid operators and their stakeholders to address their credit and risk management issues individually before considering a conference or rulemaking.
“At a minimum, these RTOs and ISOs should have time to gain experience with those rules before the commission facilitates a dialogue of best practices, schedules a technical conference and/or commences any rulemaking proceeding to examine further enhancements to credit policies and practices in organized electricity markets.”
IRC said a rulemaking would “upend those individual stakeholder processes and the timely submittal of reforms by individual RTOs and ISOs.” It proposed an alternative approach that it said acknowledges ETI’s concerns without becoming an impediment to stakeholder processes and filings before the commission.
“From a timing perspective, the IRC believes that the issues raised by ETI are best addressed once experience is gained with those individual RTO and ISO reforms. The IRC’s proposed approach is consistent with the commission’s prior determination that: ‘In matters of administrative regulation, a month of experience may be worth a year of hearings.’”
“MISO’s filings are intended to improve the baseline by implementing well-considered measures,” the RTO said in a statement Monday.
PJM has also been working for seven months and hopes to submit its proposed credit and risk management rule changes by the end of March. (See “Credit Risk Tariff Revisions on Hold,” PJM MRC/MC Briefs: Jan. 23, 2020.)
SPP’s Credit Practices Working Group, which has been working for nine months, is reviewing draft proposals on capitalization requirements and other matters and expects the group to vote on the proposed changes by the end of the first quarter.
“The commission should not schedule a nationwide technical conference at this time. Instead, it should proceed to address filings that are before it or that RTOs/ISOs plan to submit in the near future,” IRC said.
Improvements Needed
ETI said improvements are needed in credit risk management, counterparty risk management and ISO/RTO internal risk management infrastructure and expertise. It says each of the RTOs should hire a chief risk officer who reports to its board — as PJM did following the GreenHat debacle. (See PJM Names Chief Risk Officer.)
The group said MISO, SPP and ISO-NE “have inapposite submission credit requirements, on the one hand requiring submission credit as much as 10 times the anticipated exposure and, on the other, far lower hold credit requirements for cleared positions that under-collateralize the actual exposure of the position.”
Despite FERC regulations prohibiting unsecured credit in financial transmission rights markets, the group says, MISO allows market participants to hold positions for which they have not posted collateral.
MISO returns hold credit to counterflow FTR holders at the beginning of every month even though the market participant holds the counterflow position open for the entire month, the group said. “MISO’s assumption is that the counterflow FTR’s value will remain in-the-money. However, this is not always the case. Put simply, the market participant then gets to hold those positions for free.”
ETI also criticized SPP, saying it gives transmission congestion rights holders “a credit for historically strong performing paths. By not establishing a basic credit requirement for any position, SPP allows for large portfolios (i.e., exposure) that require no collateral.”
“SPP’s FERC-approved credit and risk management practices are fair, reasonable and configured according to the specific design of our market and market participants,” RTO spokesman Derek Wingfield said in response to ETI’s criticism. “Because our Integrated Marketplace operates differently than other ISO/RTOs’ markets — our region is vertically integrated and we lack a capacity market, for example — it would not make sense that we would have the same credit requirements as our peers operating in other parts of the country.”
ETI said the technical conference should include representatives from exchanges, futures commission merchants and commercial entities with experience managing commodity risk. It wants FERC to follow the conference with a Notice of Proposed Rulemaking that will lead to adoption of industry best practices such as mark-to-auction tools to track changes in exposure and requiring variation margin as the value of a position changes.
Only PJM has implemented mark-to-auction valuation, a standard practice in other commodity markets, including commission-jurisdictional bilateral markets, ETI said.
The group likened the need for uniformity in minimum credit requirements to NERC’s national reliability standards. “Some foundational rules spanning all ISOs and RTOs are inherently necessary for credit models to function well.”
ETI suggested the minimum net worth requirement should be $1 million, which it said is “high enough to signal the risk of participating in the markets but not so high as to unnecessarily discourage entry or negatively impact liquidity.”
It criticized SPP’s proposal to require a market participant to have $20 million in capitalization regardless of a market participant’s activity — meaning the money cannot be used in another ISO/RTO market — as arbitrary and an unnecessary barrier to entry.
Markets ‘not Standardized’
IRC challenged ETI’s premise that the rules should be standardized, saying “the underlying markets to which the credit policies apply are not standardized. While an evaluation of areas of credit policy that lend themselves to standardization is appropriate, assuming standardization at the outset is not appropriate.”
“If the commission is inclined to facilitate a dialogue to identify whether specific credit policies should be made applicable on a uniform basis, the IRC requests that the commission allow the individual RTOs and ISOs to finalize their stakeholder discussions, submit their proposed tariff revisions to the commission and implement these changes first. This would allow each region and stakeholders to gain experience with those rules and begin to examine best practices that might be applicable across RTO/ISO markets. At that point, the commission could facilitate a more informal dialogue as a potential next step without necessarily scheduling a formal technical conference or commencing any rulemaking proceedings.”
SACRAMENTO, Calif. — The California Energy Commission is funding pilot programs for energy storage systems that go well beyond lithium-ion batteries, the audience at the Community Choice Energy Summit heard Friday.
The state accounts for 77% of planned large-scale storage nationwide, David Erne, a supervisor with the commission, told the audience.
He described the effort to develop utility-scale storage systems that don’t rely on lithium-ion batteries. Among the most sought-after systems are those with a minimum rating of 400 kW that could provide electricity for more than 10 hours at a time.
“We struggle with having a diversity of technology available,” Erne said.
Driven partly by the multiday outages caused by wildfires and public safety power shutoffs, the commission is seeking longer-duration storage that overcomes the run-time limits of lithium-ion batteries.
The commission is looking at technology that includes flywheel energy storage systems, flow batteries and non-lithium-ion Znyth batteries developed by Eos Energy Storage.
Proposals for some types of storage, primarily to deal with grid outages, are due at the end of February. The same solicitation includes smaller-scale storage systems to support Native American and low-income communities as well as lithium-ion batteries for residential construction.
A solicitation for projects to study the most useful locations and run times for longer-duration storage systems will be coming out soon, Erne said.
“We’re grappling with where [it will] provide the most value and what duration will provide the most value,” he said. “That one is not currently on the street, but it will be released imminently.”
Much of the research is funded by the commission’s Electric Program Investment Charge (EPIC) program, which provides approximately $130 million per year for research in science and technology to meet the state’s renewable energy and greenhouse gas reduction goals. (See EPIC Interest Growing Rapidly in California.)
The program is funded by a charge on ratepayer bills and administered by the commission and the state’s three big investor-owned utilities, Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric.
Erne said a related effort by the commission is resolving problems and costly delays connecting storage to the grid. It is working with the California Public Utilities Commission on rulemaking to ease interconnection rules and speed the process, “which I know is a significant problem for everyone who wants to put new technologies on the grid,” he said.
“It has become very challenging both from a time perspective but also from a cost perspective,” because developers find it hard to anticipate what a metered interconnection might ultimately cost, Erne said.
Entergy must provide a clearer rationale before it will be allowed to include a line item for pension costs in its rate base, FERC ruled Thursday.
Relying on a 10-year-old order involving Southern Co., the commission ruled that Entergy is allowed to include prepaid and accrued employee pension costs in its rate base but must still justify and more clearly account for those costs before doing so (ER15-1436).
In a filing updating its formula rate in 2015, Entergy proposed to include prepaid and accrued pension costs for pension plans at its Gulf States Louisiana, Arkansas, Louisiana, Mississippi, New Orleans and Texas operating companies. Prepaid pension costs represent company contributions that exceed pension expenses “to meet the requirements of pension funding laws and rules,” while accrued pension costs are payments collected from ratepayers “in excess of what the utility has contributed to its pension plans,” which must be credited back to customers.
FERC sent Entergy’s transmission rate to settlement procedures in 2016, and a partial settlement left unresolved whether the operating companies could include the pension line item in their base rates. An administrative law judge in 2018 decided that Entergy hadn’t properly justified prepaid costs in the rate base because it did not show a net benefit to ratepayers or a “correlation between its prepaid pension costs and a reduction in transmission rates.”
Entergy Tower in New Orleans
But FERC last week rejected the ALJ’s reasoning while still disallowing the pension line item, saying Entergy’s accounting wasn’t properly justified — but not because the pension costs didn’t show customer benefit.
The commission said prepaid pension costs in rate bases are reasonable when the “pension expense recovered from ratepayers is less than its contributions to fund pension costs.” Likewise, it said accrued pension costs are also permissible.
“Entergy is not required to provide a policy statement or other documents describing how it exercises its pension funding discretion,” the commission said.
However, FERC found that “Entergy’s proposed formula for its qualified pension plans includes components that Entergy has not fully explained and that are not clearly appropriate to include in the calculation of prepaid and accrued pension costs for inclusion in rate base,” the commission said.
Entergy had proposed a formula that included using a funded status minus unrecognized gains and losses. But FERC said the company should calculate cumulative differences between its pension contributions and expenses each year.
The commission said Entergy failed to explain what constitutes “unrecognized gains and losses” and describe why it thought its proposed calculation would yield the “same result as calculating cumulative employer contributions and cumulative pension expense.”
“Without additional explanation, we are unable to evaluate whether unrecognized gains/losses are an appropriate component to include in the calculation of prepaid pension costs to be included in rate base,” the commission said.
It also pointed out that “employee contributions to a pension trust are not shareholder-financed funds that the utility has paid out of pocket.”
“Consequently, it would not be just and reasonable for Entergy to include amounts that employees contribute to pension plans in rate base and earn a return on such amounts,” FERC said.
Another Shot
While FERC ordered removal of the pension line item, it also urged Entergy to refile the line item formula when it could “adequately demonstrate” its proposal.
“If the commission approves the inclusion of that line item, Entergy would then be required under the MISO formula rate protocols to provide specific prepaid pension cost amounts in its annual formula rate informational updates,” FERC wrote. “Interested parties would be able to challenge the prudency of such amounts at that time. … Therefore, we find that Entergy does not need to quantify or support specific prepaid pension costs in this proceeding to establish a line item in its formula rate.”
Finally, the commission said Entergy also needed to explain why its rate included prepaid and accrued pension costs even for its non-qualified plans. Non-qualified pension plans are often used as an additional retirement savings for executives and are not governed by the Employee Retirement Income Security Act.
“There is insufficient evidence and explanation in the record to find that Entergy’s proposed inclusion of prepaid and accrued pension costs for its non-qualified pension plans in rate base is just and reasonable,” the commission concluded.
FERC on Thursday rejected requests for rehearing of its order directing PJM to allow two merchant transmission operators to convert some of their firm transmission withdrawal rights (TWRs) to non-firm.
The New Jersey Board of Public Utilities and Public Service Electric and Gas had challenged the commission’s December 2017 finding that the RTO and PSE&G’s interconnection service agreements (ISAs) with Hudson Transmission Partners (HTP) (EL17-84) and Linden VFT (EL17-90) were unjust because they did not permit the conversions. (See NJ Merchant Tx Operators Win Relief on Upgrade Costs.)
The transmission companies own facilities that carried power into New York City as part of the “Con Ed-PSEG wheel,” in which 1,000 MW were exported from upstate New York to PJM through PSE&G’s facilities in northern New Jersey, and then exported to the city. Consolidated Edison and PSE&G canceled the agreement in April 2017. HTP and Linden had sought the conversions to relieve themselves of cost allocations under PJM’s Regional Transmission Expansion Plan.
Linden VFT’s exterior | Joseph Jingoli & Son
PSE&G argued that FERC erred in applying the just-and-reasonable standard of the Federal Power Act to the ISAs, rather than the public-interest standard of the Mobile-Sierra doctrine, which presumes the rates established through a negotiated contract are just and reasonable unless they’re found to harm the public interest. The commission had found the ISAs’ terms to be generally applicable to all PJM participants — and thus excluded from Mobile-Sierra — but the utility said the TWRs and provisions in the ISAs were unique, not pro forma.
In rejecting PSE&G’s argument, FERC pointed to the fact that Section 232.3 of PJM’s Tariff governs the conditions under which a transmission interconnection customer receives firm and non-firm TWRs. “Because PJM determined the TWRs available to HTP [and Linden] following [studies] conducted under terms and conditions that are generally applicable (even though the results of that study were specific to [the companies]), we regard those terms as generally applicable and therefore subject to the ‘just and reasonable’ standard, rather than the Mobile-Sierra presumption,” the commission said.
PSE&G also argued that the commission erred in finding no operational or reliability rationale preventing it from directing that PJM convert the TWRs and that it ignored the utility’s affidavit that raised concerns about the operational, reliability and LMP impacts from the conversions, rather relying on “one sentence written by an attorney in a PJM pleading, unsupported by any independent evidence or expert testimony.”
“We disagree with these PSEG arguments,” FERC said. It “reasonably relied on statements from PJM that reducing [the] TWRs from firm to non-firm presented no operational or reliability risks to PJM’s system.” The commission also noted that the utility’s affidavit relied on NYISO’s 2016 Reliability Needs Assessment, which made no reference to the TWRs in question.
The New Jersey BPU argued that FERC failed to consider whether the conversions would result in preferential rates to NYISO customers. But the commission said that argument was outside the scope of the proceeding, as Schedule 12 of the PJM Tariff calculates merchant transmission facilities’ cost responsibilities for RTEP projects based on their firm TWRs.
