Page 1026 – RTO Insider

November 3, 2020

ERCOT Technical Advisory Committee Briefs: Oct. 28, 2020

ERCOT stakeholders last week approved the oldest protocol change on the grid operator’s books, shooting down a late request to table the measure in the process.

Luminant filed comments on the revision request the day before it would be considered by the Technical Advisory Committee and requested a delay so committee members could review the comments.

The Nodal Protocol revision request (NPRR945) is hardly controversial. It simply removes the “associated load” term that proponents say has been interpreted in some instances to restrict private-service arrangements otherwise authorized under state law and regulatory precedent.

“We filed the comments because we’ve heard from different groups that the NPRR didn’t change anything,” Luminant’s Ian Haley said during the TAC’s web meeting Wednesday. “We had concerns that TAC would be voting without understanding what it does. We wanted to ensure TAC is well aware of what we’re voting on today.”

ERCOT — Katie Coleman, TIEC | © *RTO Insider*

Attorney Katie Coleman, representing Texas Industrial Energy Consumers and the measure’s sponsor, accused Luminant of “a little bit of sandbagging,” noting the revision dates back to May 2019 and that the company has had “ample opportunities to relay this concern.”

She reminded members that the issue has been discussed several times within the TAC’s Protocol Revision Subcommittee and that she conducted a workshop where she went through the NPRR’s effects and its history.

“This section of the protocols was meant to define the electric configurations that were eligible for net metering. It does not pertain to legal and regulatory requirements,” Coleman said. Referring to “associated load” as an “ambiguous term,” she said, “That term has been interpreted as load and generation to be owned by the same entity.

“That’s not what the language says, and I’m not sure it’s clear to market participants. It’s more restrictive than what the law allows in certain scenarios,” Coleman said. “We have [private-network] sites set up today, lawfully set up, and some reviewed by the [Public Utility Commission] in contested cases, where load and generation is not owned by same entity.”

Removing the term, Coleman said, will provide regulatory certainty for both existing and planned sites by deferring to legal and regulatory precedent and avoid potentially inconsistent interpretations of the protocols.

The NPRR adds language that “explicitly state[s]” that private-service arrangements must comply with PUC precedent and Texas’ Public Utility Regulatory Act. It also adds market transparency with a new reporting requirement that identifies all generation resources and settlement-only generators registered as part of behind-the-meter private-use networks (PUNs).

Luminant says NPRR945 provides clarity to those seeking to set up PUNs, but it raises “many additional and equally important policy questions, some of which cannot be addressed by ERCOT stakeholders.”

The generation company said PUNs are neither typical loads nor typical generation resources and are subject to nonmarket incentives that “warrant appropriate controls” to ensure their usage “balances risk and reward fairly across market sectors and customer classes.”

“In an energy-only market, this can actually harm resource adequacy objectives … by allowing a single entity to capture scarcity value that does not accrue to the rest of the market,” the company said in its comments. “Luminant supports correct pricing outcomes that utilize the demand of consumers in ERCOT and all generation bids needed to meet that demand. Unfortunately, [PUNs] bypass this needed aspect of price formation.”

“As Luminant is starting to understand, this has potential implications that are pretty serious,” said Golden Spread Electric Cooperative’s Michael Wise, saying he was concerned about cost shifts and their unintended consequences. “ERCOT’s interpretation of the protocols and the term ‘associated load’ has protected consumers very well. We believe it’s probably one of the most important issues brought forward to stakeholders and it merits this attention.”

Other TAC members weren’t so sure.

“With all due respect to Luminant and Golden Spread, these issues you’re raising are issues we’ve been discussing for months and months,” Demand Control’s Shannon McClendon said. “Katie has given detailed information. PUNs do not cause additional costs to the consumer. That’s a red herring Golden Spread is putting out there.”

Reliant Energy Retail Services’ Bill Barnes said that although he shared some of Luminant and Golden Spread’s concerns, he was “cautiously supportive” of NPRR945.

“I don’t think minds will change in one month. I don’t see the need to table,” he said.

The motion to table failed 8-22. The TAC then passed the measure by a 23-5 margin, with two members abstaining.

Staff, WMS to Address Market Delays

ERCOT staff will work with the TAC’s Wholesale Market Subcommittee to address what has literally become a growing problem.

At issue are the increased complexities of the day-ahead market (DAM), which has led to a steady increase in the market’s ability to publish its results on time. There have been 20 delays this year, the most since 42 in 2011, the first year of ERCOT’s nodal market.

ERCOT has seen increasing delays in its day-ahead market, driven in part by more granular point-to-point bids. | *ERCOT*

The grid operator allots three-and-a-half hours for the DAM’s execution, during which software must optimize its time, validate data inputs, execute the price-validation tool and post results, among other tasks. Input/output verifications and data errors can also lead to delays.

“There’s a lot of iteration in the DAM’s execution. Because of those iterations and other factors, we could have long run times to clear the DAM,” said Kenan Ögelman, ERCOT vice president of commercial operations. “If we get more than 170,000 [point-to-point (PTP) interval] submissions, we’ll pretty much have a DAM delay. An increase in settlement points can also lead to long run times.”

Ögelman said DAM participation has trended upward, with PTP bids largely contributing to the increased variables. Energy bids and energy-only bids have also grown, and binding constraints are on an upward path.

He said staff haven’t been “sitting on our hands,” but going after low-hanging fruit — “easy for us to do on our own,” Ögelman said — has resulted in staff falling further behind in solving the problem.

“We would like to engage stakeholders in an organized basis,” Ögelman said. “When I look at the solutions before us, they all have some drawbacks. I’m not seeing some perfect, low-cost solution without adverse effects.”

TAC Approves 7 Changes, Tables 8

The TAC’s unanimously approved consent agenda resulted in the approval of four NPRRs, a system change request and single revisions to the Planning Guide and Settlement Metering Operating Guide. Eight other change requests were tabled while they wait on their related NPRRs.

NPRR1028: requires qualified scheduling entities to notify ERCOT of physical limitations on their resources’ starting ability that are not modeled in the reliability unit commitment software and excuses compliance with parts of RUC dispatch instructions that violate a notified resource’s physical limitations. The NPRR also establishes a requirement that ERCOT extend a RUC commitment to honor a resource’s minimum run-time limitation when a physical limitation delays its ability to reach its low sustained limit.

NPRR1031: requires ERCOT to post operations messages informing market participants when load is curtailed because of a transmission problem.
NPRR1032: limits the DC tie schedules used in RUC optimization and settlements to the ties’ physical rating.
NPRR1041: adjusts the expiration of the protected information status of wholesale storage load data from 180 days to 60 days, aligning the disclosure of real power consumption and metered generation output to 60 days after each operating day.
PGRR023: adds a requirement that transmission service providers submit and annually review a list of contingencies for their portion of the system, ensuring that the appropriate contingencies are submitted for ERCOT and NERC planning criteria.
SCR812: creates an Intermittent Renewable Generation Integration report similar to wind and solar power production integration reports.
SMOGRR0 23: provides an option for a professional engineer’s nameplate certification of newly installed or replaced instrument transformers when nameplate photos cannot be physically accessed, and replaces a list of instrument transformer nameplate data requirements by referencing Institute of Electrical and Electronics Engineers standards.

November 3, 2020

Entergy, in Eye of the Storms, Beats Expectations

Entergy held its third-quarter earnings call with financial analysts Wednesday as yet another hurricane, the fifth to hit Louisiana this season, bore down on the state.

entergy

“We’ve activated our storm response plan, and we are fully prepared and ready to respond,” Entergy CEO Leo Denault told analysts. “We’ve had a record-breaking storm season with back-to-back hurricanes hitting our service area. Yet no matter what 2020 threw at us, we remain steadfast in delivering on our commitments to our customers, our communities, our employees and our owners.”

Hurricane Zeta made landfall later that evening, ripping through Entergy’s New Orleans hometown with 110 mph winds. The most powerful hurricane to hit the U.S. this late in the year since 1899, Zeta knocked out power to more than 480,000 customers. By Friday morning, 327,000 were still without service, with some facing prospects of a full week without power.

Zeta followed Laura in August and Delta in October, both of which caused significant damage west of New Orleans. Aided by mutual assistance partners, Entergy deployed 12,000 workers after Delta to restore most of the nearly 500,000 outages in five days.

“We showed why we are best-in-class in storm response as we successfully managed to back-to-back major hurricanes all amid a global pandemic. That’s what we prepare for, and that’s what we do,” Denault said. “We can control what we can control. We can’t control the public health crisis, so we’re going to control what we can control.”

Entergy reported third-quarter earnings of $521 million ($2.59/share), as compared to 2019’s third quarter of $365 million ($1.82/share). That exceeded analysts’ expectations of $2.42/share, according to Zacks Information Research.

Denault said the results “amid these extraordinary times” demonstrated Entergy’s progress in building a “simpler, stronger and more resilient company.”

Entergy’s share price lost traction during the week, as did the rest of the broader market. Shares closed Friday at $101.22, down 5.8% following the earnings announcement.

November 3, 2020

FERC Accepts $430K AECI Settlement

FERC last week approved a settlement between SERC Reliability and Associated Electric Cooperative Inc. (AECI) for violations of NERC reliability standards. The ERO notified the commission of the settlement, which carries a penalty of $430,000, in a Notice of Penalty (NOP) on Sept. 30 (NP 20-22); FERC indicated in a notice Friday it would not review the NOP, letting the agreement stand.

The commission also accepted a settlement between an unnamed entity and its compliance enforcement authority for violations of NERC’s Critical Infrastructure Protection (CIP) standards. NERC’s NOP for the CIP violations, also filed Sept. 30 (NP20-23), follows the organization’s new policy of treating CIP noncompliance information as critical energy/electric infrastructure information (CEII) in its entirety. (See FERC, NERC to End CIP Violation Disclosures.)

Up to last month, NERC selectively redacted potential CEII from its filings to the commission. (See FERC Accepts WECC Violation Settlement.) In what is likely to be standard policy in such cases going forward, all information about the settlement — including the number, date and location of violations; the entities involved; mitigation actions; and penalties assessed — were included in a separate filing that is visible in the docket’s list but not accessible by the public.

Audit Uncovers Longstanding Issues

SERC’s settlement with AECI involves violations of a number of standards by the cooperative:

EOP-008-1 — Loss of control center functionality (two violations)
FAC-009-1 — Establish and communicate facility ratings
TOP-004-2 — Transmission operations
PER-003-0 — Operating personnel credentials
PER-005-1 — System personnel training

Per the terms of the agreement, AECI neither admitted nor denied the violations but did agree to the monetary penalty and additional mitigation and compliance activities.

The infringements of EOP-008-1 and FAC-009-1 were discovered during a compliance audit conducted from July to October 2016. However, the violations had been ongoing for several years at that point: since 2013 in the case of the EOP-008-1 violations, and 2007 for the FAC-009-01 issue.

AECI’s two infringements of EOP-008-1 concern requirements R1 — requiring reliability coordinators, balancing authorities and transmission operators (TOPs) to have a plan for meeting their obligations for reliable operation if their primary control centers are lost — and R4 — mandating BAs and TOPs have backup functionality for maintaining compliance with reliability standards during a loss of primary control center functionality. Both violations began on July 1, 2013, when the standard became enforceable.

As to the first requirement, SERC determined that the agreement between AECI and its six generation and transmission (G&T) cooperatives, which operate as regional dispatch centers (RDCs), did not require the creation of such a plan. The regional entity ruled the primary cause of the violation to be “management oversight” on the part of AECI leadership for “failing to ensure the implementation of an organizational model that reflected the [cooperatives’] role” in maintaining TOP functions.

A contributing cause was an “erroneous belief” by AECI’s management that backup plans were only required if all six G&Ts’ primary and backup control centers were lost. In reality, none of the G&Ts had a backup control center, meaning that a failure of even one primary center would put that cooperative out of action and potentially spark cascading failures. The lack of backup control centers was at the core of the R4 violation as well.

Both violations were found to pose a serious risk to the reliability of the bulk power system, as they could significantly lengthen response time in an emergency situation. AECI committed to a number of mitigating activities, primarily involving revisions to its rules for loss of RDC functions in the case of requirement R1 and requiring G&Ts to install backup facilities to fulfill requirement R4. The mitigation plans are expected to be fulfilled by the end of this year.

The FAC-009-1 violation was initially discovered at the same audit, when SERC determined that ratings for AECI’s solely and jointly owned facilities were not consistent with its stated facility ratings methodology (FRM). However, the full scope was not visible until SERC issued a request for information that required AECI to evaluate all transmission and generation facilities. At that point, the cooperative discovered that 101 of its 415 transmission facilities and eight of 25 generation facilities were incorrectly rated.

SERC assessed the violation as a moderate risk to the BPS; no harm is known to have occurred. In response to the violation, AECI rerated all transmission and generation facilities in accordance with its FRM, with all work completed by June 2019. Additional mitigation measures by the cooperative include revising its ratings application procedure, creating a new procedure for documenting asset database management processes and deploying new asset management software.

Relay Test Leads to Procedure Oversight

The remaining violations were submitted to SERC via self-report, with the TOP-004-2 infringement reported earliest of the three.

TOP-004-2 requires TOPs to “implement formal policies and procedures to provide for transmission reliability,” including switching transmission elements. AECI reported to SERC in March 2017 that one of its G&Ts had failed to follow the cooperative’s switching order procedure (SOP) following the inadvertent trip of a circuity breaker during relay testing at a substation. The operator at the G&T did not contact AECI prior to returning the breaker to service as required in the SOP.

SERC rated the violation as a moderate risk but noted that AECI had reported a similar incident of noncompliance with TOP-004-2 in 2015 (NP 16-21). “The underlying cause of the prior noncompliance was similar, and the mitigation for the prior noncompliance should have prevented [this] noncompliance,” the RE said.

AECI’s mitigation plan, submitted Sept. 13, 2019, includes semiannual training for all G&T relay technicians on the SOP, along with modifying system control software to remind operators to contact AECI prior to operating BPS elements.

Training, Certification Round out Violations

AECI’s report of its PER-003-0 violation, submitted on July 24, 2019, saw the cooperative acknowledge that personnel working in the RDCs operated by its G&Ts had failed to obtain valid NERC certificates as required by the standard. SERC also attributed this shortcoming to management oversight on the part of AECI, alleging that the cooperative’s agreement with its G&Ts did not fully account for the functions they were expected to perform. As a result, AECI did not realize that the responsibilities of the affected positions required staff that were fully certified by NERC.

SERC determined that this violation posed a serious risk to the reliability of the BPS, as did the violation of PER-005-1, under which AECI reported that it did not have a systematic approach for training system operators employed by its G&Ts. The utility committed to mitigation activities for the PER-003-0 violation, including the creation of a NERC certification and training task force and a program to ensure management and implementation of the standard.

AECI’s proposed certification and training task force is a factor in planned mitigation measures for PER-005-1 as well. In addition, the entity is also developing a list of company-specific reliability tasks for all G&Ts along with programs to verify the capabilities of personnel assigned to perform those tasks. Mitigation for the PER-005-1 infringement was reported complete earlier this year, while the PER-003-0 mitigation is expected to be finished by next June.

November 1, 2020

Overheard at ACE NY Fall Conference 2020

Actor and anti-fracking activist Mark Ruffalo and former EPA Administrator Gina McCarthy, now CEO of the Natural Resources Defense Council, headlined the Alliance for Clean Energy New York’s (ACE NY) annual Fall Conference Wednesday. Here are some highlights of what we heard.

Taking Action

In her keynote address, McCarthy said the climate battle being waged in the country is “a fight for our lives” and the future of the planet. She said people concerned with the environment need to raise their voices together to demand action.

The good news, McCarthy said, is that solutions exist to deal with climate issues, and one of the biggest answers to the problem is clean energy. She said the conversation around clean energy needs to continue and expand because initiatives are taking off at a greater pace at the state and local level because of the economic, health and quality of life benefits they provide.

McCarthy said she is particularly excited by the opportunities for the development of offshore wind on the East Coast, and a next step in the green energy revolution is to have federal leadership that will act on a national level.

“We need to turbo-charge the transition to clean energy nationwide,” McCarthy said. “And while there’s no substitute for federal leadership, there is no way that any of us are going to wait for Washington to wake up.”

ACE NY — Gina McCarthy, NRDC | © *RTO Insider*

With the current political climate, McCarthy said now is not the time to be “morose” or to sit and wait for things to happen regarding clean energy. She said there needs to be a “doubling-down effort” on building local and grassroots momentum across the country to “tip the scales” away from fossil fuels.

McCarthy said what has made New York a leader on climate initiatives was the passage of the Climate Leadership and Community Preservation Act (CLCPA) in July 2019. The CLCPA requires that 70% of electricity come from renewable resources by 2030 and that electricity generation be 100% carbon-free by 2040. Clean energy targets include deploying at least 9 GW of offshore wind energy by 2035, doubling distributed solar generation to 6 GW by 2025, deploying 3 GW of energy storage by 2030 and raising energy efficiency savings to 185 trillion BTU by 2025. (See Cuomo Sets New York’s Green Goals for 2020.)

The time for action and implementation of the CLCPA is now, putting it to work to transform the transportation sector and the power sector and modernize the electric grid, McCarthy said, adding that action on clean energy means many well paying jobs will be created.

“Progress is happening here, and if you can do it and show the way, then progress will happen all across the nation,” McCarthy said. “And it won’t matter if it’s red or purple or blue. Every state will want a piece of the action.”

Hulk Talk Green New York

Ruffalo, the award-winning actor and a resident of New York, said he’s been a longtime advocate for clean energy and addressing climate change as he spoke in a short video presented at the conference. He said ACE NY has been hard at work for years, helping the state adopt one of the most aggressive climate acts in the country.

The actor said ACE NY has embarked on an “ambitious” study of the transmission system to make sure it can handle all the renewable energy set to come online. He said the organization has played a leading role in making a clean energy future possible in the state and helping to reach the renewable energy generation goals laid out in the CLCPA.

New York has the chance to be “the greenest state in the nation,” Ruffalo said.

“Trust me, I know a little bit about going green — dad joke,” Ruffalo said, referencing his role as the Hulk in the Marvel Cinematic Universe franchise of superhero movies.

Building the Offshore Wind Industry in NY

In a discussion on building New York’s offshore wind industry, Nathanael Greene, senior renewable energy advocate for NRDC, called for “rigorous pre- and post-construction monitoring” to protect wildlife and fish habitats, which he said the Department of the Interior’s Bureau of Ocean Energy Management is not requiring.

“The data from good monitoring will tell us what needs to be protected and if the companies’ mitigation measures are working. Ultimately, it makes protections more cost effective,” he said. “But we can’t do pre-construction monitoring and develop baselines after the fact. We need developers to step up and include detailed monitoring plans in their [construction and operations plans] until BOEM starts requiring them.”

Greene also criticized FERC’s buyer-side mitigation requirements, saying they are undermining New York’s clean energy efforts. “And now some want to expand buyer-side management so that it’s statewide, which would make a bad policy terrible,” he said. “It’s time we took seriously the alternatives to the capacity market and take steps necessary so that New York voters, our elected and appointed officials determine our resource adequacy, not the fossil fuel agenda of ideologues at FERC. The makeup of FERC may change following the election, but until the feds catch up with New York’s climate leadership, we may have no choice but to take charge of our own power mix planning.”

Adrienne Downey, principal engineer for offshore wind for the New York State Energy Research and Development Authority, said New York’s pledge to build 9 GW of OSW, as well as the targets by neighboring states, have gotten the attention of Asian and European investors.

“We are seeding an incredible opportunity here. Right now, [for] the earliest projects, the lion’s share of jobs are clearly in the construction and installation phase [and] in the operations and maintenance phase, which is 25 years.

“We want to expand that to see manufacturing start to happen. So, what we would anticipate is we’ll start to see the components that are probably the most logistically flexible … so we might see towers [and] foundations. We’re anxious to start seeing deeper manufacturing come as we advance our target deeper toward 9 GW to things like blades. The holy grail would be full turbine assembly.”

Dominik Schwegmann, head of offshore development for RWE Renewables Americas, said manufacturing will only come to the U.S. “if the offtake for these components is there; if the market has the size; if the project pipeline … is predictable and reliable for the manufacturers to say, ‘Yes, I [will] invest [a] couple hundred million dollars and do investments in the training of the workforce. … The [U.S.] market has enough … potential to justify that, just as in Europe.”

Joe Martens, director of the New York Offshore Wind Alliance, noted that the U.S. hasn’t completed the permitting for any commercial-scale OSW yet.

“I think that once there is a clear signal from Washington, then I think we will see some significant investment in other components that right now are not manufactured in the U.S. come to the U.S. And that will be an exciting moment.”

YIMBYs

ACE NY named Win With Wind, a group of private citizens on the South Fork of Long Island, winner of its 2020 Clean Energy Advocate award.

Martens said the group, which seeks to generate grassroots support for and combat misinformation against offshore wind, is “motivated by their simple and sincere desire to see their communities in the forefront of clean energy leadership.”

“There is no place more vulnerable to climate change than Long Island,” he added. “Rising sea levels and ocean acidification, in particular, are a direct and immediate threat.”

Cate Rogers, a member of the group’s steering committee, accepted the award. Rogers said she and another activist, Judith Hope, started the group in 2018 to counter disinformation on the South Fork Wind Farm, a 15-turbine project that Ørsted will build wind 35 miles off Montauk.

After organizing the group, Rogers said, she learned “that an overwhelming majority of people in our community supported the project and the transition to renewable energy. They just needed to be given the facts, have some questions answered and understand that we have shovel-ready solutions at hand. … But without a place to gather, a group with which to connect, they could remain the silent majority and, even worse, fall victim to misinformation and scare tactics and take up the mantra we often hear: ‘I support renewable energy, but not this project.’”

After the award presentation, ACE heard from Betta Broad, director of New Yorkers for Clean Power, which supports electrification and renewable generation. Broad said the group’s goal is “creating more YIMBYs — that’s ‘Yes, in my backyard.’”

November 1, 2020

Study: Storage Can Replace 53% of LIPA Peakers by 2030

The Long Island Power Authority (LIPA) could replace more than half of its aging and rarely used fossil-fueled peaker plants with energy storage by 2030, saving ratepayers almost $400 million, according to a study released last week.

The report by consulting firm Strategen, prepared for the New York Battery and Energy Storage Technology Consortium (NY-BEST), said “it is feasible and cost-effective” to replace 1,116 MW of peakers by 2023 and more than 2,300 MW by 2030. It said LIPA frequently dispatches the 4,357 MW of peaker units on the island uneconomically and for reasons other than meeting peak-load needs.

In addition to saving customers more than $390 million in net present value over the next 10 years — about $360 per household — the study says swapping peakers with batteries would significantly reduce harmful air pollutants.

“The whole framing of this is that New York has the goal of getting to zero emissions by 2040 … so we need to start on that path with what we can do now,” Edward Burgess, lead author of the study and a senior director at Strategen, told RTO Insider.

Strategen, based in Berkeley, Calif., estimates that the peaker fleet is costing Long Island ratepayers approximately $473 million annually just for capacity — three times the market rate for capacity resources cleared through NYISO’s competitive markets — and that if it is not replaced, the cost could increase to $716 million by 2030. (The study identifies as peakers those plants with an annual capacity factor of 15% or less; it says about 3,053 MW of the capacity operated 10% or less of the time, while 36 units (1,249 MW) ran less than 1% of the time in 2019.)

A 15-year power service agreement (PSA) between LIPA and National Grid that runs to 2028 accounts for the bulk of these costs. The PSA is for 3,634 MW, 90% of which are for peaking plants.

LIPA spokeswoman Jen Hayen told RTO Insider that LIPA will be issuing a request for storage proposals in the next several months that may result in the replacement of certain Long Island peaker or steam plants and will evaluate the proposals it receives compared to the costs of the existing units.

“LIPA has already announced the retirement of 68 MW of peaker plants in 2020 and 2021 and has an ongoing study for the retirement of an additional 400 to 600 MW of steam and peaker plants in 2022. We anticipate additional retirements in 2024 and beyond,” Hayen said.

She challenged the study’s savings estimates, saying they “are higher than we have experienced in either deploying storage or retiring existing plants.”

“In classifying low-usage steam plants as ‘peaking plants,’ the study overstates the potential savings in fixed costs, much of which are prior capital costs that must be paid to the plant owner at the time of retirement,” Hayen said. “Moreover, the study assumes that future storage discharge requirements can be determined from past peaker operation, which does not reflect the significant system changes that will be occurring.”

Uneconomic Dispatch?

The study’s claim that the peakers are frequently dispatched when they are not economic is based on the 2019 NYISO State of the Market report by the ISO’s Market Monitoring Unit, Potomac Economics. It said out-of-merit “dispatch was frequently used to manage 69-kV constraints and voltage constraints (i.e., transient voltage recovery requirement on the East End of Long Island).”

In addition to using peakers to resolve local transmission problems, LIPA generally does not coordinate their dispatch with NYISO, so the actions are not optimized through the ISO’s day-ahead and real-time market software, the study said. The result is often depressed locational-based marginal prices that send inaccurate price signals for potential future investment and require millions of dollars in uplift charges.

“The proportion of hours where out-of-merit actions were taken to resolve congestion issues (versus times when the market was used to resolve these) were quite significant throughout Long Island and are more pronounced in certain locations,” the study said. “For example, in the Brentwood area, 99% of congested hours in 2019 were managed through out-of-merit actions rather than through the [day-ahead] and [real time] markets.”

The MMU’s 2019 report also noted that NYISO has said that issues frequently arise because of lack of coordination between the ISO and LIPA regarding the scheduling of phase angle regulators to manage congestion. Under state law, LIPA is generally exempt from the New York Public Service Commission’s jurisdiction.

An Evolving Grid

The study notes that the percentage of the peaker fleet on Long Island (Zone K) needed to meet peaking needs has declined in recent years, from 71% in 2016, to 67% in 2017 and 64% in 2018. Whether that decline continues, Burgess said, will depend not only on the peakers, “but also [on] what’s happening on the load side.”

“On the one hand, maybe we have increasing demand from electrification, but on the other hand, maybe there’s more distributed solar or energy efficiency,” he said.

Other generation on the system is also a factor, he continued. “Are we using more of the recently installed combined cycle units because gas is cheap? That certainly would be an interesting thing to look into further and see how those trends have gone over a longer period of time,” Burgess said.

The state’s Climate Leadership and Community Protection Act (CLCPA) calls for at least 9 GW of offshore wind energy by 2035, and 6 GW of that will likely interconnect onto Long Island by 2030. The CLCPA also targets 6 GW of distributed solar generation by 2025, 3 GW of energy storage by 2030 and raising energy efficiency savings to 185 trillion BTU by 2025.

The study mentions that the iconic Ravenswood peaker plant on the East River in New York City is being converted to a 318-MW energy storage facility.

Asked why such conversions aren’t happening on Long Island, Burgess said, “Definitely there’s a need for local generation capacity in New York City [Zone J]. There’s also a need for generation on Long Island too. I believe part of the rationale for that is that [at Ravenswood], we have a site with an interconnection and it’s all ready to go, and New York City is even more constrained in that sense than Long Island is.”

One of the values of storage is its ability to perform functions in addition to substituting for generation, he noted. “Storage can also be a load; it can absorb energy,” Burgess said. “Perhaps down the road when we have a lot more renewables on the system that’s going to be a necessary function too, if you have oversupply of wind or solar at a certain time. And there’s all the different ancillary services it could provide too: balancing functions [and] ramping up and down in very quick succession.”

Of the 2,300 MW of fossil peaker plant replacements, 334 MW could be retired and replaced immediately, and in the East End of Long Island, there is a near-term opportunity for up to 90 MW of fossil peakers to be displaced with storage, the study said.

Burgess said some peakers will likely retire because of the state Department of Environmental Conservation’s (DEC) regulation limiting nitrogen oxides (NOx) emissions from simple cycle combustion turbines. The department required all impacted plant owners to file compliance plans by March 2, 2020. The phased approach goes into effect May 1, 2023, and limits emissions to 100 ppm, dropping two years later to 25 ppm for units using gaseous fuels and 42 ppm for units burning liquid fuels. (See NY DEC Kicks off Peaker Emissions Limits Hearings.)

Because of “the NOx regulations that the DEC put out … some of these plants without the pollution controls will have to either be making retrofits or retiring,” Burgess said. “We’ve also got decisions that LIPA is going to have to make around contracts and the current power supply agreement that they have with National Grid. … There are provisions that would allow them to ramp down a portion of that.

“And there are a lot of inefficiencies that we’re seeing here in how some of these plants are being operated. There are some economic benefits to be gained, so that’s another driving factor, along with the environmental,” he said.

Replacing peakers with storage will eliminate 2.65 million metric tons of CO2, 1,910 tons of NOx and 639 tons of SO2 of emissions annually, resulting in societal benefits of $163 million annually through fewer pollution-related deaths and hospital visits, according to the study.

November 1, 2020February 12, 2025

NYISO Reviews Fuel Security, Mitigation Project

NYISO told stakeholders last week that its fuel and energy security (FES) metrics remain “well aligned” with the assumptions of Analysis Group’s November 2019 study, which concluded that the state’s grid is “currently well equipped to maintain reliability in the winter, even under adverse winter system conditions.”

Although the report concluded “only fairly severe and relatively low probability conditions or events would create meaningful reliability challenges,” it said the ISO should continue monitoring because of the transition of its resource fleet and the increasing reliance on natural gas and renewables.

In April, NYISO pledged to update the metrics at least twice a year and said the study will be “refreshed” if the ISO observes large deviations between actual conditions and the conditions assessed in the study. A refresh also could result from large differences between the study’s assumptions and actual conditions that could adversely affect reliability. (See NYISO Launches Fuel Security Effort.)

An example of enhanced monitoring tools shows stored energy and required storage draw and margin (MWh). | NYISO

The ISO uses 23 metrics to monitor fuel security, including the deployment of new renewable and clean energy resources; the impact of the state Department of Environmental Conservation peaker rule; gas-only generator outages because of lack of fuel; and the status of transmission upgrades such as the AC Transmission Projects and Western NY Public Policy Transmission Need.

“We were aiming to enhance monitoring by adding some elements related to fuel security to both the Winter Capacity Assessment and the cold-weather operations presentations, those occurring in the fall and the spring,” market design specialist Amanda Myott told the Installed Capacity/Market Issues Working Group.

The ISO also is working to improve the accuracy of its generator fuel and emissions reporting (GFER) surveys, which inform internal FES assessments.

The fuel security monitoring “is focused on severe cold-weather conditions and being able to meet winter peaks in those conditions,” Vice President of Operations Wes Yeomans said.

On compensating for the intermittency of renewable resources, Yeomans said, “At other times of the year, we might have a duration of low wind or clouds; we are certainly aware of that and have other processes we’re trying to enhance with market designs and even some good work setting up the [installed reserve margin] with” the New York State Reliability Council.

In response to a recommendation that the ISO consider comparing actual conditions and operating experience to the conditions assumed in the FES study, Yeomans noted that winter 2019/20 was “extremely mild.”

“But if there is a cold snap this upcoming winter, it will be very important to look at what we assumed about gas availability for the generator fleet and the actual availability experienced,” he added.

CMR Project Treads Water

NYISO is pausing its Comprehensive Mitigation Review (CMR) project until it receives further clarity from FERC, which rejected the ISO’s proposal to make it easier for public policy resources to clear its capacity market, Michael DeSocio, director for market design, said in an update.

The project’s objective is to modify the capacity market framework while preserving competitive signals and facilitating the state’s ambitious clean energy goals. CMR efforts this year included the ISO’s proposed renewable exemption limit and changes to the Part A test for exempting resources from market mitigation.

In July, FERC approved the renewable exemption limit formula for calculating a megawatt cap of renewable resources exempt from buyer-side market power mitigation (BSM) specific to each mitigated zone. (See NYISO BSM Mitigation Ruling Sparks Glick Rebuke.)

NYISO’s buyer-side mitigation rules cover New York City and zones G-I. | NYISO

But the commission rejected the Part A changes on Sept. 4, prompting a dissent from Commissioner Richard Glick and an Oct. 5 rehearing request by the ISO (ER20-1718-002). (See FERC Rejects NYISO Bid to Aid Public Policy Resources.) Rehearing requests were also filed by Equinox, New York Transmission Owners and jointly by the New York State Energy Research and Development Authority and Public Service Commission.

“The ISO still thinks that the proposal is an excellent one that makes a whole lot of sense,” DeSocio said. “FERC unfortunately didn’t see it exactly the same way.”

The ISO’s BSM rules require new ICAP resources in New York City and zones G-I to offer at or above the default offer floor. To win an exemption from mitigation, a new entrant must pass one of two exemption tests. Part A allows exemptions if the forecast of capacity prices in the first year of a new entrant’s operation is higher than the default offer floor. Part B permits exemptions if the forecast of capacity prices in the first three years of a new entrant’s operation is higher than its net cost of new entry (CONE).

DeSocio said ISO officials are considering a suite of options, the first being contractual models such as CAISO’s, with an energy-only market and fixed resource requirement.

The second option is enhancements to the capacity market such as to BSM, available capacity transfers and a future clean capacity requirement. The third option is a redesign of the capacity market, with possibilities such as a “multiple value pricing” model that co-optimizes over several variables (e.g. specific to resource type, zero-carbon resources, etc.) and a Forward Clean Energy Market to procure a certain percentage of generation from qualifying renewable resources.

The combination of the renewable exemption limit and the BSM proposals addressed many of the concepts being considered in the proposal for available capacity transfer (ACT) — expanding the use of the renewable exemption bank — and CRIS+, the pairing of transferable capacity resource interconnection service (CRIS) rights with an existing resource’s BSM exemption.

“We’re recommending to put [ACT and CRIS+] on the shelf until we get clarity on the Part A revisions that we filed earlier this year,” DeSocio said.

In the meantime, the ISO wants stakeholder feedback on capacity market changes and any other ideas before moving into 2021, he said.

“As we add more renewable resources and more limited-duration resources in the future, that will change how we approach reliability, and that does have an impact on the role of the capacity market,” DeSocio said.

The ISO will likely be more focused on BSM and how that impacts state policies and the design of the capacity market, and how the capacity market supports resource adequacy, he said.

“It’s a broad conversation, and if folks have ideas on how to structure that, I would certainly be willing to listen, because these markets are pretty complex, and as you tug on one area, it affects another area,” DeSocio said.

November 1, 2020

FERC OKs More Rigorous MISO Capacity Requirements

Conventional capacity resources in MISO will now have to prove full deliverability before collecting maximum capacity credits, FERC said last week.

The commission on Oct. 27 approved the RTO’s proposal to require capacity resources to demonstrate deliverability through firm transmission service up to installed capacity (ICAP) levels before they can convert their entire unforced capacity (UCAP) into zonal resource credits (ER20-1942).

MISO said procuring firm transmission remains optional for capacity resources, provided that they are comfortable with settling for fewer capacity credits based on their partial ability to deliver. The RTO said it plans to prorate credits. Staff have previously acknowledged that it may be expensive for some resources to secure firm transmission service up to their installed capacity levels.

The RTO used to allow capacity resources to demonstrate full deliverability based on UCAP levels — something its Independent Market Monitor has long called inconsistent with the assumptions used in the grid operator’s loss-of-load expectation (LOLE) study, which assumes that all capacity resources are fully deliverable.

Before, MISO’s Tariff required capacity resources to demonstrate capacity deliverability by having network resource interconnection service, which stipulates that the entire ICAP of the resources must be deliverable. However, the Tariff also allowed resources to demonstrate deliverability by securing energy resource interconnection service and procuring firm transmission service up to their UCAP levels, which tend to be about 5 to 10% below full ICAP levels.

FERC agreed that the second option needed to be eliminated for the sake of reliability and accurate reserve margins.

“MISO has demonstrated a disparity between its LOLE study assumptions and the deliverability requirements associated with conventional capacity resources used to satisfy MISO’s reserve requirements,” the commission said. “As MISO explains, the LOLE analysis, and therefore the resultant reserve margin and reserve requirements, assumes that a conventional capacity resource can deliver its full installed capacity level of output when it is online. Therefore, we find reasonable MISO’s proposal to require all conventional capacity resources that seek to participate in MISO’s resource adequacy construct at their full unforced capacity levels to demonstrate deliverability up to their installed capacity levels. In doing so, MISO’s proposal will provide certainty that MISO’s reserve requirements are satisfied by fully deliverable planning resources, thereby ensuring that MISO meets its reliability needs.”

November 1, 2020

NYISO Management Committee Briefs: Oct. 28, 2020

The NYISO Management Committee on Wednesday endorsed a technical fix to the 2017-2021 capacity demand curve reset (DCR) to address an error in the model used to estimate net energy and ancillary services (EAS) revenues for the hypothetical peaking plant.

The problem resulted from a misalignment of natural gas prices. The model assumed that index prices published by S&P Global represented the “trade day” — the day before generators take delivery and use the gas to produce electricity. In fact, the data actually represent the “flow day” prices.

The error was discovered during work on the net EAS model for the 2021-2025 DCR, and the change will apply to that period as well. (See NYISO Management Committee Briefs: Sept. 23, 2020.)

NYISO already submitted the change to FERC, which approved it on Oct. 22 (ER21-130). “We have implemented the revised reference prices into the capacity market [and] spot market auctions,” Vice President of Market Operations Robb Pike said.

Pike said the ISO would submit an informational filing to FERC to provide notice of the MC’s concurrence with the previously filed revisions.

The 2017-2021 DCR includes the capacity demand curves for the 2017/18 through 2020/21 capability years (May 1, 2017, through April 30, 2021).

2020 Reliability Needs Assessment OK’d

The MC unanimously approved the 2020 Reliability Needs Assessment (RNA), which cut the peak load forecasts for 2020-2028 by as much as 467 MW from the 2018 RNA. If the Board of Directors approves the revisions in November, NYISO will file the changes with FERC.

Laura Popa, manager of resource planning, presented the 2020 RNA, which examines needs over the coming 10 years. The presentation included a transmission analysis supplied by Keith Burrell, manager of transmission studies.

Pallas LeeVanSchaick of Potomac Economics, the ISO’s Market Monitoring Unit, presented comments on the RNA and said the MMU found a number of areas where the reliability needs identified by the RNA are in part driven by gaps in the market design, where it fails to provide incentives for resources.

Some key findings that the MMU focused on included a number of base case transmission violations from 2024 to 2030 in New York City driven by impending peaker retirements and load growth, he said. The state Department of Environmental Conservation last year adopted a regulation to limit nitrogen oxides (NOx) emissions from simple cycle combustion turbines, or peaking units, and required all impacted plant owners to file compliance plans by March 2. (See NY DEC Kicks off Peaker Emissions Limits Hearings.)

The RNA found transmission security violations on Consolidated Edison’s non-bulk power transmission facilities system in the Astoria East/Corona as well as Greenwood/Fox Hills load pockets, rising to 180 MW in 2030 for the former and 370 MW for the latter.

It “also found transmission security violations on Con Edison’s bulk system, and the deficiency there rises to 1,075 MW by 2030,” LeeVanSchaick said. “[The RNA] also found resource adequacy violations beginning in 2027, but it’s notable that the compensatory megawatts needed to resolve those are much lower than for the transmission security violations … being only 350 MW by 2030.”

The two significant takeaways are Astoria East/Corona and Greenwood/Fox Hills, as well as the “big difference” between the compensatory megawatts needed in the transmission security analysis versus those in the resource adequacy analysis, he said.

“This RNA reveals a number of ways in which the NYISO market design fails to reflect the value of resources that help satisfy transmission security needs, which may lead to [reliability-must-run] contracts and other regulated transmission investment. The first recommendation that would help to align market signals with the reliability value of resources is better reserve market pricing in New York City,” LeeVanSchaick said.

The second issue is lining up the capacity accreditation with the reliability value of resources in NYISO planning studies, particularly for the large units and special-case resources, LeeVanSchaick said. Finally, the RNA is another piece of information that supports enhancing locational capacity pricing with the “C-LMP” framework, which would allow the ISO to set different prices for different areas and, in turn, for more cost-effective capacity to meet reliability needs, he said.

“If you do those things, it’s much less likely that you’d have to make any further out-of-market investment,” LeeVanSchaick said.

NYISO will seek updates to local transmission owner plans and other resource and load changes in December and determine in January whether the needs should be adjusted and solutions solicited to the remaining needs.

2021 Budget Approved

The MC also approved a draft budget for 2021, which will go before the board for final approval in November.

Alan Ackerman of Customized Energy Solutions, chair of the Budget and Priorities Working Group, presented the draft budget, which was unchanged from the draft stakeholders reviewed last month.

For the second year in a row, NYISO is proposing a decrease to the budgeted revenue requirement, with the draft budget allocating $167.4 million across a forecast of 147.3 million MWh, for a Rate Schedule 1 charge of $1.137/MWh, down from the 2020 budget of $168 million allocated across 154.3 million MWh ($1.089/MWh).

Wentlent Elected 2021 Vice Chair

The MC elected Christ Wentlent to serve as its vice chair for 2021, beginning in December.

Wentlent represents the Municipal Electric Utilities Association and New York Municipal Power Agency as liaison to both NYISO and the New York State Reliability Council.

He was unable to attend the meeting, but he sent a message read by Chair Jane Quin. “We all know our energy market is at a major transition point, and I would be honored to assist the NYISO and its stakeholders with that transition,” he said.

November 1, 2020

MISO, SPP Heads Present Unified Front on Seams

The heads of MISO and SPP stood on common ground to discuss seams issues during last week’s Organization of MISO States’ annual meeting.

The CEOs’ unified front during the virtual conference Thursday was a striking change from the executives’ past reticence on seams matters.

MISO CEO John Bear acknowledged that both RTOs are “struggling” with their renewables-packed interconnection queues.

“We’ve really built our systems out from our footprint perspective,” he said, explaining that MISO and SPP have developed renewable generation near the seams, sometimes disregarding the congestion the projects can cause on each other’s systems. He said in some cases, seams congestion has been neglected to the point that an interconnecting generator is “looking over a cliff” of interconnection expenses.

Bear said he and SPP CEO Barbara Sugg agreed that they needed to perform studies on the most congested areas.

The RTOs announced in September that they will partner on a special study focused on transmission projects that can bring more of the interconnection queues’ renewable generation online. (See MISO, SPP to Conduct Targeted Transmission Study.)

“Look, we’re fighting the same battles,” Sugg said. “And I think the only way you’re going to get a little is to give a little. We’re 100% confident we’re going to produce some really good results. We do share some of the very same pain points.”

MISO SPP seams — MISO CEO John Bear | *OMS*

Sugg said cost-allocation discussions are not atop the agenda as the RTOs probe possible cross-border interconnection solutions.

“If somebody wants to talk to us about cost allocation in April, we won’t talk about it,” Sugg said, noting that it’s important to keep potential bickering over costs out of an initial search for helpful projects.

“Look, we’re going to have our differences in the future, but I think we’ll be able to keep it out of FERC. I’m optimistic,” she said.

Bear said that MISO-SPP relations have improved by “assuming noble intent on the other side” and having empathy for each other’s challenges.

“At the end of the day, we are businesses competing with each other, but there’s value in being partners,” Sugg said.

Bear said seams management has long been MISO’s modus operandi. When it began its energy market in 2004, MISO had to accommodate PJM member Commonwealth Edison in Chicago, which became an island within MISO’s footprint.

“We’ve had to learn about seams very fast and furiously,” he said.

Sugg said that as the two RTOs expand their footprints, seams arrangements must adjust with every new membership.

“Growth is a fantastic thing … but it definitely makes the seams discussions continue to evolve. It definitely is an ongoing challenge, but one that is worth every minute of effort,” she said. There’s a better appreciation today among regulators of the energy markets’ complexity, she continued.

Sugg said wind is poised to beat out coal this year as SPP’s most used fuel source, a milestone that will come earlier than expected.

“There are so many wind-rich areas in SPP and such clamoring … for energy produced from a renewable source,” she said, noting a “robust transmission system” will be necessary to support the demand for renewables.

Bear said MISO’s own ballooning renewable portfolio has prompted a rethink of its current resource adequacy construct that focuses on a summer peak. Bear said the RTO has a significant loss-of-load risk in some hours in shoulder periods.

“[It’s] so we don’t kid ourselves that we’re reliable in every season, even though some hours might go unserved,” he said.

Sugg predicted FERC Order 2222 — which directs RTOs and ISOs to develop participation models for distributed energy resource aggregations — will have a “humungous” effect on grid operators. (See FERC Opens RTO Markets to DER Aggregation.)

“It’s going to have tremendous impact on us and change what enters the market,” she said.

November 1, 2020

DTE Energy to Cleave Pipeline Business

DTE Energy backed away from its pipeline business last week, announcing that it will spin off its non-utility natural gas pipeline, gathering and storage business.

The transaction will have the company shedding DTE Midstream and becoming a pure-play electric and natural gas utility. Midstream is set to carve out its own Detroit headquarters and become an independent and publicly traded company by mid-2021. DTE shareholders will retain their shares and receive pro rata shares of the new Midstream company.

DTE said the move will not negatively affect rates, customers or utility operations. CEO Jerry Norcia said the Midstream spinoff announcement “follows a thorough review with our board to identify opportunities to optimize our portfolio and maximize shareholder value.”

“We recognize that this comes not long after our significant acquisition of assets in the Haynesville [Shale] basin,” Norcia said during the company’s third-quarter earnings call Oct. 27. “Through 2019, while business mix discussions were still ongoing, we continued to pursue an aggressive value creation agenda for Midstream, which yielded the Haynesville acquisition. … Because this acquisition and the balance of the Midstream portfolio continues to perform exceedingly well … and thrive on its own, it crystallized our path to pivot to a high growth pure-play utility with the spin of a well run Midstream company. We believe this strategy will unlock significant value for our shareholders.”

Current Midstream President and COO David Slater is set to become CEO of the standalone company.

After the Midstream transaction, DTE will receive about 90% of its operating earnings from its core utility business versus the 70% it receives today.

Midstream owns approximately 2,350 miles of pipeline and operates 91 Bcf of gas storage capacity. DTE acquired most of the network in $1.3 billion and $2.5 billion transactions in 2016 and 2019 respectively. When the deal is complete DTE estimates it will generate 90% of its operating earnings from its utility business versus the current 70% operating earnings from its core utility.

“As most of you know, my background includes a substantial amount of time in the gas industry, including my involvement in development of our Midstream business. The team and I have dedicated a significant amount of time and energy creating a Midstream business at DTE that is recognized as one of the best in the country. So, you can imagine how important this decision is to our team and me. After careful consideration and review with our board, I am confident that the separation is the best way to allow the Midstream business and its team to achieve their full potential and to enhance overall value for our shareholders,” Norcia said.

DTE estimates Midstream will earn $700 million before taxes in 2020.

The company reported third-quarter earnings of $476 million ($2.46/share), compared with $319 million ($1.73/share) in 2019. It said earnings were up because of higher year-over-year residential sales, higher rates and warmer weather. The earnings report represents a turnaround from first-quarter earnings, when DTE contemplated shaving millions from operations and maintenance expenses to offset drooping sales. (See DTE to Cut Spending in Response to Pandemic.)

“I want to thank all the leaders and our 10,000 employees of DTE for creating this tremendous success in a year of great turmoil and uncertainty,” Norcia said. “We are firing on all cylinders, keeping our people safe and delivering for our customers, communities and investors. It is truly remarkable and certainly a reflection of the grit and determination of the great people of DTE.”

Norcia said DTE plans to invest about $14 billion in its electric utility over the next five years, some of that in renewable generation. He noted DTE’s goal of achieving net-zero carbon emissions by 2050. For that to happen, he said DTE needs to double renewable capacity by 2024 and quadruple it by 2040.