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December 13, 2019November 13, 2023

ERCOT Board of Directors Briefs: Dec. 10, 2019

AUSTIN, Texas — ERCOT’s Board of Directors on Tuesday approved price corrections for 21 operating days, dating back to September, that resulted from a series of software errors.

The board unanimously approved correcting day-ahead market prices for Sept. 16-23 and real-time prices for Oct. 16-20, 23-24, 26, 29-31, and Nov. 4 and 6.

Staff were able to correct several other operating days that were caught within two business days, as per ERCOT’s protocols.

“The volume of price corrections is not acceptable to ERCOT,” said Kenan Ögelman, vice president of commercial operations. “We have initiated a review of our practices … and changes we institute to software, to make sure we deliver to you the highest quality products.”

Ögelman said some of ERCOT’s vendors have committed to provide a better testing environment, “which is one of the ways we try to deliver quality and an error-free product.”

“It’s not the only thing,” Ögelman said, “but testing is important in delivering the product.”

The board determined that real-time prices were “significantly affected” by the software error. The Technical Advisory Committee in September debated “significance” as it applies to pricing errors, as some resettled amounts were in single digits. (See “Staff to Review Pricing Issues Following Software Errors,” ERCOT Technical Advisory Committee Briefs: Nov. 20, 2019.)

Ögelman said staff would work with stakeholders to better define the significance of price corrections.

“We believe this would reduce the incidents and the frequency of coming to the board,” Ögelman said, noting a protocol change will be likely.

ERCOT this week has already issued market notices listing the resettled prices for the Sept. 16-17 and the Sept. 18 –19 operating days.

Magness, Walker Recount NERC Presentations

ERCOT CEO Bill Magness and Public Utility Commission Chair DeAnn Walker briefed the board on their November presentations to NERC’s Member Representatives Committee, saying their update on the ability of the Texas grid operator’s energy-only market to meet record demand with a single-digit reserve margin was well received.

“It was an education opportunity. There are a lot of people who don’t operate markets like this,” said Magness, noting they had offered to make the presentations before the summer began. “That’s how confident we were.”

Walker said NERC CEO Jim Robb came up to her after the presentation and said, “We’ll see about next year.”

“I was like … here we go,” Walker said, rolling her eyes. “The other fascinating thing is I was there from 1 to 5:30 [p.m.] While they seemed to be concerned about ERCOT, not once did they mention the word ‘California.’”

During his CEO report, Magness said staff are projecting a $33.9 million positive budget variance for 2019, thanks to a $6 million favorable variance for expenses and an unexpected $19.2 million in interest income. ERCOT also reported a positive variance of $29 million in 2018, a result of “aggressive” interest rate assumptions set in 2017.

Magness told the board the variances will be set aside to fund the real-time co-optimization (RTC) project. Staff have said it will take four to five years and upward of $50 million to implement RTC, which procures energy and ancillary services simultaneously in the real-time market every five minutes to find the most cost-effective solution for both requirements.

The directors will get their first chance to vote on the RTC Task Force’s work during their February meeting. The team is developing a set of key principles that will guide the protocol changes to implement the process.

Magness said the board will get regular updates in 2020 from the RTCTF, the Battery Energy Storage Task Force and on distributed generation resources. ERCOT has temporarily limited interconnections of new DG projects while it develops rules and requirements.

Garza Delivers Final IMM Report

In her last report to the board, Independent Marker Monitor Director Beth Garza said real-time prices have dropped to last year’s levels, while natural gas prices have trended even lower, resulting in higher implied heat rates for generating units.

Garza said November’s heat rate was about 12 MMBtu/MWh, compared to 2018’s final rate of 11.1 MMBtu/MWh. ERCOT’s gas prices averaged $3.22/MMBtu last year but were down to about $2.50/MMBtu in November, she said.

Real-time prices dropped to about $30/MWh in November, Garza said. They averaged $50.90/MWh through October, an approximately 42% increase over last year’s average of $35.6/MWh. Prices averaged more than $160/MWh in August, thanks to spikes in scarcity pricing.

Garza closed her report by announcing she would be stepping down as the IMM’s director. (See related story, Garza Steps Down as Head of ERCOT IMM.)

ERCOT Members Gather for Annual Meeting

Magness welcomed members to ERCOT’s annual meeting, held after the board’s public session, by recounting the market’s growth since 2009, when he joined the grid operator as legal counsel. Smart meters have grown seven-fold, wind resources have gone from 91.6 MW to 22,428 MW, and the demand peak is expected to have grown from 63.4 GW to next year’s projected record peak of 76.7 GW.

“I remember when we got to 65,000 MW, we were like …” Magness said, grabbing the podium with both hands and ducking in faux fear. “Now, we’re helping ERCOT develop the best market in the world.”

Members celebrated the service of CPS Energy’s Carolyn Shellman and CenterPoint Energy’s Kenny Mercado, who cycle off the board at year-end with a combined nine years of experience. Austin Energy’s Jackie Sargent will replace Shellman in the municipal segment, while Oncor’s Mark Carpenter will step in for Mercado as the investor-owned utility’s segment representative.

Tenaska Power’s Keith Emery also joins the board as the independent power marketer’s segment representative. He replaces DC Energy’s Seth Cochran, who is taking Emery’s previous position as an alternate.

State Rep. Dade Phelan keynoted the annual meeting, celebrating what he called “no-opposition Tuesday” — reaching the Dec. 9 filing deadline for next year’s elections without an opponent.

As chair of the House State Affairs Committee, Phelan is responsible for legislation affecting the state’s utilities. He said when handed the chairmanship, he knew “plenty about ERCOT.”

“I was at Disney World [home of Epcot]. I saw all the resorts,” Phelan said to laughter.

Board Approves AS Methodologies, 14 Changes

The board unanimously approved staff’s proposal to not make any changes to the methodologies used to determine 2020’s ancillary service quantities and the representatives to the 30-person Technical Advisory Committee, which reports and makes recommendations to the board.

Based on feedback from stakeholders, ERCOT will compute responsive reserve service quantities with an updated resource contingency criterion of 2,805 MW.

The board also unanimously approved its consent agenda, which included 10 Nodal Protocol revision requests (NPRRs), a single revision to the Planning Guide (PGRR), two system-change requests (SCRs) and a Verifiable Cost Manual update (VCMRR):

- NPRR849: Clarifies the range of voltages at a generation resource’s point of interconnection and circumstances for which its reactive capability must be designed to meet.
- NPRR902: Defines ERCOT Critical Energy Infrastructure Information (ECEII), adds items that are considered ECEII, specifies the restrictions imposed upon parties that receive or create ECEII and provides a framework for the submission of ECEII to ERCOT.
- NPRR928: Defines “cybersecurity incident” and “cybersecurity contact,” classifying the former as protected information, and creates a form for notifying ERCOT of a cyber incident. The change also allows ERCOT to notify state or federal law enforcement of a cybersecurity incident and to notify market participants in order to mitigate further effects.
- NPRR937: Removes distribution-level and non-settlement metered block load transfers from deployment during Level 2 energy emergency alerts (EEAs).
- NPRR941: Creates a 138/345-kV trading hub for the Lower Rio Grande Valley, allowing additional trading liquidity and forward-price discovery in the area.
- NPRR957: Establishes the terms “energy storage system” (ESS) and “energy storage resource” (ESR). ESS is the umbrella term for storage assets. ESRs are ESSes eligible to participate in security-constrained economic dispatch and/or provide ancillary services. ESRs must be registered with ERCOT as both a generation resource and a controllable load resource.
- NPRR965: Excludes a quick-start resource’s five-minute intervals from the generation resource energy deployment performance calculation when the resource is engaging in the decommitment process or telemetering “shutdown” status.
- NPRR968: Updates protocol language to comply with NERC reliability standards BAL-002-3 (Disturbance Control Standard – Contingency Reserve for Recovery from a Balancing Contingency Event) and EOP-011-1 (Emergency Operations) by changing the physical responsive capability trigger for a Level 3 EEA to match a new most severe single contingency of 1,430 MW, to be implemented on Jan. 1, 2020.
- NPRR969: Clarifies ERCOT is the final authority in qualifying market participants.
- NPRR972: Gives ERCOT the authority to decline to open a transaction-adjustment period for a congestion revenue right auction, even if the transactions submitted exceed the limit announced prior to the auction, as long as the number of transactions submitted does not exceed the number that can be processed by ERCOT’s systems.
- PGRR071: Updates the Planning Guide to align with NPRR926, which removed the 90-day period between subsynchronous resonance study approval and initial synchronization and was approved by the board in June.
- SCR800: Incorporates DC tie-scheduled ramp into SCED by updating the resource limit calculator’s formula to determine the generation-to-be dispatched value and adding a scheduled five-minute DC tie ramp rate (DCTRR). The DCTRR will be calculated from the scheduled systemwide DC tie ramp multiplied by five and a configurable factor to capture the scheduled five-minute ramp.
- SCR805: Allows ERCOT to automatically provide certain reports to requesting transmission service providers (TSPs) before they are posted to the market information system public area. TSPs will receive the reports once a formal request has been approved by ERCOT.
- VCMRR025: Removes the ESR definition from the manual, aligning it with NPRR957.

— Tom Kleckner

December 13, 2019

CAISO Reports Wholesale Prices Way Down in Q3

By Hudson Sangree

CAISO’s Department of Market Monitoring reported significantly lower wholesale electricity prices in the ISO during the third quarter this year, driven by lower natural gas costs and fewer transmission constraints than in previous quarters.

“Market prices were very low relative to our historical Q3 prices and highly competitive,” Amelia Blanke, manager of monitoring and reporting for the ISO’s Department of Market Monitoring, told participants on a call Tuesday. “The big factors that were driving that were gas prices … higher renewables, particularly hydro, and low congestion.”

Average gas prices were down nearly 44% from the third quarter of 2018. That drove the cost of wholesale electricity down from $68/MWh to $39/MWh.

“That’s a dramatic reduction,” Blanke said.

CAISO Wholesale Prices — Total Q3 wholesale costs were down from Q3 2018. | *CAISO*

Volatile gas prices have been the major source of price spikes and decreases this year and last.

In the first quarter this year, a huge spike in natural gas costs drove up prices by more than 40% compared with the same period a year before, the DMM said. (See Gas Spike Drove High CAISO Power Costs in Q1.)

Average hourly hydropower production rose by approximately 2,000 MW in July compared to the same month a year before, according to the market presentation.

The comparative lack of major wildfires during the summer and early fall months, the start of California’s fire season, meant transmission lines weren’t down for extended periods.

“We had relatively few transmission-related outages causing congestion as well as low fires within Q3,” Blanke said.

Congestion revenue rights losses for ratepayers also continued to fall because of settlement changes and lower congestion, Blanke said.

Ratepayers have been covering big losses in the CRR auctions since they were implemented in 2009 because of the difference between revenues and payments to CRR holders, the DMM has found. The loss to ratepayers had reached $860 million as of late last year, the department said earlier this year.

The main beneficiaries have been financial entities that purchase the CRRs, betting on profits.

Changes implemented in January significantly reduced the number and pairs of nodes at which CRRs can be purchased in the auction. They also limited net payments to CRR holders when payments exceed congestion charges collected in the day-ahead market, CAISO said.

Payments have exceeded auction revenues in every quarter this year, including by $4.1 million in Q3, the DMM reported. In comparison, CRR auction payments outpaced revenues by approximately $180 million over Q4 2017 through Q4 2018.

December 13, 2019

NYISO Advances Change to Retirement Studies

By Rich Heidorn Jr.

NYISO’s Business Issues Committee on Tuesday endorsed the ISO’s plan to replace its ad hoc generator retirement studies with quarterly “short-term” analyses.

The new Short-Term Reliability Process (STRP) would address generator deactivations and other reliability needs, beginning with quarterly Short-Term Assessment of Reliability (STAR) studies, explained Keith Burrell, NYISO’s manager of transmission studies. Burrell said the change would ease the workload for ISO staff and transmission owners.

“We are about to start our 11th generator deactivation assessment this year,” he said. “Certainly, from a workload perspective, doing four instead of 11 looks awfully nice.”

The Tariff changes, which the ISO plans to file with FERC in February, also would expand the generator deactivation rules to non-market participants that have the “ultimate authority” over deactivations. Generators with a nameplate rating of 1 MW or less would be exempt.

NYISO retirement studies — Alliance Energy Group’s 55-MW Hillburn Power Plant in Hillburn, N.Y. | *Alliance Energy*

Zach Smith, vice president of system and resource planning, said “a core change” is that the biennial Reliability Needs Assessment (RNA), which has covered Years 1 through 10, will be narrowed to Years 4 through 10. The RNA, which evaluates resource and transmission adequacy and transmission system security, is the first of two studies done in the Reliability Planning Process (RPP). The RPP also includes the Comprehensive Reliability Plan, which evaluates market‐based solutions to the needs identified in the RNA.

The STRP and the RNA will include an overlap in assessing Years 4 and 5.

“You will have a short-term reliability process to address issues identified in the short term, and you will have the RNA, which is now essentially a long-term planning process,” Smith added. “My expectation is that within the RNA … that we document what the recent findings have been from the short-term reliability process.”

The STRP will conclude if the STAR does not identify a short-term need or finds that such needs will be addressed in the RPP. If the STRP does identify short-term needs, NYISO will issue a solicitation seeking solutions.

The ISO is proposing to pay costs in excess of $100,000 that a generator in an ICAP-ineligible forced outage (IIFO) incurs to repair or replace a damaged step-up transformer or other system protection equipment if the equipment is needed to address an immediate STRP need. Such generators would not be reimbursed for repairs of less than $100,000.

One other change: “Today, when a generator completes its notice to deactivate, a study period is 365 [days] plus five [years],” Burrell said. Under the new rules, “it’s 365 [days] plus four [years], so it’s a five-year study … instead of a six-year study.”

The units, many of which are counted on to maintain transmission security in load pockets, typically run on hot summer days when ozone readings are high. Many of the units are inefficient and nearing 50 years of age, making them poor candidates for the installation of after-market controls. The second phase of the ISO’s 2018/19 RPP is evaluating the reliability impacts of the retirements of all 3,300 MW.

The proposed DEC rule, which it expects to finalize within several weeks, would phase in compliance obligations between 2023 and 2025.

Smith said the peaker rule was part of the motivation for the proposed changes. “I’m nervous that our current process wouldn’t be able to handle the change fast enough,” he said.

The BIC unanimously recommended Management Committee and Board of Directors approval of the STRP. The ISO will seek a May 1, 2020, effective date, with the first STAR beginning July 15 and results expected by October.

Relocating the IESO Proxy Bus

Rana Mukerji, senior vice president for market structures, also briefed the BIC on plans to relocate the proxy bus used for scheduling transactions with Ontario’s Independent Electricity System Operator (IESO).

NYISO’s market software currently uses the Bruce 500-kV bus, but an analysis of the transactions between IESO and NYISO indicates that moving the bus “may better align the power flow results with real-time operations,” Mukerji said.

He said NYISO will pursue a move to the Beck 220-kV bus next year.

December 12, 2019

MISO Avoids Fall Emergencies

By Amanda Durish Cook

INDIANAPOLIS — MISO avoided maximum generation alerts and events this fall despite dealing with record-breaking temperature swings in its southern footprint.

The RTO’s nearly 107-GW fall peak on Sept. 11 was “well below” the forecasted 112-GW peak for the season, MISO Executive Director of System Operations Renuka Chatterjee reported to the Markets Committee of the Board of Directors on Tuesday. This year’s fall peak also paled compared with 2018’s almost 115-GW record.

Real-time prices were likewise down, averaging $25/MWh, a 23% decrease year-over-year. Chatterjee put lower prices down to “surging” natural gas production.

However, the modest peak and prices belie the volatility in fall temperatures, with hot weather alerts in the southern parts of the footprint in early September and October, followed by a cold weather alert by mid-November.

MISO Fall Emergencies — Markets Committee of the MISO Boad of Directors | © *RTO Insider*

“Both of these weather events brought record-setting temperature swings in our footprint. I’ve heard that close to 100 temperature records were broken,” Chatterjee said of a hot weather alert Sept. 5-9 and a cold weather alert Nov. 12-13, both in MISO South.

MISO President Clair Moeller said operations teams showed “exemplary” performance in handling both situations.

Chatterjee said “unseasonably extreme cold” settled in the Central and South regions during the November event. “If these temperatures happened in January, we wouldn’t be talking about them,” she said.

She said MISO control room employees were busy managing congestion and responding to outages on Nov. 13.

MISO was able to avoid issuing a maximum generation event this fall, though Chatterjee said conditions in MISO South would have warranted it for about 30 minutes on Nov. 13.

“In hindsight, we could have issued that notification for a short time,” Chatterjee said.

Last fall, MISO entered a maximum generation event in mid-September. (See MISO in Conservative Ops After Emergency Declaration.)

Tricky Mid-November

MISO Independent Market Monitor David Patton called the conditions on Nov. 13 “bizarre.” He said Little Rock, Ark., registered at 19 degrees, about 30 degrees below normal. He also said a large MISO South generator kept delaying its start time during the day, losing out on roughly $1 million worth of payments in the process and complicating the supply picture.

Patton also said his staff is still investigating a request from SPP to cut MISO flows on the regional dispatch limit that day to 1,500 MW, resulting in additional congestion costs of $876,383 to MISO. MISO neighbors Southern Company and SPP were also facing challenging supply conditions Nov. 13, Patton said.

“What happens when we derated this, not only did it cost MISO and its customers a lot of money, but it also caused MISO to violate a constraint in MISO South,” Patton said.

Patton said if MISO were granted “better visibility of neighbors’ constraints” in real-time, it might have been able to provide targeted relief instead of simply following SPP orders to “massively derate” the flows.

Patton said MISO operators likely didn’t have an appropriate amount of time to react to SPP’s request.

“MISO was put in the position of having to derate the [Regional Dispatch Transfer] and wasn’t able to offer alternative solutions. When they’re asked to derate due to reliability concerns, you have to,” Patton explained.

“This has seemed to blow the cover off areas that we don’t have much progress on. We don’t have visibility into our neighbors’ decisions, and they might not have visibility into our decisions, and that’s costing economic decisions,” MISO Director Barbara Krumsiek said.

Patton also said he continues trying to convince MISO’s transmission operators to adopt dynamic transmission line ratings. He also said MISO should “more actively” validate transmission ratings. He said the suggestion would likely make it into his 2019 State of the Market Report.

MISO Enters Winter

Chatterjee said MISO continues to expect a 104-GW winter peak, with about 115 GW worth of resources on hand to mitigate it. She said MISO is especially concentrating winter preparations on outages. Over the last five years, MISO experienced an average 27 GW worth of generation outages on monthly peak hours December through February.

Moeller said many of the outages occur in MISO’s older, steam generation.

“We’re seeing outages of the older, steam fleet continue. In many cases, they’re aging so [operators see] no reason to put money in them,” Moeller said.

This is the first winter MISO will use a $1,000/MWh soft cap and a $2,000/MWh hard cap on energy offers after MISO Files Offer Cap Revisions Ahead of Schedule.)

Additionally, MISO in November began publis hing a first edition of its multiday operating margins, which predicts supply conditions six days in advance. The multiday forecast is for informational purposes only and is not a multiday financial market.

December 12, 2019March 12, 2025

Advanced Metering Tops 50% for First Time

By Rich Heidorn Jr.

Advanced meters now represent more than half of the electric meters in service, but the growth of demand response has been choppy due to slow adoption of time-of-use rates, FERC reported Wednesday.

The U.S. had 78.9 million advanced meters operational in 2017, 51.9% of the total of 152.1 million meters and an increase of five percentage points from 2016, FERC reported in its 14th annual report on DR and advanced meters. The annual report was mandated by Congress in the Energy Policy Act of 2005.

Between 2007 and 2017, the number of advanced meters in operation jumped almost twelve-fold and now dominate in five NERC regions: Texas RE (90%); SPP RE (63%); the Western Electricity Coordinating Council (61%); the former Florida Reliability Coordinating Council (58%) and ReliabilityFirst (55%).

Advanced meter growth (2007–2017) | FERC, Energy Information Administration, Institute for Electric Efficiency

In the last year, FERC reported, utilities in Arkansas, Hawaii, Indiana, Minnesota and New Jersey have proposed or received approval for deploying advanced meters, seeking to improve customer engagement, reduce outage duration and create a foundation for other grid modernization efforts.

Commission staff noted regional differences in advanced meter penetration, with residential customers at higher penetration levels than commercial or industrial customers in most regions. In FRCC, Hawaii, the Midwest Reliability Organization and the Northeast Power Coordinating Council regions, however, advanced meter penetration is highest in the industrial sector.

Overall, advanced meter penetration rates for residential and commercial customer classes were at or above 50% for the first time in 2017, while penetration for industrials grew to 44.5%.

Time-of-Use Rates

But while advanced metering has become more ubiquitous, policymakers have been slow to embrace the technology’s capabilities. The report identifies the “relatively slow implementation of time-based rate programs” as a main cause of lackluster customer participation in demand response.

Nationwide, enrollment in time-of-use (TOU) rate programs has increased by 42% since 2013, with retail customer enrollment increasing by about 7% in 2016/17. But only 8.5 million customers nationwide have TOU rates, 75% of them in ReliabilityFirst and WECC.

Penetration rate and number of advanced meters by region (2013–2017) | FERC

Regulators in New York and North Carolina have ordered their utilities to expand time-based rates to reduce peak demand and leverage their metering investments. Regulatory commissions in Maryland, Michigan, Minnesota, and the District of Columbia have adopted or are exploring time-based rates for electric vehicles to incentivize charging during off-peak hours.

Demand Response

Demand response statistics showed some advances and some retreats.

Potential peak demand savings from residential programs — the total demand savings that could occur at the system peak hour if all demand response was called — dropped by 12% to 31,508 MW from 2016 and 2017, with the biggest reductions in SPP RE (due to lower reported savings by Oklahoma Gas and Electric) and WECC (with large decreases reported by Salt River Project and Southern California Edison). The report said the drop in WECC “likely reflects a shift toward greater demand response participation in CAISO’s wholesale market.”

Demand response participation in the wholesale markets increased by about 8% from 2017 to 2018, to a total of 29,674 MW, with the biggest increases in CAISO and MISO but decreases in ISO-NE and PJM, which have tightened requirements for capacity resources. The registration of DR in wholesale capacity, energy and ancillary services markets grew to 6% of peak demand in 2018.

Potential peak demand savings (MW) from retail demand response programs by region (2013–2017) | FERC

ISO-NE reported a 48% drop in DR participation from 2017 to 2018, which the report noted “coincides with the implementation of ISO-NE’s Pay-for-Performance program, which places more stringent requirements on [capacity] resources,” including DR.

PJM reported a net decrease of 226 MW (2.4%) in DR enrollment from 2017 to 2018, which the commission said “may be due to the continued phasing out of legacy demand response products” as the RTO completed its transition to an annual Capacity Performance product with tougher penalties for non-performance.

ERCOT, MISO, CAISO and PJM each deployed emergency demand response in 2019:

ERCOT reduced load by about 3,100 MW on Aug. 13 and 1,800 MW on Aug. 15 by deploying emergency response service (ERS) after high demand, reduced wind production and generation outages left the region short of its 2,300-MW reserve threshold. (See ERCOT Survives Another Day in the Ro a ster.)
MISO activated load modifying resources (LMRs) on Jan. 30, during an energy emergency alert Level 2 emergency in its Central and North regions. The RTO’s market monitor predicts DR will be deployed more frequently as the region’s capacity surplus decreases. (See MISO Maintains Relia b ility Through Arctic Midwest Temps.)
CAISO issued a statewide “flex alert,” calling for voluntary conservation on June 11, and some utilities declared critical peak pricing days — boosting prices temporarily — for retail customers several times during the summer.
PJM called on interruptible customers in the American Electric Power, Baltimore Gas & Electric, Dominion and Potomac Electric Power Co. zones to reduce load on the afternoon of Oct. 2, when the RTO’s demand exceeded 126,000 MW, its second-highest October demand on record.

December 12, 2019

FERC OKs ISO-NE RFP Rules

By Rich Heidorn Jr.

FERC on Tuesday approved Tariff revisions refining ISO-NE’s rules for conducting competitive transmission solicitations, a process that may be tested for the first time this month (ER20-92).

The changes increase the information to be provided by transmission developers and provide more detail on the evaluation criteria the RTO will use.

ISO-NE plans to issue its first competitive transmission solicitation — for solutions to non-time sensitive needs identified in its 2028 Boston Needs Assessment Update and Needs Assessment Addendum — as soon as this month. The request for proposals (RFP) will address transmission facility overloads under peak load conditions in the Boston area and system restoration concerns with the underground cable system in the area. (See “Needs Update Reduces Thermal Violations” in ISO-NE IDs $8 .7M Tx Fix for Boston Area.)

ISO-NE request for proposals — 115-kV transmission and above in Boston area | *ISO-NE*

Two-Step Process

The RTO will use a two-step process, with developers first submitting plans describing a project’s interconnection to the existing transmission system, estimated costs, financing and any cost containment measures.

ISO-NE will review the proposals, with input from the Planning Advisory Committee (PAC), to ensure they address the identified needs and are feasible and cost competitive. The RTO will then identify finalists who will be required to provide additional details to guide its selection of the preferred solution.

The RTO also created a new pro forma agreement between it and the selected qualified transmission project sponsor (QTPS) spelling out the development, design and construction of the project, including project milestones, status reports and cost containment measures. The RTO’s agreement is modeled on the designated entity agreement PJM uses in its competitive transmission solicitation process.

The changes also include a clause allowing the RTO to cancel an RFP if new assumptions modify or eliminate the identified need.

Outside the Scope

The commission dismissed as outside the scope of the proceeding the Connecticut attorney general’s protest arguing that while the RTO’s proposals are an improvement, they are insufficient to ensure truly competitive procurements and thus not compliant with Order 1000. The AG contends the process does not adequately consider non-transmission alternatives (NTAs), such as battery storage and transmission line ratings, and asked the commission to order RTOs to report annually or biannually on their adoption of NTAs or other grid management options.

The Massachusetts Attorney General asked FERC to determine ways to improve the ability of NTAs to compete with traditional transmission solutions.

Transmission developer New England Energy Connection (NEEC), an affiliate of LS Power, asked the commission to encourage ISO-NE to establish a stakeholder process to address broader issues in the competitive solicitation process after the 2019 RFP.

NEEC sa i d an “over-reliance on the immediate need designation” is a significant factor in the lack of competitive windows in New England to date and the region should consider replacing its sponsorship model with competitive bidding.

FERC said the Massachusetts and Connecticut proposals were outside the scope of the proceeding because the proposed Tariff changes don’t address NTA participation.

“Although we find that NEEC’s request to encourage ISO-NE to establish a stakeholder process to address broader issues in the existing transmission competitive solicitation process is also outside the scope of this proceeding, we note ISO-NE’s intention to hold stakeholder discussions following the 2019 RFP to consider additional changes to the competitive solicitation process,” FERC wrote.

ISO-NE spokesman Matt Kakley said the RTO does not have a firm date for release of the RFP, “though we are hoping to get it out this month.”

December 10, 2019

Garza Steps Down as Head of ERCOT IMM

By Tom Kleckner

AUSTIN, Texas — Beth Garza announced Tuesday she will step down as director of ER C OT’s Independent Market Monitor, a position she has held since 2014.

Garza broke the news during her bimonthly report to the ISO’s Board of Directors, telling stakeholders, “My time as director of the IMM has come to an end.”

She told RTO Insider it became evident to her that Texas’ Public Utility Commission, which has oversight of the IMM, wanted someone else to fill the director’s position.

“I support the commission’s decision to have the IMM director they want,” she said. “I’m disappointed that I’m not the person for that role.”

The PUC, ERCOT and Potomac Economics, Garza’s employer for 11 years, are all parties to the IMM’s contract. However, that four-year contract expires at the end of the year.

The PUC requested proposals for a new contract and is currently in negotiations, with the hope of reaching an agreement before the end of year, said Andrew Barlow, the commission’s external affairs director. Potomac Economics is among those bidding for the new IMM contract.

Garza said the PUC would be “willing” to award the contract to Potomac Economics but with the understanding she needed to be replaced. She hinted at disagreements between the PUC and the IMM.

“There’s a built-in tension between the commission’s role to provide oversight and direction to the IMM and the IMM’s role to provide independent analysis,” Garza said. “That tension interacts squarely at the director’s position.”

ERCOT directed media inquiries to the PUC, which did not offer comment beyond Barlow’s.

Potomac and Garza have been fierce advocates of real-time co-optimization. The PUC earlier this year directed ERCOT to implement the market tool, which procures both energy and ancillary services every five minutes to find the most cost-effective solution for both requirements.

Garza said she would remain at Potomac in a non-public role.

The Washington, D.C.-based firm also provides market monitoring for ISO-N E, M I SO and NY I SO.

December 10, 2019

PJM Operating Committee Briefs: Dec. 10, 2019

PJM said it was a quiet operations month in November with zero spinning events, nine post-contingency local load relief warnings (PCLLRWs) and one reserve sharing event with the Northeast Power Coordinating Council (NPCC).

The load forecast error came in at 2.22% — well below the 3% margin and a far cry from the unsolved load deviation witnessed during the first two days of October. (See “DR Load Forecast Error Unsolved” in PJM OC Briefs: Nov . 12, 2019.)

PJM’s 2019 Load Forecasting Error margin (Achieved 80% of the time)| *PJM*

Fall Restoration Drills

PJM sa i d its fall restoration drills conducted between Sept. 25 and Oct. 30 went well, with only minor complaints about the simulator and event duration.

Some 143 companies and 52 PJM operators participated. All of the RTO’s nuclear plants received off-site power under the four-hour deadline with one exception, due to simulator issues.

Companies said the drill should last two days and requested more practice on cross-zonal procedures. The simulator itself took some getting used to, Brian Lynn told the Operating Committee on Tuesday.

The spring drills are scheduled for May 19 and May 20.

Manuals Endorsed

The committee endorsed:

Manual 38: Operations Planning — Periodic revie w to conform NERC standard references, remove the PJM-NYISO seasonal operating study and update Attachments A and B.
Manual 14-D: Generator Operational Requirements — Re m ove references to PJM’s Tariff regarding the definition of “generating facility.” The term is not defined in the Tariff, pending a ruling on FERC Order 845 compliance.

—Christen Smith

December 10, 2019

MRO Member and BOD Briefs: Dec. 5, 2019

ST. PAUL, Minn. — Below is a summary of actions taken at the Midwest Reliability Organization’s (MRO) Annual Member and Board of Directors Meeting last week.

Approvals and Appointments

The members:

Endorsed NERC’s revised ERO Enterprise Long-Term St r ategy as shared at the Member Representative Committee in November. (See Strategy Plan Prompts ‘Cost-b e nefit’ Disc u ssion at MRC.)
Revised the name of the Organizational Group and NERC Representative Oversight Committee to Organizational Group Oversight Committee.
Updated Policy and Procedure 1 regarding MRO Independent Directors’ removal of outdated language. It also raises the annual retainer from $56,500 to $79,625 while eliminating the $6,000 annual retainer per committee.
Revised MRO’s General Finance Policies to define intangible assets and the procedure for carrying them on the balance sheet. The change was suggested to all regional entities by NERC, with the goal of encouraging a low debt-to-asset ratio.

In addition, members voted to appoint Lam Chung — currently vice president and engineer of strategy, innovation and finance – as treasurer, thrift savings plan trustee and corporate compliance officer effective Dec. 5, replacing Ken Gartner. The Board of Directors agreed to elevate current Vice Chair Thomas Kent from Nebraska Public Power District to Chair effective Jan. 1, replacing Silvia Mitchell of NextEra Energy. Kent’s role will be filled by Brad Cox of Tenaska Power Services.

MRO Praised for Security Work

NERC Chair Roy Thilly praised MRO for taking a proactive approach to security, singling out the Security Advisory Council (S A C), established this year, as a particularly valuable resource. The SAC advises MRO’s Board of Directors, staff and registered entities on cybersecurity; physical security; and SCADA, EMS, substation and generation control systems; and promotes awareness of these subjects.

MRO — Roy Thilly, NERC | © *ERO Insider*

The SAC’s information-sharing functions are of particular interest to NERC, given the decision earlier this year to merge NERC’s Operating, Planning and Critical Infrastructure Protection committees into a new panel, tentatively called the Reliability and Security Technical Committee (RSTC). (See NERC Board O K s Committees Merger.) A group like the SAC can help to fill any gaps left by the dissolution of the existing committees while the new group starts up, Thilly said.

“I get feedback from [NERC CEO Jim Robb] and from the [Electricity Information Sharing and Analysis Center] that they really like that model as a way of engaging the regions on the cyber issue, which has been difficult,” said Thilly. “I know Jim would like to see [that model] replicated in the other regions. So, thank you for that, and help us do that because with CIPC going away, there’s a forum function and information sharing function … that need to be captured.”

McMullen Honored on Retirement

MRO CEO Sara Patrick called on members to recognize Michael McMullen, the director of regional operations at MISO, who will retire this year after 13 years of service. McMullen was the inaugural chair of MRO’s operating committee and currently serves on the Reliability Advisory Council, formed earlier this year. In addition, he has served on several technical committees and groups at NERC.

MRO — Michael McMullen, MISO | © *ERO Insider*

“He was instrumental in standing up the operating committee and remained a committee member, providing leadership and technical guidance, for its eight-plus years of existence,” Patrick said. “We sincerely appreciate Mike’s dedication and contributions to the success of MRO and reliability of the bulk power system.”

Thanking the members for their recognition, McMullen said it was a pleasure to have served in MRO and he was confident in the organization’s work going forward.

“I think my biggest vote of confidence is that in my next stage, I do not own a generator and I do not plan on getting one,” McMullen said. “I know that we’ll remain reliable.”

MRO’s next board meeting will be held in St. Paul on April 1-2.

— Holden Mann

December 9, 2019

NEPOOL Participants Committee Briefs: Dec. 6, 2019

Senators Ask ISO-NE to Heed States on Clean Energy.)

In his Nov. 21 response, van Welie noted the region’s efforts to integrate energy efficiency and demand response into the wholesale markets and addressed the senators’ concern that the Energy Security Improvement (ESI) market design project “further delays market reforms that recognize and facilitate state public policies to grow clean energy and address climate change.”

Van Welie said that although the ESI would benefit generators with stored fossil fuel, it could also provide opportunities for solar facilities with battery storage “or an offshore wind farm that operates at a high capacity factor during winter.”

“Rather than delaying the transition to a renewable future, ESI may actually accelerate the transition to reliable, zero-carbon renewable resources and storage technologies by recognizing and compensating these resources for the reliability attributes they provide,” van Welie wrote.

NEPOOL — Price-responsive demand (PRD) energy market activity by month | *ISO-NE*

PC Chair Nancy Chafetz cut short the ensuing discussion, assuring stakeholders that they would have ample opportunity to voice their opinions at NEPOOL Technical Committee meetings over the coming months.

The PC also received a briefing from ISO-NE Director Brook Colangelo on the RTO’s cybersecurity work and its participation in last month’s GridEx V exercise. (See GridEx V Throws New Tech Curveball.)

COO Vamsi Chadalavada apologized for a computer glitch on Nov. 3 that caused the submission window for external transactions to close at 9 a.m. instead of 10 a.m.

The problem was due to a software error related to the daylight saving time transition, he said.

A new eMarket application had been placed in service Oct. 23, and a few participants could not enter or modify external transactions after 9 a.m. on Nov. 3, though the application performed as expected for all other supply offers and demand bids.

The day-ahead market was cleared with the offers and bids as of 10 a.m., per normal schedule, and the issue was fixed by early afternoon, Chadalavada said.

One stakeholder suggested that the RTO have extra staff on hand when transitioning to new software, just in case customers need service.

Natural Gas Prices Double from October

Chadalavada reported the energy market value for last month was $284 million, through Nov. 25, up $82 million from October 2019 and down $319 million from the same month a year ago.

Natural gas prices doubled from October to November, helping push average real-time hub LMPs to $35.52/MWh, up 74% from the prior month.

However, natural gas prices and LMPs were down 46% and 36%, respectively, from November 2018.

Average day-ahead cleared physical energy during the peak hours as a percentage of forecasted load was 99.6% during November, up from 98.8% during October, with the minimum value for the month of 95.7% posted on Nov. 8.

Daily uplift, or net commitment period compensation (NCPC) payments, in November totaled $3.3 million through the 25th, up $600,000 from October and down $1.3 million from the same month last year.

NCPC payments over the period were 1.2% of the energy market value.

Committee Officers Elected, Appointed

The Participants Committee re-elected Chafetz (Customized Energy Solutions); Vice Chairs Calvin Bowie (Eversource Energy), David Cavanaugh (Energy New England), Douglas Hurley (Synapse Energy Economics) and Tom Kaslow (FirstLight Power Resources); Secretary David Doot (Day Pitney); and Assistant Secretary Sebastian Lombardi (Day Pitney). In addition, Michael Macrae, energy analytics manager for Harvard Dedicated Energy, was elected vice chair representing End Users. He replaces Liz Delaney, who stepped down after leaving the Environmental Defense Fund to become director of wholesale market development for Borrego Solar.

ISO-NE appointed Mariah Winkler to serve as the new chair of the NEPOOL Markets Committee. Winkler has 10 years of experience in the Forward Capacity Market and led the Reliability and Transmission committees through discussions on issues such as FCM fuel security reliability reviews and competitive transmission solicitations.

The RTO appointed Emily Laine to replace Winkler as the new chair of the Reliability and Transmission committees. Laine also serves as secretary of the Demand Resources Working Group.

After 17 years serving the MC, most recently as chair, Alex Kuznecow will now serve as chair of the NEPOOL Working Groups.

2020 Budget

The PC unanimously approved a 2020 budget of $6,365,000 for NEPOOL, up $90,000 (1.4%) from 2019’s spending plan. NEPOOL expects to spend $6,625,000 by the end of this year, $350,000 above the approved budget. Most of the increase stems from $340,000 in above-budget spending for Day Pitney’s counsel fees, an 8.6% exceedance. Independent financial adviser fees and disbursements were $5,000 over budget (12.5%), and committee meeting fees were $30,000 more than planned (4.4%). They were partially offset by $25,000 in savings on the Generation Information System (-2.9%).

Consent Agenda

The PC unanimously approved the Reliability Committee’s recommendation to revise ISO-NE Operating Procedure No. 2 to incorporate a new reference document and clarify the RTO’s role in approving the scheduling of planned equipment maintenance and outages.

It also approved the Markets Committee’s recommendation to change Market Rule 1 to sunset the fuel security reliability review provisions following Forward Capacity Auction 14, one year earlier than currently planned. The RTO said the review will not be necessary for FCA 15, when the ESI design is expected to be in place.

Litigation Report

Doot highlighted a few items from the monthly litigation report, including that Storage Plans Clear FERC with Conditions.)

That compliance filing is due Jan. 21. Requests for rehearing of FERC’s order are due by Dec. 23.

Doot also mentioned the commission’s Notice of Inquiry in March for comments on whether it should change its method of calculating returns on equity for electric transmission and natural gas and oil pipelines (PL19-4). The proceeding has produced splits between transmission owners and load interests, as well as calls for new policies to increase the efficiency of existing lines and mandates on interregional planning. (See Tx Incentives NOI Brings Calls for Broader Reforms.)

He also drew attention to the D.C. Circuit Court of Appeals’ ruling Thursday indicating it will reconsider its precedent that allows FERC to issue “tolling” orders to indefinitely delay action on requests for rehearing. (See related story, DC Circuit to Reconsider FERC Tolling Orders.)

— Michael Kuser