Page 1061 – RTO Insider

August 16, 2020November 30, 2023

ERCOT Board of Directors Briefs: Aug. 11, 2020

ERCOT is facing a collision of major system changes in 2024 when a new energy management system (EMS), real-time co-optimization (RTC) and energy storage and distributed generation resources will all be brought together.

If handled correctly, ERCOT “will have as modern a system as operated by anyone in the world, by a fair amount,” CEO Bill Magness told the Board of Directors on Aug. 11.

Under the Texas grid operator’s Passport Program, staff and stakeholders will bring an upgraded EMS online in June 2024. At the same time, they plan to incorporate the work currently being done by the Real-Time Co-optimization and Battery Energy Storage task forces. They will also add solutions for energy storage resources (ESRs) and distributed generation resources (DGRs).

Passport may not be on the same scale as the Nodal Program market redesign, which lasted more than four years, involved hundreds of contractors and cost hundreds of millions of dollars. When it was all over in 2010, nodal replaced ERCOT’s zonal market structure with a more granular structure comprising more than 8,000 resource nodes.

“This is a multiyear effort that’s going to require strong coordination,” Magness said. “One of the challenges [in] the next few years … will be resources. Some of these systems will need changes, and there are only so many people who can do coding.”

The program’s immediate focus is to complete the market rules for RTC and ESRs this year “so we can hit the ground running in 2021 writing the requirements,” he said.

The Passport Program will be more broadly communicated to stakeholders in September during ERCOT’s annual strategic planning sessions with the membership segments.

Unaffiliated board member Peter Cramton said Passport’s integrated approach to delivering the various projects is important, as the projects are interrelated and should be treated holistically.

“In June 2024, ERCOT should be in a position to be leading the world in modern electricity markets,” he said.

Peak, Wind, Solar Records as Load Returns

Magness told the board that load has begun to return to pre-COVID-19 levels as evidenced by increased energy usage in June and July.

Usage in June was nearly 1% higher than June 2019 and usage in July was up 2.7% when compared to July 2019. ERCOT set a new monthly peak demand on July 13 at 74.3 GW, breaking the previous mark of 73.5 GW.

Demand in the grid operator’s West Texas zones has also reached record levels, Magness said during his CEO’s report. The Far West and West zones exceeded prior summer peaks by 7% and 9%, respectively, during mid-July.

ERCOT also set records for wind and solar generation during June and July. Wind production reached a peak of 21.4 GW on June 28, while solar production topped out at 3.7 GW on July 3. The grid operator has added an additional 3.2 GW of wind and solar nameplate capacity since last summer.

“We’re really starting to see the impact of [utility-scale] resources,” Magness said. He noted that prices were $25 to $33/MWh during the July peak, reflecting a lack of scarcity pricing.

He said ERCOT will continue to produce COVID-19 load impact analyses through September, even though they’ve “kind of hit a groove.”

Hurricane Hanna inflicted “significant damage” in South Texas “that could have been worse” when it made landfall on July 24, damaging 30 138-kV and 69-kV lines, Magness said. He said American Electric Power’s Wade Smith, an ERCOT director, told him the night before the board meeting that AEP had restored a critical 138-kV transmission line several days ahead of schedule.

“The lines were basically lying on the ground,” Magness said. “What AEP did, in the heat of August, in the [Rio Grande] Valley, with COVID, was really remarkable.”

COVID-19’s effects have led to a $9 million drop in system administration fees. Combined with a $15.9 million negative variance in interest expense, a timing issue “that is going to save us in the long term,” ERCOT is currently facing a $28 million year-end negative variance, Magness said.

Retired DC Tie’s Load Zone Removed

The board approved staff’s recommendation to delete the recently retired Eagle Pass DC tie’s load zone in South Texas.

The DC tie began a forced outage in March. AEP, the tie’s owner, told ERCOT in April that it was permanently removing the tie from service because replacement parts were unavailable. The grid operator has since stopped approving injections onto the tie.

ERCOT’s protocols require a 48-month waiting period before a load zone can be removed. Staff are considering sponsoring a Nodal Protocol revision request (NPRR1017) to remove the board’s required approval and aligning DC-tie load zone deletions with the timeline for removing resource nodes.

The DC tie remains a settlement point for congestion revenue rights (CRRs) through 2022.

Direct Energy’s Ross Voted onto Board

Board Chair Craven Crowell said Direct Energy’s Ned Ross has been elected to replace Rick Bluntzer as the Independent Retail Electric Provider segment’s representative on the board. Bluntzer resigned from the board effective July 31.

Infinite Energy’s Steve Madden was elected to replace Ross as the segment’s alternate.

Consent Agenda Includes 35 Changes

The directors unanimously approved 34 revision requests and ERCOT’s methodologies for determining minimum ancillary service requirements on its consent agenda.

The latter change simply removes the use of the Resource Asset Registration Form (RARF) with more general language. A Resource Definition Task Force recently completed a three-and-a-half-year review of ERCOT’s definitions that resulted in several protocol changes.

The Resource Integration and Ongoing Operations (RIOO) function will replace the RARF, enabling market participants to electronically review and edit existing resource asset registration data. By the end of next year, ERCOT hopes to be able to add ESRs and DGRs to the RIOO.

The package of changes came with individual costs as high as $1.3 million.

“We feel like we’re in good shape financially with the implementation of these over time,” Magness said. “It’s not an issue of running out of money for this, but the buckets are getting full, and we have to make priorities.”

The changes included 15 Nodal Protocol revision requests (NPRRs), six changes to the Nodal Operating Guide (NOGRRs), a pair of Other Binding Document revisions (OBDRRs), five changes to the Planning Guide (PGRRs), three revisions to the Resource Registration Glossary (RRGRR), a system change request (SCR) and two changes to the Verifiable Cost Manual (VCMRR).

- - NPRR903: Clarifies the deviations that may occur with day-ahead market (DAM) delays and adds language requiring ERCOT to issue a market notice for any act or omission to ensure the DAM process is successfully completed.
  - NPRR973: Adds definitions for “generator step-up” and “main power transformer” to the Nodal Protocols and clarifies their uses.
  - NPRR983: Deletes remaining gray-boxed language associated with NPRR257 (Monitoring Programs and Changes to Posting Requirements of Documents Considered CEII).
  - NPRR990: Deletes the remaining gray-box for NPRR889 (RTF-1 Replace Non-Modeled Generator with Settlement Only Generator) and relocates the defined term “combined cycle train” from “Resource” to “Resource Attribute.”
  - NPRR992: Ensures that the day-ahead liability estimate correctly includes ERCOT contingency reserve service (ECRS) charges and payments, as intended by NPRR863 (Creation of ERCOT Contingency Reserve Service and Revisions to Responsive Reserve).
  - NPRR993: Clarifies grey-boxed language after the concurrent approval of NPRR902 (ERCOT Critical Energy Infrastructure Information) and NPRR928 (Cybersecurity Incident Notification).
  - NPRR996: Aligns the protocols’ hub bus names with the substation names within the ERCOT model.
  - NPRR1000: Removes the term “dynamically scheduled resource” from the protocols.
  - NPRR1002: Establishes ESR “single model” registration and charging restrictions during emergency conditions.
  - NPRR1003: Replaces all remaining references to the RARF with more general language in anticipation of the form’s elimination.
  - NPRR1004: Creates a new process for determining the CRR auctions and DAM clearing load-distribution factors by using load forecasting models and existing validation/error correction to determine daily load-distribution factors.
  - NPRR1015: Clarifies the market system’s submission and reporting changes necessary to complete NPRR863, implement changes to responsive reserve service and add ERCOT contingency reserve service.
  - NPRR101 6: Clarifies various important reliability requirements for DGRs seeking qualification to provide ancillary service(s) and/or participate in security-constrained economic dispatch.
  - NPRR10 20: Allows ESRs with integrated loads that cannot be metered as designed to use internal sensors in calculating the loads.
  - NPRR10 30: Changes the CRR auction revenue distribution allocation methodology from a peak 15-minute settlement interval to a load-ratio share based on adjusted metered load totals for each month. Also makes parallel changes for the CRR balancing account and certain block load transfers for consistency and implementation’s ease.
  - NOGRR195: Addresses the Texas Reliability Entity’s audit recommendations for ERCOT and modifies generator voltage control tolerance bands.
  - NOGRR196: Clarifies language used by NPRR973-proposed defined terms “generation step-up” and “main power transformer.”
  - NOGRR200: Deletes all remaining gray-boxed language associated with NOGRR025 (Monitoring Programs for QSEs, TSPs and ERCOT).
  - NOGRR208: Aligns the NOG with the Nodal Protocols as modified by NPRR1002. An alignment NOGRR for energy emergency alert will be filed following NPRR1002’s approval to align with the protocols.
  - NOGRR209: Replaces all remaining references to the RARF with more general language to align with NPRR1003.
  - NOGRR 2 1 2: Aligns the guide with NPRR1016’s revisions and clarifies DGRs’ various reliability requirements.
  - OBDRR018: Aligns the procedure for identifying resource nodes with NPRR1003’s changes by replacing all remaining references to the RARF with more general language.
  - OBDRR019: Aligns the requirements for aggregate load resource participation in the ERCOT markets with NPRR1003’s changes by replacing all remaining references to the RARF and updates the process’s change control process with similar OBDs.
  - PGRR074: Clarifies language used by NPRR973-proposed defined terms “generation step-up” and “main power transformer.”
  - PGRR076: Changes the generation resource interconnection or change request process to specify that the proposed commercial operations date in the initial application must be 15 months or greater than the date of the application; redefines the security screening study output; creates separate reports for the full interconnection study; coordinates reactive study; and clarifies when the dynamic data model should be submitted to meet the quarterly stability assessment prerequisite deadline.
  - PGRR078: Specifies that data related to the regional transmission plan and special planning studies considered protected information may be posted to the market information system’s (MIS) certified area for transmission service providers. The change also includes updated resource asset registration form generator data postings to the MIS.
  - PGRR079: Aligns the guide with NPRR1003’s changes by replacing all remaining references to the RARF.
  - PGRR080: Aligns the Planning Guide with NERC Reliability Standard TPL-007-4 (Transmission System Planned Performance for Geomagnetic Disturbance Events) by identifying responsibilities for performing studies needed to complete benchmark and supplemental geomagnetic disturbance vulnerability assessments.
  - RRGRR022: Clarifies language used by NPRR973-proposed defined terms “generation step-up” and “main power transformer.”
  - RRGRR02 4: Aligns the glossary with NPRR1003’s changes by replacing all remaining references to the RARF.
  - RRGRR026: Adds a new data point to support implementation of an interim solution representing DGRs and distribution ESRs in the ERCOT network operations model.
  - SCR810: Adds logic to ERCOT’s EMS by removing the flag that indicates to the operator that a unit representing a DC tie does not count toward the 2% criterion for activating transmission constraints.
  - VCMRR207: Removes from the manual and its appendix language regarding the validation rules imposed on ERCOT’s external telemetry and used in the resource-limit calculator. This maintains consistency between the manual and the protocols by aligning ESR-related provisions with NPRR986 (BESTF-2 Energy Storage Resource Energy Offer Curves, Pricing, Dispatch, and Mitigation) and its provision that ESRs do not have start-up or minimum-energy costs and sets their mitigated offer cap at the systemwide cap.
  - VCMRR 0 2 9: Aligns the manual with NPRR1003’s changes by replacing all remaining references to the RARF.

August 14, 2020

MISO Processing Heftiest Interconnection Queue Ever

MISO is juggling several transmission planning activities as it faces a cascade of new gigawatts in its interconnection queue, stakeholders heard during this week’s Planning Week.

The RTO announced a record number of new queue entrants in July, with customers submitting 353 applications representing about 52 GW of new generation. Solar generation, with 36 GW, accounts for the majority of the new generation proposals.

MISO said the 2020 queue entrants unseated the previous record of 47 GW, set in 2007, and the 44 GW that applied last year.

The new hopefuls bring the queue to 756 projects totaling 113 GW, 64% of which is solar. The grid operator is currently managing 13 queue cycles, with another cycle to open in 2021.

MISO was expecting about 25 GW of entrants this year, RTO adviser Joe Reddoch said during the Planning Advisory Committee’s teleconference Wednesday.

“More stringent requirements and transmission costs did not deter initial response,” he said, referring to stricter proof-of-land-use rules and higher network upgrade costs in recent years.

Reddoch said MISO’s use of the 2019 transmission planning futures — which executives admitted have become obsolete — likely contributed to the understated estimates. He said internal questions were raised as to whether the futures were too outdated and did not reflect a more aggressive renewable generation buildout.

Multiple Tx Planning Efforts Underway

MISO has several transmission planning initiatives underway against the backdrop of the daunting queue.

The RTO has opened a window for stakeholders to propose new planning studies for its 2021 Transmission Expansion Plan (MTEP 21). MISO’s new planning futures for 2021 predict anywhere from 148 to 352 GW of natural gas, solar and wind generation coming online over the next two decades.

“We are asking if you have any requests or input you would like to be considered for any additional studies for the MTEP 21 cycle,” MISO Project Manager Sandy Boegeman told stakeholders during a Planning Subcommittee (PSC) meeting. The idea submission window is open through Sept. 17.

At the same time, MISO is finalizing MTEP 20 projects it will recommend to the Board of Directors in October.

MISO Interconnection Queue — Draft breakdown of MTEP 20’s 513 projects | *MISO*

The MTEP 20 package now contains 513 new projects worth about $4 billion. Boegeman said the total costs are similar to last year’s package. However, she noted that this year’s $538 million spend on interconnection projects, or about 13% of MTEP 20’s costs, is about double that of MTEP 19’s.

MISO has also concluded that it should undertake long-range transmission planning studies separate from the annual MTEP study cycle. (See MISO Foresees Massive Shift to Renewables by 2040.)

Vice President of System Planning Jennifer Curran said MISO member plans portend a slew of new renewables and retirements of older, conventional resources. She told the PAC that now is the time for a new long-range transmission plan to keep the grid reliable and efficient as the resource portfolio shifts.

“MISO must focus now on solutions that anticipate and adapt to those rapid changes,” she said. She said that the long-term transmission studies will focus on renewable integration and transmission constraints, such as the import restrictions in Lower Michigan and the Midwest-South sub-regional limit.

The RTO’s last long-range transmission plan culminated in 2011’s Multi-Value Project (MVP) portfolio. Curran said this planning iteration won’t resemble that of a decade ago.

“I don’t think all these projects are going to come at once like the MVPs,” she said. “I think we could have multiple groups of projects approved periodically.”

Curran said the first projects would likely emerge next year in MTEP 21. She acknowledged that MISO has yet to work through a cost-allocation plan for the long-term projects, but it may be able to use existing allocation methods, such as the market efficiency project (MEP), for some of the MTEP 21 projects.

“But it’s important to focus on what the needs are first before we begin those conversations,” Curran said. “We don’t see cost allocation as a prerequisite for the work. … There are pros and cons for every cost allocation, and it’s going to be challenging.”

Xcel Energy’s Drew Siebenaler thanked MISO on behalf of the 10 Minnesota utilities that produced the CapX2050 transmission study for tackling long-term needs. (See CapX2050 Prompts MISO Focus on Midwest Tx.) Multiple state regulators also thanked the grid operator. The Organization of MISO States has been keen on a new long-term transmission plan since early 2019.

“We’re already seeing this portfolio shift, and we would argue some policies in the MISO states are going to accelerate this transformation,” Clean Grid Alliance’s Natalie McIntire said.

The grid operator is still working through a plan to coordinate its MTEP and interconnection-queue planning studies.

MISO MISO Interconnection Queue — | *Renew Wisconsin*

MISO proposed last month that generation project upgrades would need a minimum rating of 230 kV and cost at least $5 million to be eligible for evaluation as a possible MEP. (See MISO Unveils 1st Proposal to Consolidate Tx Planning.)

The RTO is debating whether it should align the interconnection queue and MTEP timelines and whether it should use more than one annual MTEP cycle to approve a transmission project solving multiple needs, provided the project is identified more than five years ahead of time.

MISO Senior Manager of Expansion Planning Edin Habibovic said it would probably be impossible for MISO to totally combine its interconnection queue studies with its economic and reliability planning studies. “But this doesn’t prevent us from looking at issues from a holistic point of view … to find a joint solution,” Habibovic told the PSC.

“The intent isn’t to merge these different planning studies into a single study,” MISO Senior Manager of Economic Planning Neil Shah agreed during the PAC teleconference. He added that the grid operator could investigate the concept of a consolidated planning process in the future.

Shah said MISO is currently focusing on fitting a “coordinated, not consolidated” approach that fits into existing Tariff processes. He said there are too many “moving parts” between economic planning and interconnection planning to completely merge them.

McIntire said it was worth considering a combination of some studies in the future.

August 14, 2020

Maine Court Rejects Referendum on Tx Project

Maine’s Supreme Judicial Court removed a major obstacle to the New England Clean Energy Connect (NECEC) transmission line Thursday, rul ing that a proposed voter initiative on the project is unconstitutional.

Ruling on a challenge by Central Maine Power and parent Avangrid Networks, the court said the ballot question improperly intruded on executive branch authority in seeking to reverse the Maine Public Utilities Commission’s 2019 order granting the project a certificate of public convenience and necessity. Maine’s constitution, the court said, only allows citizens’ direct initiatives to propose “legislation.”

The decision reversed a lower court decision that said it was not necessary to determine the constitutionality of the referendum before the vote.

“The ruling by the Maine Supreme Court is a victory for Maine and our future, both environmentally and economically. The Clean Energy Corridor makes Maine a leader in the efforts to address the climate crisis, removing millions of metric tons of carbon from our air,” project officials tweeted. “We now look forward to completing the permitting process and getting to work to deliver the benefits of this project to all Mainers.”

Opponents of the project vowed to continue their fight, however. Former state Sen. Tom Saviello, who leads a group opposed to the corridor, told the Bangor Daily News the opponents could seek legislation blocking the project or launch another referendum drive. “We’re not giving up,” he said. “This is just the beginning.”

NECEC Referendum — A rendering of what the poles will look like along CMP’s 145-mile transmission line | *Central Maine Power*

The $1 billion NECEC project would span 145 miles, with capacity to carry 1,200 MW of Canadian hydropower from the Maine-Québec border to Lewiston, Maine, where it will connect to the New England Control Area. The HVDC project includes upgrading 50 miles of existing AC transmission, a new converter station, a new substation and other upgrades.

NECEC says Massachusetts electric customers will pay for the entire project. The state entered negotiations with NECEC in 2018 after the New Hampshire Site Evaluation Committee rejected the competing Northern Pass project. (See Massachusetts Bids Adieu to Northern Pass.)

Referendum

The referendum would have asked voters to direct the PUC to issue an amended order finding that NECEC is not in the public interest.

NextEra Energy Resources, which owns fossil fuel generators in Maine and Massachusetts and the Seabrook nuclear plant in New Hampshire, intervened in support of the referendum, along with several voters and a generator-funded group called Mainers for Local Power.

Supporters argued that the substance of the referendum was consistent with the state constitution “because the legislature merely delegated legislative power to the commission, and the legislature remains free to interpose itself in proceedings where the commission has acted,” the court said in summarizing their position.

The court disagreed, saying legislative activity does not involve matters to which the legislature has delegated decision-making power.

“Directing an agency to reach findings diametrically opposite to those it reached based on extensive adjudicatory hearings and a voluminous evidentiary record, affirmed on appeal, is not ‘mak[ing] and establish[ing]’ a law,” the court ruled.

“Separate from its role in legislating through rulemaking to regulate public utilities, the commission functions in an executive capacity as an administrative agency, including by holding a public hearing — sometimes, as in the proceeding at issue here, a hearing substantial both in duration and in the volume of information submitted to and considered by the commission — and rendering a decision in a particular case when a utility has applied for a certificate of public convenience and necessity,” the court said. “The commission’s adjudicatory decisions therefore are subject to judicial — not legislative — review.”

The court said any motions for reconsideration of its ruling must be filed within five days after the order is published because ballots for the November 2020 election must be printed starting at the end of August.

Big Spenders

The battle over the referendum has generated millions in spending in the small state.

Clean Energy Matters, a political committee funded by CMP and Hydro-Québec, has reportedly spent at least $16.7 million to oppose the referendum. Calpine and Vistra Energy, which own natural gas generators in Maine, planned to spend $6 million supporting the initiative through Mainers for Local Power, Maine Public Radio reported last month.

The project also has split environmental groups in the region. The Conservation Law Foundation has been supportive, saying it will deliver low-carbon power to New England and allow retirement of fossil fuel plants. The Natural Resources Council of Maine opposes the line, saying it will have a negligible impact on carbon emissions while damaging the state’s woodlands.

About two-thirds of the line would be built along CMP’s existing rights of way, with the remainder routed through commercial timberland.

The 53 miles of new ROW will result in a 150-foot width clearing with an additional 150 feet undeveloped, NECEC says.

The routes where the HVDC line will be co-located with existing CMP transmission lines are 300 to 500 feet wide, with 150 feet or more cleared for existing lines. NECEC said it will clear an additional 75 feet for the new line in those locations.

CMP hopes to begin construction in 2020 and have the project in service by 2022. The Maine Department of Environmental Protection issued CMP a permit in May for construction of the project, which still needs approval from the U.S. Army Corps of Engineers and a presidential permit to cross the Canadian border.

Avangrid shares closed at $50.02/share Thursday, up 38 cents (0.77%).

August 14, 2020

PJM Monitor Reports Record-low Energy Prices

PJM energy prices were lower in the first half of 2020 than any first six-month period since the creation of the RTO’s markets in 1999, according to a report issued Thursday by the Independent Market Monitor.

Monitoring Analytics’ 2020 State of the Market Report for the second quarter said energy prices in the RTO were already among the lowest in its history in the first six months of 2019, coming in at $27.49/MWh. But the report found the load-weighted average real-time LMP was 29.4% lower in the first six months of 2020, at $19.40/MWh.

Monitor Joe Bowring attributed the $8.09/MWh decrease to lower fuel costs, which made up 51.3% of the lower number. The second major contributor to the decline in energy prices cited by the Monitor was a significant decrease in demand because of mild winter temperatures throughout the region and the stay-at-home orders arising from the COVID-19 pandemic.

PJM load was down cumulatively by 5.9% compared to the first six months of 2019, the report said, and down 4.5% on a weather-normalized basis. Energy prices in PJM were set by units operating at or around short-run marginal costs, the report said, providing evidence of “generally competitive behavior and competitive market outcomes.”

Theoretical net revenues decreased for all generating unit types in the first half of 2020 compared to 2019 because of lower energy prices, the Monitor said, with theoretical net revenues decreasing by 26% for a new combustion turbine, 29% for a new combined cycle unit, 91% for a new coal unit and 31% for a new nuclear plant.

The trend toward more energy from natural gas and less from coal in PJM continued to accelerate in the first six months of 2020, the Monitor found. The share of total energy produced from coal fell from 24.8% in the first six months of 2019 to 17.6% in 2020, while the share of natural gas increased from 33.8% to 39.4%. The capacity factor of coal units also fell from 30.9% to 22.1%.

Total energy uplift charges decreased by $13.7 million, or 37.3%, from $36.7 million in 2019 to $23 million in 2020, the report said. Total congestion costs decreased by $74.8 million, or 29.4%, from $254.1 million in 2019 to $179.3 million in 2020.

The report said total auction revenue rights (ARRs) and self-scheduled financial transmission rights revenues offset 138.8% of total congestion costs for the 2019/2020 planning period because FTR bidders paid more in the auctions than actual day-ahead payments for the same paths.

The Monitor said the goal of the FTR market design should be to ensure load has the rights to 100% of congestion costs. “When there are binding transmission constraints and locational energy price differences, load pays more for energy than generation is paid to produce that energy” the report said. “The difference is congestion. Congestion belongs to load and should be returned to load.”

August 14, 2020

NYISO Moves Forward on EAS Projects

NYISO continues to advance its Grid in Transition agenda, moving ahead with some energy and ancillary services (EAS) projects while suspending or combining others.

The Business Issues Committee on Wednesday recommended the Management Committee approve the ISO’s Reserves for Resource Flexibility project to increase the portion of the total statewide reserve requirement for Southeast New York (SENY, zones G-K) from 1,300 MW to 1,550 or 1,800 MW depending on the hour. Stakeholders in July had delayed a vote on the proposal pending additional cost analysis. (See NYISO BIC Balks on Increased Reserves.)

If the MC approves the proposal on Aug. 26, the ISO will seek to implement it in 2021.

Preparing for Uncertainty

Michael DeSocio, director of market design, updated stakeholders on NYISO’s coordination of other EAS projects, including ancillary services shortage pricing; constraint-specific transmission shortage pricing; more granular operating reserves; and the reserve enhancements for constrained areas project.

NYISO EAS Projects — Binding constraints for the relevant transmission facilities are concentrated in certain hours throughout the year; thus NYISO is proposeing to vary the incremental SENY 30-minute reserve requirement based on hours within the year, as shown. | *NYISO*

The ISO will continue to discuss the ancillary services shortage pricing proposal over the coming months, complete the consumer impact analysis in September, target seeking stakeholder approval in October and, if approved, implement it after the Reserves for Resource Flexibility initiative takes effect in 2021, he said.

The proposal is intended to improve real-time energy pricing during tight operating conditions to incent resource performance and improve economic signals for import and export scheduling.

“We’re trying to prepare for a world where there’s just going to be more uncertainty,” DeSocio said. “We’ll have more intermittent resources; we will have more resources that we’ll need to manage better over the course of a day, like energy storage or DERs; and therefore, we need to make sure the market is sending the pricing signals needed for resources to be available.”

There are still times when the shortage pricing could be improved to help ensure resource availability. Without flexible resources to help manage real-time conditions, the ISO may need to rely on uneconomically curtailing exports, purchasing emergency energy from neighboring regions or making out-of-merit commitment of uneconomic internal generators, DeSocio said.

It also can make additional commitments of generation after the day-ahead market through supplemental resource evaluations (SREs). All tools like SREs have impacts that can lead to issues where the market fails to incent the need for flexible resources like storage, he said.

“If we’re going to guarantee that any time a committed generator is added to the system, we’re going to make it whole to its minimum generation cost, there’s not a lot of incentive for it to reduce that min-gen cost because it’s not losing anything with the current structure,” DeSocio said. “By getting these reliability actions into the market directly, now the market can come up with a better mix and better pricing outcomes.”

Shifting Priorities

NYISO will continue to discuss its “constraint-specific transmission shortage pricing” proposal next year, but based on stakeholder feedback, it wants to shift resources away from the development of this proposal to supporting the development of the distributed energy resource participation model, DeSocio said. If stakeholders approve the transmission shortage pricing proposal by the end of 2021, the ISO will further consider implementation timing during the 2022 project prioritization planning.

In addition, NYISO recommends suspending work on the “more granular operating reserves” project to allow focusing on the “reserve enhancements for constrained areas” project, which will investigate ways to dynamically allocate reserves requirements between regions based on available transmission head room.

This project will evaluate ways to improve the modeling of reserve and transmission constraints to potentially allow reserve requirements to be shifted to lower-cost reserve regions as long as transmission head room exists to deliver the reserves to where needed without compromising reliability.

NYISO says this functionality would greatly improve the existing proposal for procuring reserves in certain New York City load pockets based on the design developed in the more granular operating reserves project.

The ISO recommends next year studying ways to potentially include a dynamic reserve allocation in the existing market software.

August 13, 2020

Expert Warns Utilities Remain Vulnerable to Cyberattack

Utilities looking to fortify their systems against cyberattacks must consider NERC’s Critical Infrastructure Protection (CIP) standards a starting point to be supplemented by additional security measures, according to a cybersecurity expert focused on the energy sector.

In a webinar hosted by EnergyCentral on Wednesday, Richard Brooks, CEO of Reliable Energy Analytics, said that despite repeated warnings about the rising threat of malicious cyber actors — especially to the power grid — many utilities still have not implemented comprehensive risk assessment and security protocols. (See Government Urges Action on Cyber Threats.) Citing the 2017 attacks on the Ukrainian power grid attributed to hackers employed by the Russian military, he warned that operators that fail to take their cyber risk postures seriously face the same fate.

“Originally, [the Ukraine energy company’s] risk assessment said they had very low risk of anything happening, in regard to the products … and the protocols they were using,” Brooks said. “Then they were struck with [the NotPetya malware], and they could see that their risk posture [had] changed, and now they realized they weren’t in a [low-likelihood, low-consequence] scenario — they were in a high-high scenario. This is how risk can change when reality strikes.”

Software Verification a Key Weakness

Brooks’ presentation focused on verification of software origins, a weakness of many companies’ malware defense strategies that is often exploited in cyberattacks. A recent report by the Atlantic Council, which evaluated 115 software supply chain attacks and vulnerability disclosures over the past 10 years, found that 27 of these attacks involved state actors such as Russia, China, North Korea and Iran, as well as India, Egypt, the U.S. and Vietnam. Common elements of such attacks include:

abusing trust in code signing by falsifying the certificates that endorse the integrity of code;
hijacking the software update process to insert malicious code into users’ devices;
poisoning open-source code by either surreptitiously modifying commonly used code or posting their own packages with similar names; and
targeting mobile application distribution networks, such as Google Play and Apple’s App Store.

While code verification is part of reliability standard CIP-010-3, Brooks noted that the standard’s requirement that utilities “verify the identity of the software source [and] the integrity of the software obtained from the software source” may leave entities vulnerable to the attack vectors cited in the Atlantic Council’s report. Likening the level of trust involved to “[taking] a free drink from a stranger in a bar,” he urged utilities to look beyond compliance with NERC’s standards and create their own processes for evaluating software products and vendors.

utilities Cyberattack — The Burshtyn TES power plant in Ivano-Frankivsk Oblast, Ukraine

“This is not a one-and-done case; you need to be constantly monitoring for risk,” Brooks said. “You want to implement integrity and authenticity controls following the guidelines of CIP-010-3 but also to augment that with best practices from the [National Institute of Standards and Technology’s] Cyber Security Framework. … Standards do not necessarily require entities to employ best practices.”

Small and Large Entities Vulnerable

While attacks against power systems often involve encrypting the target’s data and threatening to delete them unless a large ransom is paid, Brooks warned attendees not to assume that only larger entities are likely to be targeted in a cyberattack, as the aim of state actors is usually to disrupt a rival’s power grid rather than financial gain. In this light, a smaller utility with fewer resources for prevention may actually be a more tempting target for hackers than a larger entity.

To support this claim, Brooks pointed to a Notice of Inquiry (NOI) issued by FERC Starts Inquiry on CIP Standards.) The final question in the NOI asks utilities whether “smaller, geographically distributed generation resources” could be used in a coordinated cyberattack across a geographically distributed region.

“[With] these resources, it really doesn’t matter where they’re deployed; whether it’s in a rural co-op or in a bulk electric system, they all run some form of software for command and control,” Brooks said. “So, they are indeed part of the attack vector of the hacker community, and they do try to get into these devices, and then try to work radially to other areas where they could potentially cause harm. You don’t have to be a big guy or a little guy to be a victim.”

August 13, 2020

FERC Accepts PJM TOs’ End-of-life Revisions

FERC on Tuesday accepted PJM Transmission Owners’ Tariff amendments governing end-of-life (EOL) projects, a proposal that was hotly contested by stakeholders (ER20-2046).

The TOs had proposed to identify and include asset-management projects within the existing planning procedures of Tariff Attachment M-3 and to include procedures for the identification and planning for EOL needs of transmission lines 100 kV and above.

The TOs voted in June to approve a Federal Power Act Section 205 filing of the proposed amendments through voting procedures contained in the Consolidated Transmission Owners Agreement (CTOA). (See TOs Vote to File End-of-life Rules with FERC.)

Stakeholders challenging the filing asserted that the TOs do not have “exclusive filing rights” in regard to EOL projects and that PJM members maintain rights under the Operating Agreement to also make filings related to EOL projects. A competing, joint stakeholder pro p osal is still pending before FERC (ER20-2308). (See PJM Files EOL Proposal over TO Protest.)

“Given the specific facts and circumstances before us, we find that the planning activities addressed by the Attachment M-3 revisions filing are within the exclusive rights and responsibilities retained by the PJM TOs under the CTOA,” the commission said in its ruling. “Under the CTOA and the Tariff, the PJM TOs retain all rights that they have not specifically granted to PJM.”

TO Filing

The new rules will require TOs to have a formal process for EOL determinations and to identify potential EOL projects five years in advance. Projects that “overlap” with Regional Transmission Expansion Plan (RTEP) violations will be included in a competitive window seeking regional solutions.

The existing provisions of Attachment M-3 provide only for the planning of supplemental projects. The TOs’ revisions “expand the applicability” of the attachment by requiring each TO to present its criteria for assessing whether a transmission facility needs to be replaced. It also allows for annual stakeholder input in the EOL process.

“Significantly, the proposed revisions provide for coordination of EOL needs with the PJM RTEP planning criteria needs,” FERC said in its order. “This provides PJM and stakeholders with increased opportunities to review and comment on EOL need transmission projects, and thus provides greater transparency.”

The TOs’ filing also said the revisions will “better coordinate the Transmission Owners’ end-of-useful-life asset-management activities with PJM’s planning to address RTEP planning criteria” by providing the RTO projected replacements up to five years in advance.

As far as asset-management projects cited in the filing, FERC found they “do not fit within the categories of projects the [TOs] have transferred to PJM” and do not fall under regional planning under the OA because they relate “solely to maintenance of existing facilities” and do not “expand” or “enhance” the PJM grid as required in the CTOA to transfer planning to the RTO.

“They are solely projects that maintain the existing infrastructure by repairing or replacing equipment,” the commission said. “These projects therefore fall within the category of rights not specifically granted to PJM and therefore reserved to the PJM TOs.”

Protests

Dozens of PJM stakeholders intervened in the TO filing, some raising concerns that the “majority” of transmission planning in the RTO is happening outside of the bounds of the RTEP process. FERC said the argument was beyond the scope of the proceeding.

Concerns were also raised that the proposed revisions could result in “a cost allocation that is not consistent with cost causation.” FERC said provisions of Schedule 12 of the PJM Tariff assign cost responsibility for required transmission enhancements, but the revisions to Attachment M-3 include no revisions to Schedule 12 and propose no cost allocation changes.

Stakeholders, including American Municipal Power and Old Dominion Electric Cooperative, argued that the commission should reject the TOs’ filing and accept the joint stakeholder proposal passed by 69% of the Members Committee on June 18 despite the RTO’s opposition. FERC ruled that the joint stakeholder proposal was not before the commission in this proceeding and “does not alter the FPA Section 205 filing rights of the PJM TOs.”

“We find the PJM TOs’ Attachment M-3 revisions filing just and reasonable and need not determine whether proposed alternatives are more or less reasonable,” the commission said. “And, again, in this instance, the alternatives mentioned here consist of a filing made in a different proceeding, not this proceeding.”

The joint stakeholder proposal would require more transparency and oversight by PJM. The TOs and PJM say it violates the RTO’s governing documents and commission precedent on the RTO’s and the TOs’ roles in the planning of supplemental projects — including EOL facilities — and asset-management projects.

Sharon Segner, vice president of LS Power, said it is “too early to tell” if the commission will reject the joint stakeholder proposal or if both the TO revisions and the stakeholder proposal will be accepted. Segner said FERC’s language in its order left open the possibility to both being accepted, with a decision by Aug. 31.

“As a policy matter, LS Power continues to fight for the value of the regional transmission planning proposition, and the FERC order from yesterday is an attack on the value of the regional transmission planning process,” Segner said.

August 13, 2020

Calif. to Stay Course on Electrification, CEC Chair Says

The California Energy Commission will stick to the path of electrifying buildings despite a legal challenge filed against it by the nation’s largest natural gas utility, the agency’s chair said Wednesday.

California Electrification — CEC Chair David Hochschild | *California Energy Commission*

“Directionally, at the Energy Commission, we are going to keep fidelity to the state’s goals” of reducing greenhouse gases, including by electrifying buildings, increasing energy efficiency and procuring renewable energy, as required by landmark laws and executive orders signed by former Gov. Jerry Brown, Chair David Hochschild said.

“And along with that, we do care a great deal … about health,” Hochschild said. “And one of the things that recent research has uncovered is that the health impacts, even among homes that have gas, that have the same appliances, are not equal. Low-income homes are more likely to have heavier burdens” because they lack adequate ventilation for emissions from gas appliances, he said.

Hochschild made his remarks after hearing from dozens of environmental activists, physicians and residents who called for the CEC to require new buildings in California to be all-electric starting with the commission’s 2022 update to its building energy efficiency standards, which it plans to approve next year. Many of the speakers cited health impacts associated with methane emissions.

Local Electrification Measures

Cities and counties can pass ordinances that exceed the 2019 standards with the CEC’s approval. Nearly three dozen local governments have done so by requiring new or existing buildings to have electric furnaces, water heaters and cooktops in place of gas appliances.

San Luis Obispo was the latest city to adopt an electrification measure. On Wednesday, the CEC approved a city ordinance requiring all new buildings to be electric or, if using mixed fuels, to achieve heightened energy efficiency standards.

The CEC also approved a Davis city ordinance mandating rooftop solar and increased efficiency standards for high-rise and nonresidential buildings. State law already requires rooftop solar on new low-rise residential structures, though the CEC has approved exceptions to the rule. (See Calif. Energy Commission Relaxes Rooftop Mandate.)

Nearly all the public speakers at Wednesday’s hearing began by backing the proposed city ordinances but quickly segued into calling for statewide electrification rules.

SoCalGas Lawsuit

Hochschild acknowledged the comments and said the CEC would stay the course on electrification even though “now [the effort is] going to continue in court, because [Southern California Gas] elected to sue us … over this issue.”

SoCalGas, which serves nearly 22 million customers, filed a lawsuit in state court July 31 arguing that the CEC had failed to consider natural gas as a cleaner alternative to other fossil fuels, as it was required to do by a bill Brown signed in 2013.

“Natural gas and renewable gas are clean, affordable, resilient and reliable sources of energy on which millions of California consumers and businesses depend,” the company said in its lawsuit. “Natural gas has played a significant role in reducing greenhouse gas emissions and improving air quality, and natural gas and renewable gas remain critical to meeting California’s energy goals.”

The move was the latest pushback by natural gas companies concerned that California’s environmental and energy regulations will leave their assets stranded and worthless in the coming decades.

Senate Bill 100, signed by Brown in 2018, calls for load-serving entities to provide 100% carbon-free energy to retail customers by 2045. An executive order by Brown requires the state to achieve carbon neutrality by 2045.

In addition to legal challenges, gas companies are advocating for their pipelines to carry up to 30% hydrogen produced using excess renewable energy. (See NARUC Panel: ‘Green’ Hydrogen Could Lower GHGs.)

August 13, 2020

BPA Poised to Weather COVID Impact

The COVID-19 pandemic is having little impact on Bonneville Power Administration operations or financial health, with fiscal year 2020 net income projected to easily exceed a “bad case” scenario outlined last quarter, agency officials said Tuesday.

“Even though we’ve had some unusual times, with disciplined cost management and favorable market conditions, we are forecasting hitting all of our financial targets for this year,” CFO Michelle Manary said during BPA’s third-quarter business review (the federal power marketing administration follows an October-September fiscal calendar).

Having weathered a highly uncertain third quarter, BPA now forecasts fiscal year net income could hit $152 million, up sharply from a second-quarter “baseline” case prediction of $110 million and well above the pandemic worst-case figure of $44 million. The latest estimate also puts BPA far ahead of its rate case target of $12 million for the year, Manary noted.

While reduced expenses account for some of the increase, the largest share stems from a big boost in net operating income, which is predicted to ring in at $65 million, compared with the $8 million estimate in the second-quarter outlook.

“This increase comes from power [generation], with higher secondary sales” of surplus power, Manary said. “Secondary sales have benefited from higher market prices and a good runoff pattern. Shape is everything,” indicating that hydroelectric surpluses happened to coincide with intervals of higher demand.

“While we’re seeing local reductions with certain customers due to COVID-19, we’re seeing increases in other areas, with a net result of no drop in aggregate load,” she added.

BPA now expects its FY 2020 net income to hit $152 million, far exceeding the rate case figure of $12 million and a Q2 pandemic “bad case” scenario of $44 million. | *BPA*

BPA’s power generation business is expected to yield more than $2.76 billion in total revenues, compared with the rate case estimate of $2.71 billion. That business line is also projected to incur expenses of nearly $2.6 billion, about $65 million below the rate case, in part because of delays in fish and wildlife project work stemming from social distancing measures. An amortization accounting adjustment related to the Columbia Generating Station nuclear plant in Washington state will additionally reduce expenses from the rate case level.

“These reductions were partially offset by power purchases, which were higher than rate case due to higher spill conditions that took place this summer. We saw average inventory in water … but we’re spilling at higher levels,” Manary said.

BPA’s transmission business should take in revenues of about $1.085 billion, just a million shy of the rate case. At nearly $1.01 billion, transmission expenses are projected to be about $25 million below the rate case, “primarily driven by lower interest rates and capital spending,” Manary said.

The latest FY 2020 capital expenditure forecast of $613 million is below the second-quarter baseline forecast of $656 million (and well below the rate case estimate of $847 million), but “substantially higher” than the COVID-19 “bad case” of $412 million “due to a restart of our capital program in June. We basically saw only a $20 million hit from COVID throughout the capital program,” she said.

Last Waltz for Mainzer

BPA also took steps early this summer to relieve the economic burden on its customer base of publicly owned utilities, including suspending collection of a surcharge implemented last year to buttress its financial reserves. That move is expected to save those utilities a combined $3 million per month for the rest of this fiscal year and a total of $30 million next year.

“At Bonneville, we remain very sensitive to the economic challenges facing our customers — and the communities they serve — as a result of the pandemic,” BPA Administrator Elliot Mainzer said. “We truly understand the hardship and uncertainty that many of you are facing.”

Mainzer said BPA would also “streamline” the process by which its customer utilities can request payment extensions if they’re facing financial hardship from the pandemic.

“This is not a waiver of the bill, but it extends the payment out, with interest, for up to three years,” he said.

Mainzer noted that the “vast majority” of staff continue to work from home in light of the pandemic and will continue “to do so for the foreseeable future,” while field staff are ramping up their work “consistent with social distancing requirements.”

“While we have not had any interruptions to service delivery, the coronavirus numbers in our service territory have remained challenging, and we’ve asked our workforce to be ever diligent in protecting the health and safety of their co-workers and their families,” he said.

Tuesday’s quarterly review was the last for Mainzer, who will depart BPA at the end of August to take over the helm at CAISO in October. (See CAISO Names Bonneville Administrator as New CEO.)

“I hope you’ve found these meetings to be informative and useful as we’ve defined clear metrics for BPA’s business performance and hold ourselves accountable to you for delivering results,” Mainzer said. “I know that Michelle and our leadership team are committed to this process going forward and will stay connected as we evolve and progress together. I’d like to thank you for all of your support along the way.”

August 13, 2020

NYISO Proposes ICAP Demand Curve Reset Values

NYISO on Monday told stakeholders that it supports most of its consultants’ proposed parameters and assumptions for the installed capacity (ICAP) demand curves for capability years 2021/22 through 2024/25.

In their quadrennial review for the demand curve reset (DCR), Analysis Group and Burns & McDonnell recommended that General Electric’s 7HA.02 turbine be selected as the peaking plant for the ICAP demand curves for all of the state.

The consultants determined preliminary reference points — which equal the clearing price at 100% of the minimum capacity requirement — ranging from $7.74/kW-month for the New York Control Area (without selective catalytic reduction (SCR) emissions controls) to $21.36/kW-month for New York City, with SCR.

Capacity Market Design Manager Zachary Smith, who presented the draft staff recommendations to the Installed Capacity/Market Issues Working Group, said ISO staff are continuing to evaluate certain of the consultants’ recommendations, including the maximum clearing price, which is set at 1.5 times the estimated monthly value of the cost to develop a new peaking unit.

Both the reference point price and the maximum clearing price calculations require translating annual values into monthly values.

But while the translation of the annual reference value — also known as the net cost of new entry (CONE) — to the monthly reference point value uses a translation factor to account for excess conditions and seasonal differences in capacity availability, the factor is currently not applied when determining the monthly value of gross CONE.

As a result, NYISO said, there is a potential for the different methodologies to produce a reference point price that exceeds the maximum clearing price, with a greater risk of such outcomes in smaller regions. To avoid such an outcome, the ISO is considering whether to applying a translation factor in determining the monthly gross CONE value used to determine maximum clearing prices.

“Obviously, most of the focus in this process has been on the reference point; however, we are required to come up with a maximum price, as well as the zero crossing point [the point at which the value of marginal capacity declines to zero] for each locality and the NYCA,” Smith said.

Staff said they preliminarily agreed with the consultants’ proposed handling of scaling factors used to adjust the historic prices used for estimating net energy and ancillary services (EAS) revenues to the Tariff-prescribed level of excess conditions assumed for the DCR.

These scaling factors — the level of excess adjustment factors — did not take into account proposed retirements identified in compliance plans for the state Department of Environmental Conservation’s “Peaker Rule,” new NOx regulations that go into effect May 1, 2023. (See NY DEC Kicks off Peaker Emissions Limits Hearings.)

NYISO said it agreed with excluding the impact of the Peaker Rule because only four months of market prices impacted by the rule’s 2023 requirements would be used in the net EAS model. This would occur as part of the annual update for the 2024/25 capability year, for which the historic data period ends Aug. 31, 2023.

The ISO said applying Peaker Rule retirements to all years covered by the DCR “does not fairly reflect the expected system that will be reflected in the historic data periods used for determining net EAS revenue offset estimates for this period.”

MMU Review

Potomac Economics, the Market Monitoring Unit for the ISO, said it also supported most of the consultants’ methodology and recommendations but called for revising three assumptions that “are not supported by market data or reasonable economic considerations,” all of which result in inflating net CONE.

“This is particularly harmful at this time given that NYISO is substantially oversupplied, and inefficiently high demand curves will serve to impede efficient retirements and perpetuate the current capacity surpluses,” it said.
Potomac called for:

reducing the cost of debt to a range of 6 to 6.5% from the proposed 6.7%. The MMU said the rate should be “based on a broader view of the available data that does not overemphasize the recent COVID-19-related financial market turbulence.”
replace the fuel-procurement cost for the sale of operating reserves with a cost of $2/MWh for dual-fuel units, which it said “would more accurately reflect the fuel reservation costs of reserve providers in New York with oil backup that would not likely incur large gas-procurement costs when selling reserves.” Todd Schatzki of Analysis Group said that based on data provided by the MMU, the consultants agree with its recommendation to adjust the day-ahead cost of offering to provide operating reserves for dual-fuel units.
increase the amortization period to 20 years from 17, which it said was “unreasonably low and ignores publicly available information on how the power system will adapt to the zero-emission provision of the Climate Leadership and Community Protection Act.”

Kieran McInerney of Burns & McDonnell, who presented portions of the consultants’ interim final report, noted that they had seen a wide range of land lease costs in Zone J, used in developing the estimated CONE, but left those costs unchanged as the current assumption is within the observed range.

The consultants previously reviewed market transactions, property tax values and stakeholder feedback, and also considered quoted values obtained through discussions with property owners in the potential acquisition of land.

Stakeholders expressed concerns about modeling values for land lease costs having been adjusted for inflation only.

Timeline

NYISO staff will issue its final DCR report to stakeholders and the Board of Directors on Sept. 9. Stakeholders will have until Oct. 9 to provide written comments to the board, which will hear presentations and debate on Oct. 19. The ISO will file the approved outcomes with FERC by Nov. 30.