Page 1261 – RTO Insider

August 13, 2019

ISO-NE Planning Advisory Committee Briefs: Aug. 8, 2019

ISO-NE planners will update the base cases for the Boston 2028 Needs Assessment to include Central Maine Power’s New England Clean Energy Connect (NECEC) and the Revolution and Vineyard offshore wind projects, senior engineer for transmission planning Pradip Vijayan told the Planning Advisory Committee on Thursday.

NECEC will be modeled as a 1,090-MW injection at the Larrabee Road 345-kV line in Maine, while Revolution Wind will be modeled as a 120-MW injection at the Davisville 115-kV line in Rhode Island (20% of the contact value of 600 MW). Vineyard Wind is also modeled at 20% of its contract value, or 160 MW. Revolution Wind is being included even though its impact on the Boston study area is not considered significant, Vijayan said.

The update also will reflect Forward Capacity Auction 14 retirement and permanent delist bids and FCA 13 retirement and delist bids outside Boston, resources which were assumed to be available for dispatch in the previous assessment. Additional active demand capacity resources will reduce net load by 55 MW.

The update will be restricted to an evaluation of 2028 peak load conditions; the changes are not expected to impact assessments of minimum load, short circuits or the 2022 peak load.

The RTO plans to issue its first request for proposals for a competitively developed transmission solution under ISO-NE Refines Competitive Tx RFP Template.)

ISO-NE planners want to maintain as much as possible of the current restoration plan, in which Mystic 8 and 9 are among the first units brought online to energize the Boston transmission system. The units help regulate system voltage during the energization of the cables. To replace them, the RTO will be seeking a dynamic reactive device capable of absorbing the charging associated with the cables, Vijayan said.

The device must be able to be re-energized remotely and adjust its voltage control set point remotely based on ISO-NE dispatch instructions. To meet NERC standard PRC-024-2 and ISO-NE’s transient voltage criteria, it also will be required to stay connected on a low-voltage ride-through for between 0.15 and 10 seconds, depending on voltage. Required high-voltage ride-through will be 0.2 to one second.

The RTO has identified several potential locations for the device: Mystic 345-kV or 115-kV; North Cambridge 345-kV or 115-kV; Wakefield Junction 345-kV or 115-kV; Woburn 345-kV or 115-kV; and Tewksbury 345-kV.

ISO-NE is also working with Eversource Energy and National Grid to develop solutions to the time-sensitive high-voltage needs identified at minimum load levels in the Needs Assessment.

They have narrowed the potential solutions to a single 160-MVAR reactor at Golden Hills 345-kV or one 76-MVAR reactor at each location for one of the following combinations:

Everett 115-kV and K Street 115-kV
Everett 115-kV and Lexington 115-kV
K Street 115-kV and Lexington 115-kV

Cost estimates and evaluations of the options will be discussed at September’s PAC meeting, when a preferred alternative will be selected. The PAC will discuss the results of the Needs Assessment update in October.

Stakeholder comments on the PAC presentation should be submitted to pacmatters@iso-ne.com by Aug. 25. The RTO set the same deadline to be informed of projects that should be reflected in the assessment update because of state-sponsored solicitations.

RSP 19 Stakeholder Comment Review

ISO-NE’s Director of Resource Adequacy and System Planning, Carissa Sedlacek, presented a review of stakeholder comments on the draft 2019 Regional System Plan (RSP).

Sedlacek went one by one through 83 comments, explaining why RTO staff did or did not accept suggested edits. Some comments were legalistic tweaks to the wording, such as deleting a reference to “regional regulators,” as there is no such thing.

In several instances, the RTO preferred the phrases “energy constraint” to “fuel constraint,” and “energy storage” rather than “battery storage.”

“ISO-NE is trying to be more generic in the language, for the region has large pumped hydro facilities that are storage facilities,” Sedlacek said.

Regarding a question on exactly what the RTO meant by “variable energy resources” (VERs), she said “the sentence states that ‘VERs … are replacing nuclear, coal and oil resources…’ which is true. The [RTO] is not stating that VERs are the same as gas-fired generation, just that VERS are variable.”

Synapse Energy, commenting on behalf of the Maine Office of Public Advocate and the energy-buying consortium PowerOptions, suggested ISO-NE add a mention to 1,381 MW of storage in a section that described the region’s wind and large-scale PV resources and that it specify whether the storage is behind-the-meter, front-of-the-meter or both.

Sedlacek referred to the RTO’s comment that it considers all behind-the-meter resources in its peak and energy forecasts. “However, we don’t create a BTM energy storage forecast,” she said.

David Ismay of the Conservation Law Foundation (CLF) wanted wording changed to reflect that “five of the six” New England states have climate change as a top priority. But Sedlacek said staff did not accept that suggestion because the RSP “is not intended to be a breakout of state policies.”

CLF also recommended discussing “the connection to ISO-NE’s fuel and energy security concerns, including capacity supply obligations granted to fuel-insecure plants at effectively their full nameplate capacity.” CLF said it was “particularly relevant” given FCA 13’s clearing of NTE Energy’s Killingly Energy Center, a 650-MW natural gas generator planned in Killingly, Conn.

“The RSP is not the place to have a discussion of matters in an open docket,” Sedlacek said. “ISO-NE awaits responses from FERC on open dockets for FCA 13 and Mystic 8 and 9.

“We hear you; we see your comments. We’re talking about energy security versus fuel security, and the integration of increasing amounts of renewable resources,” she said.

2019 Economic Studies Detailed Assumptions

Stakeholders discussed the detailed assumptions for three 2019 economic studies, as presented by ISO-NE staffers Peter Wong and Patrick Boughan.

The RTO agreed to analyze scenarios and market impacts for the integration of up to 9,700 MW of offshore wind by 2035, similar to what was requested separately by the New England States Committee on Electricity and transmission developer Anbaric Development Partners. (See ISO-NE Planning Advisory Committee Briefs: April 25, 2019.)

The NESCOE scenarios will model five levels of offshore wind ranging from 1,000 to 7,000 MW, while the Anbaric scenarios will model three between 5,700 and 9,700 MW. They also will look at varying injection locations and several potential transmission expansions, most of them 345-kV reinforcements, Wong said.

In addition, planners will evaluate two potential transmission upgrades that would increase the operating limits of the Orrington South interface in Maine, as requested by RENEW Northeast.

In one scenario, planners will consider increases of 0 to 170 MW from the modified 2016 transfer limits provided by RENEW. In the second scenario, they will evaluate increases of 100 to 825 MW. The analysis will be performed with and without the interfaces downstream of Orrington South being modeled at the projected 2025 transfer limits.

Based on the currently expected transmission system for 2030, the RTO anticipates it could add about 7,000 MW of offshore wind without additional major 345-kV reinforcements, though some reinforcement or expansion may still be needed, Wong said.

If more than 7,000 MW is added, the RTO sees the potential need for transmission reinforcements or new injections.

NESCOE counsel and analyst Ben D’Antonio asked how ISO-NE ranked the alternative transmission upgrades or reinforcements to accommodate offshore wind. Wong said that the RTO would discuss the issue and report back.

“If there’s more reinforcements beyond 345-kV lines, we want to see that,” D’Antonio said.

“We will be developing plans and high-level expansion costs associated with those needs,” Wong said.

Theodore Paradise, counsel and senior vice president of transmission strategy at Anbaric, said, “When we get close, is it that 200 MW that really pushes it over [the transmission capacity limit]? … If we spread out these interconnection points so we don’t overload, we’re OK with that too.”

“We will have to decide what modeling to use for best results,” Wong said.

VELCO Berlin Substation Condition

Vermont Electric Power Co. (VELCO) engineer Hantz Presume reported on the dilapidated condition of the Berlin substation, which connects two 115-kV lines and one transformer.

Problems include obsolete relays, lack of protection for breaker or circuit switcher failures, lack of a back-up protection system, and lack of high-speed protection.

The control building lacks space to accommodate needed improvements, communication equipment and ancillary systems, Presume said, and its location does not meet National Fire Protection Agency (NFPA) requirements that it be more than 50 feet from any power transformer.

VELCO proposes replacing the control building and the protection and control (P&C) system, installing a breaker failure scheme and high-speed protection as the second scheme.

The New England Power Pool transmission facility portion of the costs is estimated at $5.9 million, and the non-PTF portion at $4.7 million, for a total project cost of $10.6 million (+/-10% accuracy and including 15% contingency).

Replacing the substation could cost up to seven times as much, Presume said.

Eversource 345-kV Structure Replacements

Eversource’s John Case presented the company’s plans to replace 1,483 345-kV structures at an estimated cost of $403.9 million (-25%/+50%).

The replacements will be light-duty tubular steel poles that comply with current clearance and strength code requirements. Eversource anticipates completion of the work in 2021.

After this replacement program, any future 345-kV upgrades that require PAC approvals will be brought forth on a line-by-line basis, Case said.

The company is supplementing foot patrols with high-definition cameras on drones, which allows inspectors to see possible damage from all angles, he said.

“The use of drones is phenomenal at getting right in there to see what’s going on; it’s a great tool,” Case said.

– Michael Kuser

August 12, 2019

Study: Password Practices Remain Poor

By Rich Heidorn Jr.

Despite nearly daily news of cyber breaches, most computer users practice poor password security, and many people working in information technology and security would not recognize a phishing attempt if they saw one. Those are some of the disturbing takeaways from a survey of 5,000 people released last week by antivirus provider PC Matic.

“Passwords are one of the weakest links when it comes to cybersecurity, yet the importance of proper password management continues to be minimized,” PC Matic said.

More than 80% of the respondents indicated they use passwords they have memorized (55%) or written down (26%), with only 19% reporting use of a password manager. About half said they change their passwords only when they are forced to do so, a vulnerability when users continue using passwords that have been compromised through data breaches.

password security — More than 80% of the survey respondents indicated they use passwords they have memorized or written down, with only 19% reporting use of a password manager. | *PC Matic*

“Over 55% of businesses require employees to change their passwords fewer than two times annually,” the company said. “Even more alarming, over 20% of government employee respondents reported never changing their passwords.”

In addition, 20% of respondents said they use the same passwords for work and personal accounts. “Therefore, if these individuals fall victim to a data breach, the risk spills onto their employers, as the passwords those employees are using are now on the dark web,” PC Matic said. “The majority of respondents who reported using the same passwords for both personal and work purposes were 18-29 years old, nearly doubling the percentages of other age groups.”

Almost half of those surveyed said they access their personal email accounts through corporate networks. “This may not be an issue if the personal email accounts are completely secure and the employee does not click on any malicious links or open a malicious email while connected to the company’s network,” PC Matic said. “However, how likely is that to occur?”

The survey found 69% of respondents have seen a phishing email, but that more than 16% were unaware of this threat. One-quarter of respondents who were unaware of phishing reported their employment was directly related to IT and security. “Alarming?” asked PC Matic. “Very.”

More than 64% of respondents reported using two-factor authentication at work, home or both, while 14% said they were unaware of the concept.

PC Matic said companies should enable two-factor authentication and use virtual private networks, which use encryption to provide secure access to remote computers over the internet. It said companies should require employees to update their passwords every six weeks, prohibit recycling of passwords, require a predetermined password strength and offer them a password vault.

Users changing their passwords regularly will have some protection even if their vault is hacked, the company said. “It takes time for hackers to sell data on the dark web. Therefore, by the time it is actually sold, the passwords will be useless because users would have already updated them.”

August 11, 2019

UPDATED: Temps, Demand, Prices Soar in Texas

By Tom Kleckner

Summer has been late in coming to Texas, but it is quickly making up for the delay with triple-digit temperatures that are leading to four-figure prices in the ERCOT market.

AccuWeather says a ridge of high pressure has settled over Texas and will remain into the middle of this week, funneling hot air from the Western U.S. into the southern Great Plains. San Antonio and Dallas each had a single 100-degree day before last week. Houston hit 100 degrees for the first time on Thursday; heat indexes as high as 110 are expected into this week.

Naturally, energy consumption has been rising with the temperatures. On Wednesday, ERCOT demand peaked at nearly 73.1 GW during the interval ending at 5 p.m., falling just short of the all-time record of 73.5 GW set last July. Two days later, it topped 73.1 GW, setting an all-time high for August and marking the grid operator’s second-highest peak ever recorded.

ERCOT has so far met demand without resorting to the emergency measures it warned it might have to take before summer began. The grid operator has an 8.6% reserve margin and 78.9 GW of available capacity to meet a projected peak of nearly 75 GW. (See ERCOT: More Capacity, but Emergency Ops Still Expected.)

“ERCOT expects to have adequate generation to serve customers during this hot spell,” spokesperson Leslie Sopko said.

Real-time prices peaked systemwide at more than $2,400/MWh on Aug. 5, then settled at a high of $1,238.97/MWh at the West hub the next day, before dropping to a high of $91.96/MWh in the Houston load zone Wednesday. Houston hub prices hit 1514.94/MWh on Friday during the 15-minute interval ending at 3 p.m.

Day-ahead power prices hit $209.25/MWh in the North hub Thursday, the highest since reaching $300/MWh the day before the record peak last July. The hub’s next-day prices were at $38.50/MWh on Aug. 5.

August 11, 2019

Bankruptcy Judge Questions PG&E Exec Compensation

By Michael Brooks

The judge overseeing PG&E Corp.’s Chapter 11 bankruptcy questioned the utility’s attorney last week over a proposed compensation package that includes about $11 million in performance-based bonuses for 12 executives.

At a hearing in San Francisco on Friday, Judge Dennis Montali, of the U.S. Bankruptcy Court for the Northern District of California, said he took issue with the language included in a PG&E court filing supporting its key employee incentive program (KEIP), filed with the U.S. Securities and Exchange Commission in late June.

The utility told the court its board of directors’ compensation committee had “determined that the KEIP was necessary to appropriately incentivize and align the KEIP participants’ goals and performance with those of the [company] and … to provide the KEIP participants with the opportunity to achieve a market rate of compensation, but only if the KEIP performance goals are achieved.”

Montali told PG&E attorney Stephen Karotkin that he had a problem with the phrase “appropriately incentivize,” recalling that the utility’s equipment was responsible for some of the worst wildfires in the history of the state.

“If they’re not incentivized enough, they ought to find another job, frankly,” the judge said.

Karotkin defended the bonuses, saying they would only be paid if the executives met certain targets. He assured the judge that they were dedicated to safety and regaining state residents’ trust.

Montali also said he found it “troublesome” that the utility paid its new CEO, former Tennessee Valley Authority CEO Bill Johnson, a $3 million signing bonus without disclosing it to the court. Although the company disclosed the payment in an SEC filing and it was reported on in the press, it was paid before the company filed the KEIP with the court, which appeared to perturb the judge.

After a long back-and-forth with an attorney from the U.S. Trustee Program, who ultimately said he did not find the payment improper, Montali decided against ordering Johnson to disgorge the payment, though he scolded PG&E for being “too clever by half.”

CPUC ‘Protocol’ Talks Fail

Friday’s hearing was set to discuss the results of negotiations between the California Public Utilities Commission and several ad hoc groups of bondholders, insurers and wildfire claimants that have asked Montali to terminate PG&E’s exclusivity period — the time it has to offer a reorganization plan without the judge having to weigh competing proposals. The other stakeholders want the court to consider their own bankruptcy plans.

PUC attorney Alan Kornberg last month persuaded Montali to give the commission, Gov. Gavin Newsom’s office and the groups time to work out a “protocol” — a process and timeline for the commission to consider all the competing plans and file one with the judge. Kornberg said the effort could expedite the process by eliminating the need for Montali to review several plans.

Under Assembly Bill 1054, passed last month, the PUC must approve a bankruptcy plan by June 30, 2020, for PG&E to be able to access a $21 billion fund to pay wildfire claims. (See California PUC Jumps into PG&E Bankruptcy Fray.)

But on Friday, Kornberg reported that talks had broken down, with the groups apparently insisting that PG&E play no role in selecting a restructuring plan. Montali directed Kornberg and the several attorneys representing the other parties to the discussions not to give him details of the talks so as not to prejudice himself before he rules on the groups’ motions to terminate exclusivity on Tuesday.

Kornberg did say that several parties had told him they were confident the legislature would extend the June 30 deadline. An attorney for Newsom’s office called banking on that “an unintelligent move.”

Montali asked Kornberg if the PUC could begin to work on its own approval process simultaneously with the court. Kornberg said the commission needed a court-approved plan to consider; otherwise, it could waste time and resources considering a plan that might not ultimately be approved.

Earnings

The hearing came after PG&E reported earlier that day that it had lost $2.55 billion ($4.83/share) in the second quarter. The company posted a loss of $983 million ($1.91/share) for the second quarter last year.

The loss included a $3.9 billion pre-tax charge for estimated third-party claims related to the 2017 Northern California wildfires and the 2018 Camp Fire. The company has lost about $2.4 billion this year; it posted a profit of $136 million ($0.25/share) for the first quarter.

Total revenue for the second quarter was down about 7%, from about $4.2 billion in 2018 to about $3.9 billion this year.

“Items impacting comparability for the quarter also include enhanced and accelerated electric asset inspection costs; clean-up and repair costs related to the 2018 Camp Fire; legal and other costs related to the 2017 Northern California wildfires and the 2018 Camp Fire; and financing, legal and other costs related to PG&E Corp.’s and Pacific Gas and Electric Co.’s reorganization cases under Chapter 11 of the U.S. Bankruptcy Code,” the company said in a statement.

“Our primary focus areas are to further reduce the risk of wildfires in the communities we serve, to improve our safety and operational performance across the board, and to move expeditiously through the Chapter 11 process, which includes paying wildfire victims fairly and as soon as possible,” Johnson said. “We recognize we are operating from a deficit when it comes to public trust, and to regain that trust, we must sustain excellent operational performance day after day, month after month, year after year.”

August 11, 2019March 19, 2025

Connecticut Activists Protest Gas-fired Plant

By Michael Kuser

HARTFORD, Conn. — About 40 environmental activists marched Wednesday in front of the headquarters of Connecticut’s Department of Energy and Environmental Protection to protest state regulators’ recent approval of a new gas-fired power plant in the town of Killingly.

The Connecticut Siting Council on June 6 approved construction of the 650-MW Killingly Energy Center by Florida-based developer NTE Energy, permitting the plant to emit up to 2.2 million tons of carbon dioxide each year.

The organizers included Connecticut Fund for the Environment, Not Another Power Plant, the state chapter of the Sierra Club and Wyndham Land Trust.

Environmental activists marched Wednesday in front of DEEP headquarters to protest the approval of a 650-MW power plant in Killingly, Conn. | © RTO Insider

Sierra Club volunteer Martha Klein led the protesters in a chant on the steps of DEEP headquarters: “Hey, hey, ho, ho, Katie Dykes has got to go!” — referring to the DEEP commissioner.

“I’ve got a simple one-word answer for why Connecticut keeps expanding fracked methane despite knowing that it’s destroying our climate: It’s ‘corruption,’” Klein said. “It’s equal opportunity corruption, for we’ve had both a Republican governor [John Rowland] and a Democrat mayor [Hartford’s Eddie Perez] go to jail.” Neither politician was convicted of illegal activity related to the energy sector.

Martha Klein, Sierra Club | © RTO Insider

Klein told RTO Insider that “when the state approves new power plants run on fracked gas or oil, that’s going to exacerbate climate change.”

Ann Gadwah, chair of the state’s Sierra Club chapter, said, “This plant is totally unneeded. New England doesn’t need the power, and Connecticut doesn’t need the power.”

Gadwah said regulators seem to have forgotten that the state legislature passed a law requiring DEEP to monitor air quality in the eastern part of the state after New York approved construction of the 1,100-MW natural gas-fired Cricket Valley Energy Center, which is slated to go online next year and the emissions of which would generally blow into Connecticut from its site just west of the state line.

RTO Scapegoat

James Albis, a senior advisor to Dykes, spoke to activists and reporters at the protest and handed out flyers with questions and answers on Killingly.

On why the plant is being built, DEEP said, “It was procured through the regional ISO New England capacity market auction to meet regional reliability needs. It will help address reliability needs in the winter because of its dual-fuel capability, allowing it to run on ultra-low-sulfur diesel during peak times when natural gas is constrained, which is a cleaner alternative to other baseload peaking generators.”

KEC Site Location | NTE Energy

In response to the question of who will pay for the plant, the department said the state “does not have any contractual obligations with Killingly. The plant cleared in the regional [ISO-NE] market that Connecticut participates in, but NTE (the developer) bears the risk of participating in the market and the potential for stranded costs as Connecticut moves to a zero-carbon future.”

Melinda Fields came to protest from Hampton, a few miles west of Killingly.

“I protested the Siting Council meeting too,” Fields said. “It seemed like they only wanted to help the company get what it wanted; like, ‘what can the state do for you?’”

The area’s state senator, Mae Flexer, submitted testimony stating that Connecticut Economic Resource Center data indicate that Killingly would become the second-largest power generation town in the state if the plant is built, behind only Waterford, site of the Millstone nuclear plant.

Independent activist Cher Kapelner-Champ | © RTO Insider

“This would be an enormous burden to place on the people and environment of Killingly,” Flexer said. “To require so much of the state’s electricity to be generated here and — along with it — to concentrate such a large percentage of the state’s pollutants and emissions from power generation in this town is grossly unfair.”

Veteran activist Cher Kapelner-Champ said she had been among 1,200 people arrested in 1977 for protesting the construction of the Seabrook nuclear plant in New Hampshire.

“They built Seabrook anyway, so why do I keep protesting?” she said. “As a great Hebrew scholar once said, we all just bring our one teaspoon of compassion — and you never know when the tipping point will come.”

August 11, 2019July 8, 2025

Monitor: PJM Markets Remain ‘Under Attack’

By Christen Smith

PJM’s wholesale power markets remain “under attack” from those concerned about the retirements of legacy generators unable to profit in the face of ever-decreasing energy prices, the Independent Market Monitor said Thursday.

In its quarterly State of the Market report released last week, the Monitor — in a thinly veiled dig at PJM’s minimum offer price rule (MOPR) revisions pending before FERC — said there’s no reason to exclude competitive capacity offers from any generator, nor artificially increase energy prices to benefit struggling nuclear and coal plants.

“The value of markets is under attack, from those who think energy prices are too low and from those who think that market outcomes do not favor their preferred technology, whether it is nuclear, coal, wind or solar,” the Monitor said.

Instead, PJM should prevent the markets from reverting back to an integrated resource planning approach “that some would reimpose because markets provide technology-neutral incentives to all market participants, including those who will introduce technologies not yet in existence.”

“Markets continue to provide the most efficient way to organize the production of power at the lowest possible cost,” the report reads. “Markets are also the most efficient way to integrate state-supported renewable technologies.”

Record Low Energy Prices

The Monitor reported that energy prices decreased 35% to $27.49/MWh in the first six months of 2019, compared to the $42.44/MWh seen a year prior. Lower fuel costs contributed to nearly a third of the decline, while decreased load and lower mark-ups comprised the rest. These are the lowest load-weighted real-time energy prices ever seen in PJM, the Monitor said.

The lower prices drove down net revenues for all unit types, including: 65% for combustion turbines, 44% for new combined cycles, 87% for new coal plants, 30% for new onshore wind and 34% for new nuclear plants.

The last includes the subsidized Quad Cities and three other Exelon nuclear facilities in Illinois — Braidwood, Byron and LaSalle. Based on current forward prices, the Monitor said, all four of the plants will fail to recover their avoidable costs in two of the three forward years, with an average annual shortfall of 73 cents/MWh during the shortfall years.

Quad Cities nuclear plant | Exelon

Exelon told investors earlier this month that without substantive legislative action, the company will close unprofitable plants so as to not “damage the balance sheet sitting around for years with negative free cash flow or negative earnings.” (See related story, Exelon to Close Three Mile Island.)

The Monitor acknowledged PJM’s markets are imperfect and said a carbon price would provide a market-based solution to reducing emissions and supporting nuclear plants’ economics. But it said “the fact that some plants are uneconomic [without a carbon price] does not call into question the fundamentals of PJM markets. Many generating plants have retired in PJM since the introduction of markets, and many generating plants have been built since the introduction of markets.”

Energy Market Competitive, Capacity Market not

The Monitor said PJM’s energy market remains competitive while the capacity market does not — consistent with the Monitor’s conclusions in reports released in March and May. (See Energy Market Competitive in Q1, PJM Monitor Says.)

As an alternative to PJM’s MOPR for addressing the dilemma between “market solutions and potentially inconsistent state policy initiatives,” the Monitor again touted its proposed Sustainable Market Rule (SMR). (See PJM Monitor Reiterates Concerns in Quarterly SOM Report.)

Under the SMR proposal, all nonmarket resources could participate in the energy market without limits, with the capacity market used as a “balancing mechanism” for providing incentives for resources to enter and exit.

“The SMR approach to the capacity market design is simple, based in economic logic, based on the PJM competitive market design and does not require complex rule changes to implement,” the report reads. “The SMR would provide a straightforward way to harmonize federal and state approaches to the provision of energy, while respecting the distinction between federal and state authority. The SMR reaffirms the definition of a competitive offer in the PJM capacity market and removes noncompetitive barriers to the participation of renewables.”

The Monitor also criticized PJM’s energy price formation plan, saying that it guarantees double recovery for generation owners “by breaking the tight link between energy and capacity markets that has been essential to the success of the PJM market design.” It also accused the RTO of creating unintended consequences by pushing through substantial energy market revisions without any explanation of how such changes would “enhance or even maintain the competitiveness of the markets.”

The Monitor outlined five steps to address what it called legitimate concerns about price formation in the energy and reserves markets:

Consolidate the tier 1 and tier 2 synchronized markets.
Increase the scarcity price to reflect the highest generator energy offer allowed.
Increase the transparency of operator actions, with explicit pricing for defined actions.
Implement clear rules governing real-time pricing through the selection of real-time security constrained economic dispatch (RT SCED) and locational price calculator (LPC) cases. LPC, which uses the latest approved RT SCED case as its reference case, produces financially binding LMPs and reserve market clearing prices.
Develop a consistent definition of energy and reserves products in the day-ahead and real-time markets, including recognition of the appropriate role of demand-side resources.

“This should not be the end of the discussion, but the beginning of a longer, more complete discussion which would lead to incremental steps to improve markets,” the report concluded.

Recommendations

The Monitor provided three new recommendations for PJM stakeholders to consider:

Demand response reductions based entirely on behind-the-meter generation should be capped at the lower of economic maximum or actual generation output.
Load and generation located at separate nodes should be treated as separate resources.
FERC should require that the open firm flow entitlement (FFE) and firm flow limit freeze date issues be addressed at a technical conference, and that a deadline to resolve the issues that result from the freeze date be set. PJM, Outside Parties Slow MISO-PJM Freeze Date Thaw.)

August 11, 2019

ERCOT, WMS Collaborate on Price Corrections

By Tom Kleckner

ERCOT staff have laid out a plan to work with stakeholders in addressing a May pricing event that has led to a complaint filed with Texas regulators against the grid operator.

Kenan Ögelman, ERCOT’s vice president of commercial operations, met with the Wholesale Market Subcommittee on Wednesday and proposed three issues for further discussion with market participants, including potential changes to the grid operator’s price-correction methodology; adding filters, requirements or different standards to the external telemetry coming into ERCOT; and improving the communications structure around price corrections.

Ögelman said staff would return to the WMS in September with an issues list. He said he expects “more topics than any solutions.”

“We’d like to give a high-level presentation and see if you have any other issues,” Ögelman said. “I think it’s important everyone see all the issues and where they’re going so we can get a solution.”

On May 30, prices briefly reached the $9,000/MWh maximum when the security-constrained economic dispatch system received bad telemetry data from Calpine. Staff quickly corrected the data, but they have refused to correct the prices because the data were external.

“Incorrect telemetry coming from outside ERCOT is not something we run corrections for,” Ögelman told the grid operator’s Board of Directors in June.

Aspire Commodities, an energy broker, has filed a complaint with the Public Utility Commission of Texas asking that generators refund the market $18 million (49673). (See ERCOT Asks PUC to Dismiss Trader’s Complaint.)

Morgan Stanley’s Clayton Greer, who has complimented ERCOT on its quick response to the pricing error, urged quick decisions in the future.

“You let us know you were not going to reprice that day. The market understands once you do that, it’s final,” he said. “If you could find a way to put into words what you did [on May 30] into the protocols, that would be optimal.”

“We want prices to reflect the fundamentals of the market,” Reliant Energy Retail Services’ Bill Barnes said.

Luminant Generation’s Ian Haley indicated his company preferred to see bad telemetry rejected.

“We don’t think ERCOT should be in the business of determining what is and what isn’t correct,” he said.

August 11, 2019

MISO to Limit Capacity Resource Extended Outages

By Amanda Durish Cook

CARMEL, Ind. — MISO is working quickly to ensure its capacity resources are mostly accessible for the planning year after this spring’s auction cleared a Michigan generator scheduled to be on outage for the entire period.

The RTO proposed a provisional solution at the Resource Adequacy Subcommittee meeting Wednesday that would limit extended planned outages to fewer than 90 days to qualify for participation in the Planning Resource Auction. Additionally, resources expected to be unavailable for the first 90 days of the planning year would not qualify for PRA participation.

Cleared resources with planned outages lasting 90 days or longer must replace their capacity or be penalized at MISO’s approximately $250/MW-day cost of new entry. Currently, the RTO doesn’t impose any penalties for capacity resources that take extended outages.

“If you think about MISO’s resource adequacy construct, there is a reasonable expectation of availability,” Director of Resource Adequacy Coordination Matt Ellis said.

MISO plans to file the proposal with FERC by mid-October to have it in place in time for the 2020/21 PRA, an unusually fast turnaround for the RTO, which can spend several months to a few years formulating new Tariff language. MISO said it also plans to seek more fleshed-out outage rules for the 2021/22 auction.

Ellis said that while MISO may not be able to make a comprehensive filing now because it must examine several possible unintended consequences, it can impose a straightforward, 90-day requirement.

“It’s an incremental change. It’s intended to be a step in the right direction — something we can refine further as we go along,” Ellis said.

April’s PRA cleared a large generator in Michigan’s Zone 7 as a capacity resource for the 2019/20 planning year even though it is slated to be on an extended outage for the entire year. The Independent Market Monitor first criticized the move in June. (See “Extended Outages and the Capacity Auction,” Monitor Splits with MISO on Summer Readiness.)

Ellis said the 90-day requirement is meant to capture the possibility that a planning resource will be out for an entire season. Requiring availability in the first 90 days of the planning year also ensures that capacity resources will be available during summer months when availability is more critical. MISO planning years begin June 1.

Stakeholders immediately inquired about planned outages that come in just under the threshold, but Ellis said MISO is starting by drawing the line at 90 days.

“And honestly, when we discussed this internally, that’s the first thing that came up: ‘What if units take an 89-day outage?’” Ellis said. “What’s the bright line? We chose 90.”

Ellis said MISO will revisit its proposal if 88- to 89-day outages begin to become “habitual.”

When stakeholders asked what would happen if a generator extends an outage to 90 days or longer, Ellis responded it wouldn’t be retroactively penalized to cover replacement capacity. However, MISO and the Monitor would keep a sharp eye for resource owners that might be seeking to game the rule with sudden extensions. Under the plan, the Monitor would have Tariff authority to audit outages for physical withholding.

Stakeholders said the proposal could encourage generators to take forced outages — and the accompanying hit to resource accreditation — over taking a long-term planned outage that would exclude them from a capacity payment for a planning year or face having to replace the capacity at a high cost.

MISO has left the proposal open to other stakeholder comments through Aug. 23.

August 11, 2019

NYPSC Opens Resource Adequacy Proceeding

By Michael Kuser

New York regulators on Thursday kicked off a proceeding to examine how to reconcile NYISO’s resource adequacy (RA) programs with the state’s renewable energy and carbon emission-reduction goals (Case 19-E-0530).

“This item to open an inquiry is important and timely,” Public Service Commission Chair John B. Rhodes said. “We at the commission have a duty to ensure safe and adequate power. Safe means safe, and adequate means, in this case, [that] there’s power when New Yorkers need it. … It’s becoming questionable whether the answers that were organized at least 20 years ago are in fact the best answers for the situation we face today.”

David Drexler, the PSC’s managing attorney, said “a major impetus” for the RA inquiry is New York’s recently passed Climate Leadership and Community Protection Act (A8429) — particularly its mandate that 70% of the state’s electricity be generated by renewable resources by 2030.

Commissioner Diane Burman said she understood the need to examine electricity issues, “but I do find it disingenuous to say that we have an obligation to do this when there are many other issues that we have an obligation to examine,” pointing to Consolidated Edison’s moratorium on providing new customers with natural gas hookups in Westchester County until it can ensure adequate supply to the region.

The PSC held its regular monthly session in Albany on Aug. 8, 2019.

“I think the chairman nailed it when he said that the current approach was set 15 to 20 years ago, and it’s based on the cost attributes of a fossil generator,” said Warren Myers, director of regulatory and market economics for the state’s Department of Public Service.

The inquiry will focus on answering several questions, including:

Are the state’s energy policies and mandates, such as those related to offshore wind, photovoltaics, other renewables and energy storage, compatible with NYISO’s RA mechanisms? If not, what issues are manifested? Also, if not, how could they be aligned? Do policies and market structure mechanisms result in safe, adequate service at just and reasonable rates?
Is an installed capacity (ICAP) product an effective long-term solution for RA given the required future generating resource mix, which may have lower marginal costs or different availability profiles than many current generation resources in operation? What are the salient attributes of such long-term solutions?
Is there a preferred mechanism for ensuring RA? What are the cost impacts and benefits to consumers under the various potential RA mechanisms?
Should alternative approaches be considered to ensure that procurement of generation resources is aligned with state policy goals? If so, which ones? Are there existing or proposed models that might be instructive, such as the state overseeing the RA portfolios of load-serving entities as in California, or should NYISO rules be restructured to accommodate state policies?
What is the state’s role with respect to RA matters?
What, if any, next steps should the commission take with respect to RA matters?

First of Many

NYPSC Resource Adequacy — Commissioner Diane Burman

Burman said she would ask the “elephant-in-the-room question,” wanting to clarify that the PSC’s new effort would not seek to “undo the role of the ISO” regarding RA, “but in fact is looking at how can we work on these issues.”

“The elephant is prematurely in the room,” Myers responded.

Drexler said, “Actually, from a staff perspective, we’re not prejudging any of the issues at this point. This is merely meant to start the inquiry.”

Commissioner James Alesi supported the inquiry, saying that “New York is already on its way to cleaner energy consumption.”

Commissioner Tracey Edwards said it was better to start asking the right questions now than later, “when we’d be doing so in a defensive posture.”

Attending his first session since being appointed to the PSC on July 19, Commissioner John Howard said, “The truth is, the ISO and its markets work today; the lights stay on; people get paid. If you’re an incumbent, things seem to be pretty well-ensconced. However, that doesn’t mean there aren’t holes that need to be examined. … I believe this will be the first of many inquiries.”

In an Aug. 8 blog pos t, Jackson Morris and Cullen Howe of the Natural Resources Defense Council welcomed the PSC’s inquiry and raised two points.

“A central concern held by many stakeholders, including NRDC, is that NYISO’s capacity market rules could prevent clean energy resources supported by state and local policies from selling in that market, thereby depriving these resources of an essential source of revenue. …

“Another concern is that NYISO’s rules undercount the value of cleaner resources like energy storage systems, as well as wind and solar, while over-crediting highly polluting power plants.”

Burman expressed additional concern that the proceeding seems to lack direction: “Ultimately, all we seem to be addressing is the capacity markets and buyer-side mitigation, and then taking a look at, in some fashion, whether or not we want to change those rules.”

The commission has asked interested parties to submit initial comments by Nov. 8. Commenters can file with the DPS by e-filing or by email to secretary@dps.ny.gov, or through the department’s Document and Matter Management System.

“Today’s order is the beginning of an important discussion on resource adequacy, and we look forward to engaging with the Public Service Commission throughout the process to share our expertise, information and ideas,” NYISO CEO Rich Dewey said in a statement.

August 11, 2019

NERC Weighing Concerns on Reorg.

By John Funk and Rich Heidorn Jr.

NERC’s plan to streamline its top technical committees appears to face limited opposition, although officials indicated Thursday they are considering proposals to increase sector representation and lengthen the transition.

The new structure, to be discussed in detail at NERC’s quarterly meeting in Québec beginning Tuesday, would merge the Planning, Operating and Critical Infrastructure Protection committees into a new Reliability and Security Council (RSC). While the three technical committees have almost 120 voting members, the proposal would limit the RSC to 33.

Only two stakeholders made comments during a webinar Thursday on the proposal, both questioning why NERC hasn’t quantified the proposal’s supposed benefits. But NERC also has received written comments from a dozen stakeholder groups, who were nearly unanimous in calling for a longer transition and an increase in the number of sector representatives in the new organization. Some also questioned whether security issues should be combined with operations and planning.

The collapse of the existing committee structures aims to save time and money and reduce the “silos” and inefficiencies that some NERC members believe the three existing committees have created over time.

Exelon’s Jennifer Sterling, vice chair of the Member Representatives Committee (MRC) and co-chair of the Stakeholder Engagement Team (SET) that made the proposal, led the webinar.

“The idea is that we pivot quickly and focus resources rapidly,” she explained in her opening remarks. “You are all aware that our world and our industry are changing quickly and that the pace only continues to accelerate. We need to be agile. We need to be readily deployed to address these emerging issues.”

Existing subcommittees and task forces would remain intact for the time being and report to the RSC. Subcommittees that do not have recurring tasks would be eliminated or combined with others. “The whole idea is that every subcommittee should understand what their task is,” Sterling said.

Reassurances

Sterling acknowledged some stakeholders have expressed fears that the overhaul could unintentionally eliminate networking, workshops, lessons-learned sessions and similar interactions that have developed over the years.

“That was never our intention,” she said. “We would expect that the [RSC] would continue those activities going forward.”

Sterling also addressed concerns that reducing the number of committee members would diminish transparency and stakeholder involvement. “We are committed to making sure the meetings are held in spaces that are open and that provide enough space for everyone who wishes to attend,” she said.

Potential Changes

Sterling also indicated NERC is considering potential changes to the plan based on stakeholder feedback.

The SET proposed a “hybrid” of the regional representation used by the CIPC, the sector-based membership of the PC and OC, and the at-large membership of the MRC and Reliability Issues Steering Committee (RISC).

The RSC would include one voting member from each sector (except for the regional entities), 20 at-large members, a chair and a vice chair. Members would be selected by a nominating committee of NERC officers and approved by the Board of Trustees, with selections based on interconnection diversity, subject matter expertise, and a mix of small and large entities.

“Let me emphasize the word ‘proposed’ here,” Sterling said in prefacing her description of the proposed RSC makeup.

“We have gotten a number of comments that perhaps people would like to see more sector representatives. Right now, we have one per sector, but people have asked for two. And also, there have been a number of comments that they would like to see the sectors elect their own representatives. … These will all be discussed at the upcoming [SET] meeting, and I’m sure it will be discussed next week at the MRC.”

Sterling said her team also has heard stakeholder concerns that the proposed timeline — which calls for nominating RSC members in the fourth quarter and completing the transition in the first quarter of 2020 — may be too aggressive.

Stakeholders also have expressed concern that the RSC’s name could cause confusion with the RISC. “Essentially, the RISC will be developing the lists of risks on a strategic basis,” Sterling explained. “That RISC report, along with other reports, would then be used by the RSC to develop their tactical work plans.

“There were some people who thought that name, the RSC, might be confusing,” she acknowledged. “So, we’ll talk about that as a group at our August meeting.”

Cost-benefit Analysis

Only two stakeholders had comments during the workshop. Barry Jones, of the Western Area Power Administration, asked why the plan did not include an “impact analysis.” Keen Resources’ Robert Blohm, a member of the OC, said the proposal might not produce the promised efficiencies.

“What we have now are three groups simultaneously dealing with three parts of the overall issue, saving a lot of time,” he said. “I would have been more comfortable seeing this [proposal presented in] a more objective or less presumptive fashion, where cost-benefit arguments, pro and con, are listed quite clearly.”

Sterling said the SET’s goal was achieving efficiency, “and hopefully cost savings will result.”

Mark Lauby, NERC chief reliability officer, said the revamping would increase NERC’s effectiveness at addressing issues in a holistic manner. “Going from 120, 130 people to whatever the size of this group ends up being, that will certainly be less of a burden and cost to industry,” he added.

Written Comments

The Policy Input Package for the August quarterly meetings includes written comments from 12 sets of stakeholders, including industrial consumers, cooperatives, generation owners, transmission owners, utilities and RTOs.

In addition to calling for an increase in sector representation, many of the commenters also recommended eliminating the requirement that RSC members have “executive leadership experience,” saying that subject matter expertise is more important.

The Canadian Electricity Association was among the most skeptical of the proposal. “While evolving reliability issues faced by the industry may require solutions and expertise that expand across traditional operating frameworks, many companies are still internally structured through a planning/operations/security model,” said CEA, which represents generators, transmission and distribution companies. “This reality may make it challenging to identify RSC members who can bring the necessary breadth of knowledge and experience to work across these industry areas.”

It also said issues addressed by the RSC must be “well-prioritized, while also guarding against dilution of attention due to a higher number of issues being overseen by one group rather than three.”

Several commenters said that while they agree with combining the OC and PC, they saw less synergy in combining them with the CIPC, which focuses on security.

The Electricity Consumers Resource Council (ELCON), which represents large energy consumers, recommended replacing the OC and PC while retaining a separate security committee. The ISO/RTO Council said that while “there is reasonable justification” for combining operations and planning, “including security matters in the combined group does not improve efficiency.”

The Cooperative Sector said its members were split on the restructuring. It was also critical of NERC’s transparency, saying some of its members “found it challenging to understand the deliberations of the SET meetings and that meeting notes/minutes were not provided to industry. Additionally, the proposal states that the current technical committee members were surveyed for input on the existing committee structure, but the survey results were not made public.”

Only one set of comments, from stakeholders representing state, municipal and transmission-dependent utilities, opposed the RSC proposal (Option 2) outright, saying they preferred Option 1: keeping the three committees and adding a steering committee above them.

“Option 1 provides oversight by refocusing the OC, PC and CIPC, while retaining the benefits those committees bring to NERC and the industry,” it said. “If it is not acceptable as a long-term solution, Option 1 should be adopted as the mechanism for achieving an effective and efficient transition.”

Most of the commenters called for a slower transition. Said ELCON: “Change management at this scale often takes about six months to complete.”