Page 1028 – RTO Insider

December 15, 2019

MISO Board of Directors Briefs: Dec. 12, 2019

INDIANAPOLIS — MISO’s Board of Directors will remain unchanged heading into 2020 after the same chairman and three incumbent directors were elected to retain their positions at last week’s final Board Week of the year.

RTO members voted for Todd Raba, Trip Doggett and Barbara Krumsiek to remain on the board through the end of 2022. (See MISO Board of Directors Briefs: Sept. 18, 2019.)

Reporting results at the board’s meeting Thursday, MISO General Counsel Andre Porter said of 146 eligible voting members, 84 cast votes, easily passing the 25% voting participation quorum. Voting was held Sept. 1 through Nov. 26.

This year, the board also filled exiting Director Thomas Rainwater’s vacant seat with former New York Power Authority CFO Robert Lurie, who appeared at Board Week.

The meeting also saw directors vote unanimously to re-elect Phyllis Currie to a second year as their chairman.

“I tell a lot of my California colleagues that they could learn a lot by how MISO engages with stakeholders,” Currie said, accepting the position.

She opened the meeting by reminding staff and members of the RTO’s compliance hotline, where individuals can privately report suspected unlawful, unethical or inappropriate behavior.

In the latter half of 2020, MISO will hold a nomination and election to replace Director Baljit Dail, who has already exceeded his three-term limit; the Nominating Committee in 2017 waived his limit and allowed him to stand for an additional term. At the time, the committee cited MISO’s multiple new directors and Dail’s much-needed information technological experience as the reason for the waiver. (See “Committee Permits Consideration of Extra Term for Dail,” MISO BoD Briefs: June 22, 2017.)

Private Cloud Prepped for New Market Platform

MISO is wrapping up the third year of a seven-year effort to replace its market platform, this year establishing a private cloud-based server that will host the new platform’s modular server.

“We continue to accept market deliverables and find them acceptable,” Senior Director of Market System Enhancements Kevin Sherd told directors at a Dec. 10 meeting of the board’s Technology Committee.

Chief Information Security Officer Keri Glitch said MISO is still running two environments while it learns and discovers efficiencies in the cloud.

MISO will have spent about $20 million on the platform replacement this year, about $500,000 below budget because of a later-than-expected Storage Plans Clear FERC with Conditions.)

The RTO next year plans to make the cloud operational and test it using non-critical infrastructure protection data. By year’s end it will test the new market user interface with customers and begin uploading operations model data into its model manager, which is designed to be a singular repository for its many planning models.

The tasks are the major highlights of MISO’s 2020 to-do list. Vice President of Market System Enhancements Todd Ramey has said the RTO has about 200 deliverables it must complete over the year as part of the project.

“Two-thirds of the work is still in front of us,” said Ramey, who also reassured board members that MISO is “encouraged” by main vendor General Electric’s recent performance.

“We’re trying to be cautious and not too optimistic because … a lot of challenges lay before us,” he added.

MISO expects to introduce its new day-ahead market clearing engine on the private cloud in 2022.

Meanwhile, the RTO reported that it blocked 8.1 billion connections into its systems year-to-date in 2019, a 54% increase from last year. It also reported it had a 2.15% average click rate on phishing attempts in 2019, below the 5.3% industry average.

Glitch also said that over Aug. 22-26, MISO’s energy management system (EMS) experienced multiple slowdowns while trying to access its network-attached storage. “File transfer between EMS and market systems was interrupted during these slowdowns,” Glitch reported.

Glitch said that while MISO largely cleared up the problem, smaller, infrequent slowdowns persist. She said a small, dedicated team is working to identify the root cause of the problem.

MISO Slightly Overbudget in 2019

MISO expects to spend nearly $274 million in base operating expenses by year-end, exceeding its 2019 budget by about $1.3 million (0.5%).

CFO Melissa Brown said the overage is the result of MISO reclassifying some capital expenses as operating expenses.

MISO’s capital spending will likely reach $23.6 million, underbudget by $600,000 (2.7%).

The RTO has set a $337.6 million total operating budget and a $30.4 million capital expense budget for 2020.

MISO: We’re Going to Disney World!

MISO will break with tradition in 2020, holding its final Board Week of the year outside the footprint in Orlando, Fla., instead of near its headquarters in central Indiana.

MISO released a schedule of 2020 quarterly board meeting dates:

March 24-26 in New Orleans;
June 16-18 in Milwaukee;
Sept. 15-17 in St. Paul, Minn.; and
Dec. 8-10 in Orlando.

— Amanda Durish Cook

December 13, 2019

NERC Plans Review of Supply Chain Standards

By Rich Heidorn Jr.

NERC announced Thursday it will conduct a formal review of the effectiveness of its new supply chain standards, which take effect July 1.

Howard Gugel, NERC’s vice president for engineering and standards, outlined the plan during the Board of Directors’ conference call Thursday, at which the board also approved its 2019 Long-Term Reliability Assessment and the revised ERO Enterprise Long-Term Strategy.

NERC Supply Chain Standards — Howard Gugel, NERC | © *ERO Insider*

Gugel said NERC plans to report on its findings to the board after the first two years of the standards’ implementation.

The critical infrastructure protection (CIP) standards — CIP-013-1 (Cyber Security – Supply Chain Risk Management), CIP-005-6 (Cyber Security – Electronic Security Perimeter(s)) and CIP-010-3 (Cyber Security – Configuration Change Management and Vulnerability Assessments) — were developed in response to FERC Order 829, issued in 2016.

The commission approved the standards, intended to mitigate supply chain risks in industrial control system hardware, software, and computing and networking services, in 2018. (See FERC Finalizes Supply Chain Standards.)

Gugel said ERO staff will conduct surveys on supply chain awareness and collect statistics on identified “key risk indicators,” including software validation discrepancies, vendor vulnerability and cybersecurity incidents.

NERC will examine supplier contracts to determine whether entities have been able to negotiate language that includes required supply chain controls and analyze supply chain training and communications, including inquiries to the Electricity Information Sharing and Analysis Center (E-ISAC), to determine how well vulnerabilities have been identified and communicated.

Gugel said staff will make periodic reports to the Reliability and Security Technical Committee, and its formal report to the board could include recommendations for improvements to the standards.

“Every time I hear a presentation about supply chain risk, I am impressed with the complexity of this challenge and how important it is, so I think following through on the effectiveness review is really important,” Chair Roy Thilly said.

In response to Thilly’s question, Gugel said staff will look at how consistently the standards are being enforced and how facilities are characterized for application to the rules.

“I agree with your analysis” of supply chain issues, he told Thilly. “It seems like an onion. Every time we go to it, there’s another skin that needs to be peeled back.”

Trustee Jan Schori asked for interim reports on staff’s findings. “It’s also a very high visibility issue; people are extremely interested in it,” she said. Two years “seems kind of long to me.”

“Yes. We could absolutely do that,” Gugel responded.

Strategy Update OK’d

The board approved a revised ERO Enterprise Long-Term Strategy, which was last updated in 2017. NERC said the revisions were part of an effort to streamline its strategic and operational documents and ensure alignment with the Reliability Issues Steering Committee’s identification of bulk power system risks.

The document is based on four “value drivers,” including the use of innovative, risk-based programs, and balancing industry collaboration with independence and objectivity.

It identifies five long-term “focus areas,” including further development of the E-ISAC, strengthening “engagement” and seeking opportunities for “effectiveness, efficiency and continuous improvement.”

NERC CEO Jim Robb described the document as “the culmination of very collaborative work between NERC and the regional entities” and also incorporates feedback from stakeholders’ comments on earlier drafts. (See Strategy Plan Prompts ‘Cost-benefit’ Discussion at MRC.)

Robb said “alignment” between NERC and the REs “was something we were aiming for and I think a big step forward from what we had the last time we [wrote] the strategy.”

“Much of the social fabric that’s embedded in the strategy in terms of improving collaboration … I think we already have good proof points that that’s well in motion,” he continued, citing NERC’s “positive steps with the T ransmission F orum.”

Thilly acknowledged that the final draft incorporated the board’s comments as well. “I particularly appreciate that it’s only nine pages long and not 80 pages long,” he added. “It’s concise and clear, which is really helpful.”

The 2019 Long-Term Reliability Assessment, which the board also approved, will be released next week.

December 13, 2019March 12, 2025

Elections Underway for New NERC Panel

By Holden Mann

ATLANTA — It’s musical chairs for those seeking to join NERC’s new Reliability and Security Technical Committee (RSTC), with 35 stakeholders vying for 14 seats in seven sectors.

The 34-member RSTC next year will take over the duties of the Planning, Operating and Critical Infrastructure Protection committees, which have more than 120 members combined. (See NERC Board OKs Committees Merger.)

At a joint meeting of the three committees this week in Atlanta, MISO’s David Zwergel, who will be vice chair of the new group, told members that NERC has completed the sector nomination period, the first stage of the membership selection.

| NERC

Two representatives each were sought from sectors 1-10 and 12, but all but four of the sectors submitted more than two nominees; they are holding elections through Dec. 20 to narrow it down to two. Sectors 1 (investor-owned utilities) and 9 (small end-use electricity customers) each have seven candidates. Sectors 4 (federal or provincial utilities/power marketing administrations) and 8 (large end-use electricity customers) have five candidates each.

The remaining sectors did not require elections, so their representatives will take their seats at the RSTC’s first meeting in March:

Sector 3 (cooperatives): Ben Engelby of Arizona Generation and Transmission Cooperatives, and Marc Child of Great River Energy;
Sector 5 (transmission-dependent utilities): John Stephens of City Utilities of Springfield, and Carl Turner of Florida Municipal Power Agency;
Sector 10 (ISOs/RTOs): Christine Hasha of ERCOT, and Wesley Yeomans of NYISO; and
Sector 12 (state governments): Christine Ericson of the Illinois Commerce Commission, and Cezar Panait of the Minnesota Public Utilities Commission.

At-large Nominations Begin this Month

NERC RSTC — David Zwergel, MISO | © *ERO Insider*

The remaining 10 seats on the new committee will be filled by at-large members to be chosen on Feb. 6 by its Nominating Subcommittee, initially composed of Zwergel and Chair Greg Ford; NERC Chair Roy Thilly; CEO Jim Robb; and Member Representatives Committee Vice Chair Jennifer Sterling. Nominations for at-large members will open Dec. 30 and close on Jan. 10, with the resulting candidates judged based on how they reinforce and complement sector appointees’ strengths.

“If you were nominated [as] a sector rep and weren’t selected … through the election, you’re not automatically put in the at-large, but you can nominate yourself again,” Zwergel said. “The [factors] to be considered [are] interconnection diversity, Canadian representation, broad spectrum of [entity] sector and size, and then expertise.”

Beginning with the first RSTC meeting in June, half of the initial member slate will serve two-year terms, while the rest will serve for three years; following the initial terms, future members will serve for two years, to expire in June of alternating years.

Communication Plan Suggested

Members of the three retiring committees raised no major objections to the existing transition plan. However, Peter Brandien of ISO-NE suggested that NERC consider the impact of the smaller RSTC membership, particularly regarding communicating the committee’s decisions to the broader industry.

“It is going to be a much smaller group, so you’re losing the benefit of providing the information to a large audience that … can then take [it] back to their home office [and] distribute [it],” Brandien said. “So, I think the committee has to think about how to get that information out to industry a bit more.”

While the RSTC is set up, the OC, PC and CIPC will continue to meet according to their current schedules. The RSTC will hold its first meeting March 4 to elect the executive committee and hold its initial regular meeting in June to coincide with the final meetings of the retiring committees.

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

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