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March 3, 2020March 12, 2025

PJM Stakeholders Get First Look at MOPR Floor Costs

By Rich Heidorn Jr.

PJM stakeholders on Friday got their first look at the price floors that could be applied for capacity resources under the expanded minimum offer price rule (MOPR).

PJM shared what it called “informational” net cost of new entry (CONE) values, while The Brattle Group, which was hired by the RTO, gave a presentation on its work to develop avoidable-cost rate (ACR) values, the default minimum price for existing units.

The MOPR previously covered only new natural gas-fired generators. Under Consumer Advocates Appeal MOPR Order to DC Circuit.)

The Brattle Group’s preliminary gross avoidable-cost rate (ACR) for existing generating resources, showing low, high and “representative” costs ($/MW-day) | The Brattle Group

PJM’s informational net CONE numbers range from a low of $235/MW-day for a combined cycle plant to a high of $3,261/MW-day for offshore wind.

PJM’s Gary Helm said the RTO was terming the net CONE values “informational” because they include “placeholder” energy and ancillary services (E&AS) offsets from a 2018 FERC filing. “We feel pretty good” about the gross CONE values, he said.

Brattle’s preliminary gross ACRs for “representative” plants ranged from a low of $40/MW-day for solar PV to $892/MW-day for a single-unit nuclear plant (using 2022 dollars).

PJM’s capacity prices have never exceeded $245/MW-day, a peak set in the EMAAC region for delivery years 2013/14. The RTO’s most recent Base Residual Auction, held in 2018, saw a top price of $204/MW-day in the PSE&G zone.

Resources seeking to offer below the net ACR or net CONE values would have to seek a unit-specific exemption.

Both PJM and Brattle representatives emphasized during the special meeting of the Market Implementation Committee that their numbers were preliminary and would be refined before the RTO makes its compliance filing, due March 18.

Energy & Ancillary Services Offset

PJM’s Pat Bruno began the session with a presentation on the differences between the use of forward-looking and historical E&AS revenues. The E&AS will be subtracted from generators’ going-forward costs to determine unit-specific net ACRs.

The RTO and its Independent Market Monitor currently calculate unit-specific offer caps with a simple average of net E&AS revenues from the three most recent calendar years.

PJM’s preliminary net cost of new entry (CONE) values, including energy and ancillary service (E&AS) revenue offset | PJM

Bruno said PJM intends to allow use of both historical and forward-looking E&AS revenues in determining MOPR offer floors for both new and existing units, consistent with its previous policy on new units.

He acknowledged this could result in an existing unit’s net ACR floor price being above its net ACR offer cap. In such cases, he said, the seller will be required to offer at the floor price.

Becky Robinson of Vistra Energy said the possibility of the floor price exceeding the price cap “is creating a dartboard for people to criticize the justness and reasonableness” of MOPR floor prices. But she said it was unlikely to happen. “Why would anyone use forward-looking [prices] if it would make their MOPR floor price higher?”

‘Irrational’ FERC Ruling on Maintenance

Monitor Joe Bowring gave a short presentation on the IMM’s ACR template and discussed the development of E&AS offsets, including the treatment of major maintenance.

Bowring cited what he called the “unintended consequences” resulting from an April 2019 FERC order requiring that major maintenance costs be allowed in energy offers and no longer included in net ACR calculations (ER19 –210). Bowring said the “irrational definition of major maintenance” was made at PJM’s request and over the IMM’s objection. (See FERC to PJM: Clarify Allowable Costs for Energy Offers.)

“The FERC decision removed major maintenance from gross ACR, which would reduce net ACR if nothing else changed. Historical net revenues should not be reduced after the fact by subtracting major maintenance as PJM and Brattle propose. That would effectively mean that ACR was not reduced. Price-based offers were used in the calculation of historical net revenues. If participants wanted to include major maintenance in their energy offers, they would have done so,” Bowring explained after the meeting. “Similarly, for going-forward net revenues, there is no reason to assume that participants will include major maintenance in their energy offers. We have seen no evidence that they do.”

Reducing net revenue to reflect major maintenance would improperly assume that all generators include 100% of their maintenance costs in their offers, Bowring said. “We didn’t see any bump [in prices] after the FERC order. Forwards didn’t really change.”

“Arbitrarily adding major maintenance costs to energy offers will inappropriately reduce net revenues and increase net ACRs,” he added.

Bob O’Connell of Panda Power Funds said FERC’s policy might cause units to run even when LMPs are below their operating costs just to minimize maintenance expenses from start-ups, citing a “rule of thumb” that one start is equal to 20 base hours. That, he said, could suppress energy prices in off-peak hours.

Bowring said O’Connell’s scenario seemed logical but that there was no way for the Monitor to quantify such behavior in unit-specific ACR calculations.

“We put a list of items that shouldn’t be included in major maintenance in our filing, and FERC copy and pasted it in the definition of what should be” included, Bowring said.

‘Representative’ Resources

Brattle’s Michael Hagerty presented the consulting firm’s preliminary default ACR values.

Michael Hagerty, Brattle | The Brattle Group

The group listed costs it considered most representative of each technology along with “representative low” and “representative high” costs to provide a range PJM could consider in its filing. “Not the lowest of the low and the highest of the high,” Hagerty said.

The selection of the “representative” plant for each technology was based on several characteristics, including the distribution of plants by age, state, capacity and — for fuel-burning resources — post-combustion controls.

Hagerty said the firm identified the primary factors affecting cost across fleets and compared publicly available costs with those in a confidential generation project database from design firm Sargent & Lundy.

The “very significant range of plants within each technology … creates a bit of a challenge,” he said. “Our intent was to show what we see in the existing fleet and leave it to PJM to determine where they want to be on this scale.”

PJM Vice President of Market Services Adam Keech said it was too soon to say “what [costs] we think is reasonable.”

“We’re still digesting the data ourselves,” he added.

Brattle noted that its gross ACR values for nuclear units are about 12% lower than the Monitor’s largely because of lower capital cost assumptions and because it estimated that about $1/MWh of operations and maintenance costs should be accounted for in the estimate of net E&AS revenues. Bowring said the $1 reduction was inconsistent with the FERC order on maintenance.

Exelon’s Jason Barker said the Monitor’s characterization of what constitutes variable operations and maintenance (VOM) costs are “illogical and wrong.” Barker indicated that the nuclear capital costs referenced in the Nuclear Energy Institute data, upon which Brattle and the Monitor have relied, are not the classes of costs described in the FERC order.

“It’s not our characterization. It was FERC’s,” Bowring responded.

Energy Efficiency

Brattle calculated a net CONE of $230/MW-day (ICAP) for energy efficiency based on analysis of EE programs of four utilities in PJM: American Electric Power, Baltimore Gas and Electric, Commonwealth Edison and PPL.

It noted its net CONE for PJM EE was higher than estimates for ISO-NE, saying it was because of lower assumed wholesale energy prices in PJM ($29/MWh vs. $60/MWh in ISO-NE).

Brattle calculated net CONE by subtracting wholesale energy savings and transmission and distribution savings from gross CONE but did not consider any capacity savings.

Bruce Campbell, CPower Energy Management | © RTO Insider

PJM’s Jeff Bastian said capacity market benefits were not included for EE just as they were excluded from the calculations for generating resources.

“This is a load-side resource,” responded Bruce Campbell of CPower Energy Management. “It’s different than a generator.”

Tom Rutigliano of the Natural Resources Defense Council said Brattle appeared to be “vastly undervaluing” EE, saying it should be assessed from the point of view of the asset owner. In addition to including capacity benefits, that means energy savings should be valued at the retail — not wholesale — rate, he said.

“This stuns me that you simply ignore the capacity benefit at the customer level,” Campbell added. “You recognize the energy savings, but you don’t recognize the capacity savings. That just seems inconsistent to me.”

Errors on Solar PV?

The three-hour meeting ended with a presentation by Michael Borgatti of Gabel Associates on how resources seeking unit-specific price floors would document their actual costs. “The fundamental rule in the Tariff is you have to be able to provide the same level of detail and support as in [PJM’s] CONE study. That is a reasonable standard,” he said.

Borgatti used an example of a 100-MW single-axis tracking solar PV array to identify what he said are errors in PJM’s assumptions. Correcting PJM’s assumptions on useful life (30 years, not 20), construction duration (nine months), weighted average cost of capital (7.7%, not 8.2%) and capacity value (60%, not 42%) reduced the gross CONE from $290/MW-day to $168/MW-day, he said.

Separately, he offered a Lazard proxy that set gross CONE at $143/MW-day, which he said represented “what you should expect market participants to” submit. “There’s a delta there [between $168 and $143], but it’s not significant,” he said.

With a $213/MW-day E&AS offset, he added, net CONE is zero.

Gabel Associates says correcting errors in PJM’s assumptions on useful life, construction duration, weighted average cost of capital (WACC) and capacity factor reduced the gross CONE for a 100-MW single-axis tracking solar PV array from $290/MW-day to $168/MW-day. | Gabel Associates

MIC Chair Lisa Morelli said Borgatti’s presentation would inform PJM’s compliance filing and future discussions on MOPR procedures. She joined Keech in apologizing that some materials for Friday’s meeting were not posted until just hours beforehand.

“You are … getting real-time updates of the latest and greatest PJM thinking,” she said. “It’s a pretty heavy lift within the 90-day compliance [deadline]. You’re seeing a race to the finish.”

Next Meeting

The next scheduled discussion on MOPR will be the MIC’s regular meeting March 11. Morelli said the afternoon would be reserved for MOPR, “if not more.”

“We can’t sweep aside all MIC business.”

March 3, 2020

Ex-CPUC Head Counsels Fresh Look at Energy Future

By Hudson Sangree

SAN FRANCISCO — The former president of the California Public Utilities Commission told a gathering of energy lawyers Friday that common assumptions about the future of renewable energy and electrification need to be re-examined.

Michael Picker, who left the commission in summer 2019, was replaced by Marybel Batjer. Since then, Picker said he’s been working for Gov. Gavin Newsom, putting together an energy roadmap for the state as it tries to reach its ambitious renewable energy and greenhouse gas reduction goals by midcentury. (See Retiring CPUC President Still Has Lots to Say.)

Former CPUC Picker speaking at the EBA Western Chapter meeting — Former CPUC President Michael Picker was the keynote speaker at the Energy Bar Association’s Western Chapter meeting in San Francisco on Friday. | © *RTO Insider*

His research has led him to new thinking about reliability and resilience, he told the Western Chapter of the Energy Bar Association at its annual meeting. Picker was the keynote speaker, and his thought-provoking presentation was discussed throughout the day’s proceedings.

For instance, Picker said the idea that the state’s biggest utilities are opposed to clean energy, while community choice aggregators are more progressive, doesn’t pan out in the math.

The state’s investor-owned utilities — the “much maligned” Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric — had achieved renewable portfolio compliance of 40%, 36% and 41%, respectively, by the end of 2018, he said.

“So that’s not bad progress since the goal was 30% by 2020,” Picker said. “And if you look at the forward compliance, each of them expects to be at 52% or above by 2024.”

Under Senate Bill 100, passed in 2018, the IOUs are expected to achieve primary reliance on clean energy sources by 2045.

Community choice aggregators (CCAs), most of which promise clean energy to retail customers and will become the majority of load-serving entities in coming decades, are falling behind, he said. They’ve proven more reliant on short-term contracts with out-of-state generators, with transmission constraints between source and sink, he said.

The IOUs, with more capital available, have been more successful in signing long-term contracts with in-state generators, whereas the “smaller entities [such as CCAs] with thinner capitalization have had a harder time being able to make those investments in long-term contracts,” he said. (See Calif. Lawmakers Reveal Growing Divisions over CCAs.)

Another issue, Pickers said, is that time-of-day demand from residential and commercial customers is merging.

California’s aerospace and automobile manufacturing economy died away, he said. Those industries used electricity around the clock, working three shifts every 24 hours. Now the state has a lot of “computational-based industries” that mirror household demand, with peaks about 200 hours out of the year, mainly after 5 p.m. on weekdays, he said.

“Who wants to build a power plant that’s only going to be selling electricity for 200 hours per year?” Picker said. “And how do you do that with solar if some of that demand is in the evenings after the effective capacity of solar starts to decline as the sun’s going down to the horizon?”

Rethinking EVs

Picker also noted that there’s a common misconception that generators are responsible for the bulk of greenhouse gas emissions. Electricity generation is responsible for 15% of carbon emissions, whereas transportation is responsible for 40%, he said.

State law requires a reduction in greenhouse gases by 40% below 1990 levels by 2030.

“As the electricity supply gets cleaner, it’s harder to reach that 2030 goal simply on the backs of the electric industry,” Picker said. “We have to address transportation.”

EBA Western Chapter Meeting — San Francisco’s historic Palace Hotel was the setting for this year’s annual meeting of the Energy Bar Association’s Western Chapter. | © *RTO Insider*

Statutes set a goal of having 2.5 million electric vehicles on California’s roads by 2025, he said. But planners tend to focus on individual ownership of EVs.

“There’s an implicit assumption amongst many of the planners that transportation is going to look the same 20 years from now as 20 years before,” he said. “Most of the policy … is focused on single ownership cars.”

In some urban areas, including Sacramento, more EVs are being charged and parked under car-sharing programs. The cars are taken to central locations where they’re charged at night, when demand is lowest, and distributed throughout the cities during the day.

Why, then, are government planners focused on owners charging cars in their garages? Picker asked.

“Why wouldn’t [car sharing] be the public policy priority rather than people installing [charging stations] in their homes?” he said.

Another point: As more Western states adopt renewable energy goals, the hydroelectric power generated in the Pacific Northwest will become a more coveted commodity, Picker said. And limited transmission will result in greater congestion, he said.

Electricity is becoming devalued as a commodity, while poles and power lines are generating greater revenues, he said.

The focus of policies has been on reducing greenhouse gases, but climate change will require greater resilience, which Picker said is another term for adaptation to changing circumstances.

“What I’m arguing,” Picker said, “is that we’re going to see more and more focus on adaptation.”

March 3, 2020

Western RTOs ‘Imperative,’ Says Retiring CAISO CEO

By Hudson Sangree

FOLSOM, Calif. — As he prepares to leave CAISO this summer, CEO Steve Berberich said a regional transmission organization is essential for maximizing renewable energy use across the West, but that it won’t coalesce under the ISO unless California lawmakers admit other states to its Board of Governors.

California’s governor appoints the five members of CAISO’s board, and the State Senate confirms the appointments. The idea that heavily Democratic California could dictate energy policy to the more conservative states of the Interior West has proven the major obstacle to forming an RTO under CAISO. Similarly, California politicians don’t like the idea of sharing authority over the ISO with coal-burning states such as Arizona and Wyoming.

CAISO Berberich — Steve Berberich | © *RTO Insider*

Asked if he could foresee one or more Western RTOs forming in the future, Berberich replied, “I think it’s an imperative.”

In an interview with RTO Insider at CAISO’s suburban Sacramento headquarters last week, Berberich addressed the question of Western regionalization and talked about his impending retirement from the ISO.

CAISO’s Western Energy Imbalance Market allows real-time trading across state lines, and a proposal to expand it to a day-ahead market could enhance its value, Berberich said. But whether the regionalization effort can move beyond the EIM is problematic, he said.

“There is some desire of those in the West to have an RTO, and I fully respect the fact that some of the out-of-state people are certainly not interested in joining the California ISO’s RTO because of our governance,” he said. “I believe that it’s in California’s best interest to have a regional RTO, and that it be this RTO that is extended. However, I believe that the possibility does exist that other RTOs will form in the West eventually.”

Rocky Mountain states, for instance, could band together, leaving out the West’s coastal states, he said.

“It’s absolutely essential for high levels of renewables to have a regional grid,” Berberich said. “And I take note [that] … Iowa sometimes can meet 100% of its load with its wind fleet. Why? Because they’re part of MISO, and because MISO is such a giant footprint, they can absorb that kind of movement. In Europe, they run the day-ahead market across the entire continent, and they leverage each other’s assets. That’s how you have to do it.”

Although California could go it alone, it could achieve lower energy costs and higher carbon reductions in an RTO with other states, he said. (See Can Calif. Go All Green Without a Western RTO?)

That will only happen if other states are represented on the CAISO board, Berberich said. Even states with similar carbon-reduction and renewable-energy goals, such as Oregon and Washington, won’t join a CAISO RTO without a say in its governance, he said.

“If this ISO is to become the Western RTO, the governance has to change,” Berberich said.

That will be a tough sell in the State Capitol. Lawmakers have already rejected efforts to alter CAISO’s governance structure, most recently with a bill that languished in 2018. (See Western RTO Proponents Vow to Keep Trying.)

“Ultimately, I respect that the policymakers downtown in Sacramento are going to have to make this decision,” Berberich said. “It won’t be ours to make.”

‘The Right Time’

Berberich, 56, a Missouri native, earned business degrees from the University of Tulsa and worked in finance, technology and utilities, including a stint at the former TXU Corp. when it entered the newly deregulated Texas energy market in the early 2000s.

He came to CAISO 15 years ago, serving as vice president of technology, chief financial officer and chief operating officer before taking the helm as president and CEO nine years ago. Berberich earned nearly $1.5 million in 2017 according to CAISO’s Form 990 filing as a nonprofit organization with the Internal Revenue Service.

The ISO announced his plans to retire early this summer on Feb. 19. (See CAISO CEO Steve Berberich Retiring.)

The announcement came soon after the retirements of two other CAISO leaders in January. Keith Casey, vice president of market and infrastructure development, and Nancy Traweek, executive director of system operations, both retired after more than two decades at the ISO. (See CAISO Announces Leadership Changes.)

The series of high-level retirements are coincidental, each driven by personal circumstances, Berberich said.

“I think it’s the right time for me,” he said, explaining that CEOs and the organizations they lead both need a change every decade or so.

Berberich said he and his wife are planning to move to Dallas to be near their grandchildren. He said he’s not done working but hasn’t decided his next move yet.

The ISO has begun a nationwide search for his successor.

Restoring Trust

Recounting his accomplishments as CEO, Berberich said, “First and foremost, it’s showing the world how you can operate a grid with large amounts of renewables on it and do it in such a way that it’s reliable and efficient and effective — and I think we’ve done that.”

Peaks of wind and solar on CAISO’s system have reached more than 70% and total renewables serving demand topped out at more than 80% on May 15, 2019.

“I can remember when people were concerned about 20% renewables on the grid,” Berberich said. He looked at the board in CAISO’s control room last Tuesday around noon and said, “Right now we’re at 54% on the grid.”

Challenges lie ahead, he said, including serving peak and residual-peak load as the sun sets and solar goes offline, he said. CAISO planners predict potential shortfalls starting in 2021. (See CAISO, CPUC Warn of ‘Reliability Emergency’.)

And whether electric vehicles will absorb excess solar energy during the day or exacerbate California’s peak evening demand remains in doubt. (See EVs Could Soak up Solar or Exacerbate ‘Duck Curve’.)

“EVs are either a marriage made in heaven or a marriage made in hell,” he said.

Another major accomplishment, Berberich said, is the restoration of trust following California’s energy crisis of 2000-2001 and the creation of the EIM, which is on track to have significant participation from entities in every Western state by 2023.

“The EIM has shown that we have established credibility and trust in the region, which was sorely damaged during the energy crisis, and I think being able to turn that around completely to the fact that they would trust us to participate in our market is a big change,” Berberich said.

He said he’s melancholy about leaving CAISO and hopes to be remembered by its staff as a good leader.

“The proudest thing I have here is the people and the culture that we’ve been able to develop at the ISO to embrace the changes facing us,” he said. “We have an amazing group of people here, and I’m just simply humbled to have been able to be part of that.”

March 1, 2020

CERAWeek Canceled as COVID-19 Virus Spreads

The COVID-19 coronavirus has led to the cancellation of one of the world’s largest energy conferences, CERAWeek, held annually in Houston.

IHS Markit, the London-based global information firm that organizes CERAWeek, said it had made its decision “reluctantly and after deep consideration.” The event was scheduled March 9-13.

In an email to participants and a message posted on CERAWeek 2020’s website Sunday, IHS Markit said that concern about the virus has “mounted rapidly” in recent days. It pointed to increasing number of companies instituting travel bans and restrictions, more restrictive border health checks and “growing concern about large conferences with people coming from different parts of the world.”

CERAWeek COVID-19 Virus — EPA Administrator Andrew Wheeler speaks at CERAWeek 2019. | © *RTO Insider*

Event organizers were expecting delegates from more than 80 countries to participate in CERAWeek 2020. Last year’s event drew more than 5,500 executives, government officials and thought leaders from the energy, policy, technology and financial industries.

“Our No. 1 concern is the health and safety of delegates and speakers, our partners, our colleagues and vendors,” event organizers said, noting they had established a medical partnership with a local hospital and were in touch with infectious disease experts. “But the spread of COVID-19 is moving quickly around the world.”

IHS Markit said it would continue with CERAWeek 2021 in Houston on March 1-5, 2021.

COVID-19 has infected more than 88,000 people worldwide, killing almost 3,000, including one in the U.S.

— Tom Kleckner

March 1, 2020

January Proves No Trouble for MISO

By Amanda Durish Cook

CARMEL, Ind. — A mild winter across the Midwest footprint made for an easy January for MISO operators, stakeholders heard last week.

“Load is down; temperatures for the footprint are higher than usual. It’s been a mild winter so far,” Executive Director of Energy Operations Rob Benbow reported at a Reliability Subcommittee meeting Thursday. He added that MISO months before had forecasted a warm winter.

Load for the month averaged almost 76 GW, down from 80.2 GW in January 2019. The month’s 94.4-GW peak load on Jan. 21 was also significantly lower than the 101-GW peak experienced last January. MISO staff in fall predicted a 104-GW peak, with the highest risk of emergencies in January. (See MISO Taking Pains to Prepare for Moderate Winter.)

MISO January — MISO day-ahead and real-time prices January 2019 to January 2020 | *MISO*

Real-time prices were similarly down at an average of $21.21/MWh, a 27% decrease year over year.

January marked MISO’s seventh straight month without any maximum generation alerts, warnings or events. Between May and June 2019, the RTO experienced seven maximum generation actions. MISO had not experienced an emergency-free January since 2017.

Benbow said MISO South was under a severe weather alert Jan. 10-11 as a band of tornados and strong winds traveled across eastern Texas, Louisiana and Alabama. He said that while the region experienced some transmission losses over the two days, MISO operators were able to work around them and avoid escalation.

Nov. 13 Revisit

So far, MISO’s only notable cold-weather event remains outside the winter months, when the Southeastern U.S. was hit with a cold snap Nov. 13 that sent temperatures plummeting 25 degrees Fahrenheit below normal in some cities.

“We had a relatively warm summer and fall, then we got this cold weather blast,” said Gerald Rusin, senior adviser for MISO South operations. “MISO did see the cold weather coming and was prepared for it.” The RTO experienced about 5 GW of capacity losses in the face of cold weather-related outages and contingencies.

However, SPP also declared a Safe Operating Mode (SOM) and requested that MISO limit flows to 1,500 MW on the regional dispatch transfer limit between its Midwest and South regions, down from the usual 3,000 MW southbound and 2,500 MW northbound limits. The RTOs’ SOM joint agreement is meant to keep an abnormal operating event in either grid operator’s territory from progressing into an emergency.

“Did we understand that it was going to be a challenging day? Yes. Did we expect SPP to request to cut the limit by half? No,” Benbow told stakeholders.

MISO’s Independent Market Monitor in January said he continues to investigate whether SPP should have made an intermediate move, including requesting unit redispatch or transmission loading relief, before calling for the “sledgehammer” transfer limit derate. The Monitor said SPP gave little warning before the request, leaving MISO with significant congestion costs. (See “Monitor Examining SPP’s Fall Transfer Derate,” MISO Market Subcommittee Briefs: Jan. 8, 2020.)

As a result of the incident, Rusin said the RTOs have agreed to a “refresher training” for their control room operators on how to use their congestion management tool for flowgates.

Rusin also said MISO is taking pains to ensure that neighboring reliability coordinators communicate system conditions to one another.

“It’s just bringing all the RCs together before an event occurs to make sure they’re talking to each other,” Rusin said.

MISO also said it needs to ensure that when SPP requests a new regional dispatch transfer limit, any ensuing temporary calculations are reflected in all of MISO’s impacted market processes.

March 1, 2020

ERCOT TAC OKs Glossary Change in Email Vote

ERCOT’s Technical Advisory Committee on Friday unanimously approved a change to the Resource Registration Glossary (RRGRR021) with an email vote.

RRGRR021 adds new data requirements to the glossary to account for submittal requirement fields for dynamic models, which are required by the Transient Security Assessment Tool (TSAT). The change, which was granted urgent status, allows the TSAT to calculate dynamic stability-related generic transmission limits in real time and help the operators maintain system reliability.

ERCOT glossary — Reliability deployment price adder ramp, August 13 ERS Deployment | *ERCOT*

Committee members also directed the Wholesale Market Subcommittee to determine whether to modify the 10-hour restoration period for emergency response service (ERS). A reliability deployment price adder uses unrestored ERS to adjust the generation to be dispatched. ERCOT’s protocols require the TAC to annually review the restoration period.

Several members expressed their openness to ERCOT recommending a new restoration period of as little as five hours.

The issue was discussed during a January joint meeting between the Wholesale Market and Demand Side working groups, but they were unable to agree on a recommendation.

During the information session, scheduled after the in-person TAC meeting was canceled, ERCOT legal staff told the committee it has scheduled an April 9 workshop to share its proposed changes to market-entry requirements for counterparties. Referencing the GreenHat Energy default in PJM, Juliana Morehead said the Texas grid operator wants to strengthen its oversight of various counterparties’ financial health and prevent market exposure to potential bad actors.

— Tom Kleckner

March 1, 2020

NY Renewable Supporters Push for New Siting Agency

By Michael Kuser

ALBANY, N.Y. — For years, the Alliance for Clean Energy New York (ACE NY) has advocated for a more standardized siting process for renewable energy projects in the state. Now it has a proposal from Gov. Andrew Cuomo to help push through the state legislature.

Getting the legislature to pass a budget amendment to create the proposed Office of Renewable Energy Permitting “certainly is our top priority,” ACE NY Director Anne Reynolds told a legislative breakfast she hosted Thursday.

Cuomo earlier in February announced the plan to amend this year’s state budget to streamline the siting process for large-scale renewable energy projects. (See Cuomo Proposes Streamlining NY’s Renewable Siting.)

The proposed budget bill aligns state law, bureaucratic practices and policies — including property tax laws — with the clean energy goals outlined in last July’s landmark Climate Leadership and Community Protection Act (CLCPA) (A8429), said Jennifer Maglienti, assistant counsel to the governor’s office.

Transmission Warranty

“Siting is a process that needed to be turned around in order to meet the goals, and the goal here was to do a soup-to-nuts rewrite, to look at not just generation, but also to deal with transmission,” Maglienti said.

NY renewables siting agency — Jennifer Maglienti, N.Y. governor’s office | © *RTO Insider*

To facilitate development of bulk transmission, policy planners first needed to address the timing of the Article VII process, which covers the need for a project, as well as its environmental impacts, and create automatic time frames, she said.

“What we’d like to do in the siting process is have a one-year time frame for review … and we also want to look at where are there constraints,” Maglienti said. “One large portion of the bill is to deal with how to get the DPS [Department of Public Service] along with a lot of other partners to do a comprehensive study to decide where are there constraints on the grid.”

The budget amendment calls for the DPS to work with NYISO, the state’s two power authorities and the utilities to perform a “power grid study” for the purpose of “identifying distribution upgrades, local transmission upgrades and bulk transmission investments” needed to meet the CLCPA goals.

The budget bill says the state “shall provide for timely construction of new, expanded and upgraded distribution and transmission infrastructure,” which may include “submarine transmission facilities needed to interconnect offshore renewable generation resources to the state’s transmission system.”

Anbaric and other transmission developers have argued that having individual wind farms build separate radial lines to shore will be more expensive, more environmentally intrusive and less resilient than networked, open-access facilities. (See Anbaric Pushes Offshore Grid Plans.)

“Anbaric applauds the Cuomo administration’s continued support for transmission’s essential role in reaching the state’s carbon reduction and offshore wind goals,” Theodore Paradise, Anbaric senior vice president for transmission strategy, told RTO Insider.

The CLCPA calls for 70% of New York’s electricity to come from renewable energy resources by 2030 and for electricity to be 100% carbon-free by 2040.

The law also calls for 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, in addition to nearly quadrupling New York’s offshore wind energy target to 9 GW by 2035.

Statutory Process

New York in 2011 revised Public Service Law Article 10 to unify siting reviews of new or modified electric generating facilities under one state agency, the Board on Electric Generation Siting and the Environment.

“Certainly Article 10 was set up for a good reason, and the processes set up for a good reason … but it’s going to be an entirely new office, and certainly with a lot of cooperation from the regulatory agencies,” Maglienti said.

The executive branch proposes that the New York State Energy Research and Development Authority will collaborate with the Department of Environmental Conservation (DEC) and DPS to develop build-ready sites for renewable energy projects.

“We want to think about how we’re going to encourage local participation, finding a way to help local communities contribute to the process,” Maglienti said. “We want the [Public Service Commission] to determine how those communities benefit, and for NYSERDA to get a site build-ready.

“When we talk about the siting of wind and solar, we’re talking in some cases about off-the-shelf technology, and we don’t need to get into long, protracted conversations about what those impacts might be and how they might be mitigated,” she said.

Community Concerns

“We met with a lot of communities and stakeholders to go through what issues people were facing when they’re trying to get more renewable energy projects sited, and we have communities who have concerns as well as developers and environmental groups who have concerns,” said Julie Tighe, president of the New York League of Conservation Voters.

Cuomo’s leadership on the siting issue is critical, Tighe said: “Having worked in the administration myself, I know that when the governor decides to do something, and he puts his mind to it, it gets done.”

DEC is well known as a conservation organization, being the largest landowner in the state of New York, and is better equipped to do siting on a regional basis, Tighe said.

“You get a much more comprehensive, regionally important project by having a mitigation bank rather than doing a one-off,” Tighe said. “We’ll probably want to see a little more specificity around that, but I think it’s a really important component and something that the legislature should advance and embrace.”

According to EPA, a mitigation bank is a wetland resource area that has been restored, established, enhanced or preserved to provide compensation for unavoidable impacts to aquatic resources permitted under Section 404 of the Clean Water Act, or a similar state or local wetland regulation.

“We very much appreciate having a process that’s just looking at renewable energy, and including transmission in that,” Tighe said.

March 1, 2020

CenterPoint’s Somerhalder Focused on Core Business

By Tom Kleckner

CenterPoint Energy interim CEO John Somerhalder said he was “honored” to step in as a placeholder when he introduced himself to financial analysts during the company’s quarterly earnings call Thursday.

“Alongside our leadership team, I am excited to move this company to deliver strong results and drive shareholder value,” he said during the call.

Somerhalder, a member of CenterPoint’s board, was named to temporarily replace Scott Prochaska, who unexpectedly stepped down Feb. 19. (See Prochazka Steps down as CenterPoint CEO.)

CFO Xia Liu handled the majority of the analysts’ questions, but Somerhalder was quick to respond when an analyst asked when a permanent CEO would be named.

“I am interim president and CEO. I have no timeline or no time limit,” he said. “I am here; very proud to be here; very focused on executing on the strategy for as long as required until the right transition to a permanent CEO at the right time is made.”

Somerhalder said CenterPoint earned $1.25 billion in cash from the recent sail of its natural gas retail business and two natural gas pipeline contractors. The proceeds will be used to pay down debt as the Houston-based company focuses on its core utility business.

“Our board is very focused on exactly what we’re focused on,” Somerhalder said. “They see the value of our utilities. They see the value of investment in rate base growing those earnings. … And so that strategy is what they support and what they believe is appropriate moving forward.”

CenterPoint reported fourth-quarter earnings of $231 million ($0.45/share), exceeding its 2018 fourth-quarter performance of $160 million ($0.36/share) and expectations of analysts surveyed by Zacks Investment Research, which had projected the same earnings per share as last year.

For the year, the company reported a profit of $895 million ($1.79/share), up from 2018’s earnings of $698 million ($1.60/share).

CenterPoint’s stock price jumped to $25.27 shortly after the earnings announcement. It closed down for the week and the year at $23.02.

March 1, 2020

ISO-NE: States Must Lead on Carbon Pricing

By Michael Kuser

ISO-NE CEO Gordon van Welie said Thursday that implementing a carbon price in New England’s wholesale power markets would be “simple” but that state officials need to signal their support before the RTO can act.

Van Welie made his comments in his response to a Feb. 19 letter from U.S. Sens. Ed Markey (D-Mass.), Bernie Sanders (I-Vt.) and Sheldon Whitehouse (D-R.I.) expressing concern that the RTO “is pursuing certain changes to the energy market at the expense of the region’s environmental goals and related clean energy and energy efficiency policies.”

ISO-NE carbon pricing — ISO-NE CEO Gordon van Welie | © *RTO Insider*

“If ISO-NE believes that the region’s clean energy goals can be addressed by integration of a carbon price into the energy market, what is stopping ISO-NE from studying this as a potential policy pathway and ensuring that New England stakeholders have accurate background on these policies?” the senators asked.

They noted the October report commissioned by NYISO Study: Carbon Charge to Help NY Climate Goals.)

“ISO-NE should commission a similar report … and take a larger leadership role in engaging more proactively in policy development,” they wrote.

Van Welie said that while the RTO supports carbon pricing, “we are mindful of concerns raised by the New England states regarding a carbon price in the wholesale markets, including limitations on the states’ ability to influence a federally regulated carbon price. We take these concerns seriously and appreciate the relationships we have developed with the states and the New England Power Pool stakeholders over the last several decades. Therefore, any effort to study carbon pricing requires further discussion in the regional stakeholder process — a process that is improved with input (like this exchange) from members of the region’s congressional delegation.”

Van Welie said “pricing carbon could be implemented by state or federal policy including through the existing Regional Greenhouse Gas Initiative structure.”

But while Massachusetts and Connecticut have pursued ambitious environmental policies, including contracting for offshore wind, other New England states have been reluctant to reduce RGGI’s emission limits enough to make state-subsidized resources economic in the RTO markets. “What I want is not to pay for Massachusetts’ and Connecticut’s policies,” New Hampshire Public Utilities Commissioner Robert Scott told a ISO-NE Two-Tier Auction Proposal Gets FERC Airing.)

Van Welie quoted from his November response to a similar missive from seven U.S. senators from New England, saying that pricing carbon through regional wholesale markets “is a simple and easily implemented mechanism for reducing (or eliminating) carbon and sparking a clean energy transition.”

The seven senators had urged ISO-NE to “return to the table with stakeholders” and more closely align its fuel security initiative with state policies seeking to speed the transition to renewable energy resources. (See Senators Ask ISO-NE to Heed States on Clean Energy.)

The senators criticized ISO-NE for “pursuing a patchwork of market reforms aimed at preserving the status quo of a fossil fuel-centered resource mix” and having “charted its own path forward and pursued unpopular initiatives” such as Competitive Auctions with Sponsored Policy Resources and the Inventoried Energy Program.

In last week’s response, van Welie insisted ISO-NE has long supported carbon pricing.

“The relative ease of implementation is particularly attractive when compared to some of the more detailed market changes we have made in the past (and that may be required in the future) to protect market efficiencies as states take actions outside the wholesale market to meet their policy goals,” van Welie said.

March 1, 2020

MISO Preps for GridEx VI

By Amanda Durish Cook

CARMEL, Ind. — MISO last week said preparations are in the works for the 2021 GridEx VI exercise, with the RTO drawing on lessons learned during last year’s event.

Speaking at a Reliability Subcommittee meeting Thursday, MISO outage coordinator Trevor Hines said the RTO is already selecting internal committees to design scenarios and lead GridEx VI simulations.

“GridEx planning never stops. We’ve always got to improve with these things, right? We got a good baseline in 2019; 2021 will give us an opportunity to improve even more,” he told stakeholders.

MISO GridEx — Scenes of MISO participating in GridEx V last year | *MISO*

Hines said MISO’s 2019 exercise saw a jump in interest and attendees: “We went from roughly 80 players in 2017 to over 110 in 2019.” The biennial NERC-sponsored GridEx took place Nov. 13-14, giving MISO and members the opportunity to train for “fuel shortages, loss of control center functionality, physical and cyberattacks, and a compromised back office.”

MISO last year coordinated with local law enforcement and had the Carmel Police Department on-site at its headquarters during simulations.

“We used GridEx as an opportunity to test their bomb-sniffing dog,” Hines said of the 2019 training. “We had failures; we were making decisions and there was talk of evacuating in the scenario and how that works when there’s law enforcement on-site examining suspicious packages.”

Hines said for the 2021 event, MISO will focus at least one scenario on who has the authority to order an evacuation at the RTO and how it’s conducted.

He said after the 2017 exercise, it was difficult to coordinate after-the-fact with MISO members to gather suggestions for improvement. For 2019, MISO created a survey to collect suggestions for improvement in real time, allowing it to compile a list of suggestions to improve the 2021 exercise.

Hines also said MISO last year doubled the four hours that RTO executives were required to attend GridEx training. “In 2019, we made them squeal a little and made them participate for a full eight hours,” he said.

MISO will host the national kickoff meeting for GridEx VI in September at its Carmel headquarters.