VALLEY FORGE, Pa. — The PJM Demand Response Subcommittee would be tasked with updating the testing rules for rarely dispatched DR resources under a problem statement and issue charge presented to members Wednesday.
PJM’s Jack O’Neill told the Market Implementation Committee that the RTO’s current testing rules are based on limited demand response (LDR) requirements made obsolete by Capacity Performance.
LDR applied only to summers, non-holidays and weekends, while CP requires the resource on demand year-round. Likewise, CP events can now last up to 15 hours — versus just six under LDR — and lack LDR’s cap of 10 reductions a year.
PJM says it is concerned because load management events are “low frequency, high impact” incidents. The last recorded event, in 2013, required reductions totaling 6,000 MW across 15 transmission zones. In years when there are no events, there is only a one-hour summer test of performance.
“Testing is our fallback position when there isn’t anything to measure against,” O’Neill said.
PJM noted that DR has averaged about 123% performance in tests versus about 97% in actual events. “This indicates that testing may not reflect performance during actual events,” the problem statement says.
The RTO hopes to bring the revisions to the MIC for a first read in August, a schedule it said would allow for a FERC filing by February 2020 and a commission ruling in time for next year’s Base Residual Auction.
The daily load management test failure charge rate will not be affected by the review.
Utilities Question Primary Frequency Response Calculation
VALLEY FORGE, Pa. — PJM’s Operating Committee last week endorsed revisions to Manual 12: Balancing Operations over the opposition of FirstEnergy, which challenged the manual’s formula for judging primary frequency response performance.
Under the formula included in a newly added Section 3.6 of the manual, PJM will evaluate generators’ performance during events in which the system frequency goes outside a +/-40-MHz deadband for 60 continuous seconds and the minimum or maximum frequency reaches +/-53 MHz.
PJM’s Danielle Croop, senior engineer of operation analysis and compliance, said the formula was vetted by the Primary Frequency Response Task Force based on NERC criteria.
“We opened up our criteria to be more lenient … and we are catching as much performance as we can,” she said. “We are open to changing the formula.”
Jim Benchek, FERC and RTO market technical support at FirstEnergy, said the formula is too sensitive and could result in false failures. “We prefer not to have the formula memorialized in the manual at this time.”
He added that his company remains committed to providing PFR.
The manual changes were endorsed despite 24 objections by FirstEnergy and Duke Energy and 20 abstentions.
At the January OC meeting, American Electric Power noted that FERC’s order did not require scoring of PFR and said PJM had little stakeholder support for it. (See “The Right Metric on Frequency Response?” PJM Operating Committee Briefs: Jan. 8, 2019.)
PJM Continues Review of Non-retail BTM Generation Business Rules
PJM provided stakeholders additional background on a proposed problem statement and issue charge that could result in revised rules for non-retail behind-the-meter generation (NRBTMG).
Terri Esterly, PJM’s senior lead engineer for capacity market operations, said business rules in the RTO’s governing documents need modifications to address the growth of distributed generation. NRBTMG refers to resources used by municipal electric systems, electric cooperatives or electric distribution companies to serve load; they do not participate in PJM markets but can be netted against load to reduce certain charges.
Esterly said it’s been nearly 15 years since a settlement agreement established rules for NRBTMG — long before the RTO implemented the Reliability Pricing Model and Capacity Performance and took on several utility companies as members, including American Transmission Systems Inc., East Kentucky Power Cooperative and Duke Energy’s Ohio and Kentucky divisions.
Under existing rules, NRBTMG must operate at full output during the first 10 instances of maximum emergency generation conditions between Nov. 1 and Oct. 31. However, it’s not clear in Manual 13: Emergency Operations what procedures trigger this requirement.
Likewise, the RTO doesn’t know how close the grid is to exceeding the 3,000-MW NRBTMG cap set in 2005. PJM estimates put this value closer to 4,600 MW, but incomplete public records make it difficult to determine an exact figure.
PJM first proposed reviewing NRBTMG rules during a Jan. 8 Operating Committee meeting and faced suspicion from several municipal utilities and cooperatives. (See Munis Wary of PJM Rules on Non-Retail BTM Generation.) Stakeholders at last week’s meeting requested more firm data surrounding megawatt estimates before moving forward in the process.
Committee Endorses Updates to TO/TOP Matrix
Stakeholders unanimously endorsed changes to the Transmission Owners/Transmission Operator Matrix to document their responsibilities under new NERC reliability standards.
The matrix is an index between the PJM manuals and NERC reliability standards that spells out which responsibilities are PJM’s as the TOP and which are assigned to member TOs.
Version 13 of the matrix adds references for reliability standards:
TOP-001-4 R20 and R21, which took effect in July 2018;
VAR-001-5, which took effect Jan. 1;
EOP-004-4, EOP-005-3 and EOP-008-2, which take effect April 1; and
PER-003-2, which takes effect July 1.
The endorsed changes head to the Transmission Owners Agreement Administrative Committee for approval.
Incremental RFP Window for New Black Start Resources Closes May 1
PJM opened a window for new black start resources in the Baltimore Gas and Electric and Potomac Electric Power Co. (PEPCO) zones on Feb. 1.
PJM initiated the new request for proposals — separate from the five-year process completed in November 2018 — after receiving notice late last year of generator deactivations in BG&E’s territory not included in the original scope of projects. The RFP seeks service beginning by April 1, 2021.
“We have included the PEPCO zone and also some surrounding adjacent TO zones in this RFP in the event there are cross-zonal black start options that may be considered,” said David Schweizer, PJM’s manager of power system coordination. “We did not specify megawatts in the RFP because we want to be able to consider any size black start unit that’s proposed.”
Expressions of interest are due by Feb. 25, with detailed proposals due May 1.
Lisle RAS Scheduled for Retirement
A reinforcement project will trigger the retirement of two remedial action schemes designed to prevent thermal overloads at the Commonwealth Edison’s Lisle substation.
The project will add breakers to the four existing 345-kV lines and reconfigure the 345-kV bus into a ring-bus. ComEd said the schemes will be removed as they become unnecessary. The work is scheduled to begin in March and be complete by June 1, 2020.
WASHINGTON — Having regained control of the House of Representatives after eight years in the minority, Democrats have put a lot on their plate, including investigating President Trump’s finances and Russian interference in the 2016 presidential election.
But last week, House Democrats added climate change to their agenda, with two committees holding hearings on the topic simultaneously Wednesday, and Rep. Alexandria Ocasio-Cortez (N.Y.) and Sen. Ed Markey (Mass.) introducing the “Green New Deal” on Thursday.
The hearings came the same day that NASA’s Goddard Institute for Space Studies and the National Oceanic and Atmospheric Administration reported that 2018 was the fourth hottest year on record, with the average global surface temperature for the year coming in only behind those of the previous three.
Since the 1880s, the average temperature has risen about 1 degree Celsius (1.8 degrees Fahrenheit), according to climate scientists. A report released in October by the U.N.’s Intergovernmental Panel on Climate Change said that catastrophic effects from climate change could occur as soon as 2040, when warming is expected to reach 1.5 C if the current rate continues. International efforts, such as the 2015 Paris Agreement, have so far focused on preventing only a 2-degree C increase. (See IPCC: Urgent Action Needed to Avoid Climate Trigger.)
The IPCC report said the impacts of climate change are already being felt in increased storm intensity, precipitation, wildfires and heat waves; rising sea levels from melting polar ice; and the nearing extinction of several species, including coral.
It was these effects that the hearings by the House Natural Resources Committee and the Energy and Commerce Committee, and their witnesses, focused on during Wednesday’s hearings.
“Our communities are paying the price for years of inaction on this issue,” said Rep. Raul Grijalva (D-Ariz.), chair of the Natural Resources Committee. “The massive and unprecedented storms, heat waves, fires and droughts we are experiencing are not normal. They are being made worse by climate change, and if we don’t take action now, we’re only at the beginning.”
Climate change “goes by many different names: Sandy, Harvey, Maria, Katrina, Camp Fire,” said Rep. Paul Tonko (D-N.Y.), chair of the E&C Committee’s newly renamed Subcommittee on Environment and Climate Change.
Many of the Democratic committee members used their allotted time to talk about the natural disasters unique to their states; Californians especially focused on the wildfires of the past few years.
Similarly, North Carolina Gov. Roy Cooper (D) and Massachusetts Gov. Charlie Baker (R) told the Natural Resources Committee about the challenges their states have faced.
“We’ve weathered two so-called 500-year floods in two years and three in fewer than 20 years,” Cooper said. “In the Western North Carolina mountains, volatile weather has caused mudslides, damaged infrastructure, cost apple growers valuable crops and forced ski areas to close mid-season, hurting local businesses and putting jobs in jeopardy.”
“Shortly after taking office in January of 2015, the snow started falling, hard, and it didn’t end until well into April,” Baker said. “What was different about those storms was the sheer volume of snowfall, with record-breaking amounts in Worcester and Boston.”
Most of the Natural Resources Committee’s witnesses after the governors were environmental and social activists, who spoke of how climate change would hit poor and minority communities the hardest.
“As a poor and working-class community, housing displacement and disruption of services due to storms and other severe weather affect our people much more acutely compared to resident of affluent communities with more resources,” said Elizabeth Yeampierre, executive director of UPROSE, an organization representing the Latino community in Brooklyn’s Sunset Park neighborhood.
Only two scientists appeared on the panel, one of whom, Judith Curry, was invited by Republicans and downplayed the severity of the threat. “Both the problem and its solution have been vastly oversimplified,” said Curry, president of the Climate Forecast Applications Network and former chair of the School of Earth and Atmospheric Sciences at the Georgia Institute of Technology.
Republicans Resistant
Some Republicans at the hearings questioned the science of climate change, asking questions such as whether this was the hottest the planet has been, or whether extreme heat or extreme cold kills more people.
One GOP member of the Natural Resources Committee, Louis Gohmert (Texas), asked Curry, “Do you think we’re causing the polar ice caps on Mars to melt? … That’s probably the sun.”
The Republicans that did not question the science criticized the economic costs and job losses associated with closing down fossil fuel plants, said renewable resources are less reliable than baseload plants and rejected proposed solutions as infeasible.
“We want a healthy environment for our children, grandchildren and their children,” said Rep. Greg Walden (R-Ore.), ranking member of the E&C Committee. “But we also want the people who live in our districts and in this country today, right now, to have jobs and to be able to provide for their families. These are not mutually exclusive principles. Working together, we can develop the public policies to achieve these goals.”
Rep. Rob Bishop (R-Utah), ranking member of the Natural Resources Committee, criticized Grijalva for even holding a hearing on climate change, saying it wasn’t in the committee’s jurisdiction. Instead, he said he wanted the committee to focus on issues such as wildfire management and National Parks maintenance.
“Are these hearings simply for those of us around the horseshoe who are going to be making legislation, or are these hearings simply for those who sit around that table in the corner so they can write cute stories?” Bishop asked, pointing to the table of reporters seated next to the witness table.
He noted that Grijalva had dubbed February “climate change month.”
“I appreciate the fact you picked the shortest month of the year to do that,” Bishop said.
Ironically, between the two governors at the hearing, Baker received most of the Republicans’ criticism. Rep. Tom McClintock (R-Calif.) cited the failure of two wind turbines in Falmouth, Mass. The town spent about $10 million to build the turbines in 2009 and 2011. Last month, the town’s Board of Selectmen voted to shut down the turbines and potentially spend millions more dismantling them after residents continually complained of noise.
Baker responded by saying, “My father always used to say that there’s two things: There’s doing the right thing, and then there’s doing the thing right. And doing the right thing but doing it wrong doesn’t necessarily solve the problem. There were a whole series of issues with a well-intended effort in Falmouth that in many respects failed because they didn’t make a lot of the decisions with respect to where they sited them and how they sited them that would have made sense. …
“I think sometimes when something doesn’t go the way it should go, everybody blames the concept. Well sometimes we actually just screw up the way we implement it, and it makes the concept looks bad.”
Rep. Garret Graves (R-La.) noted that his state was one of the top oil and gas producers in the country, while Massachusetts was one of the top oil and gas consumers. “How do you reconcile what you’re able to do based on your economy versus the challenges in Louisiana based on what our economy is founded on?” he asked Baker.
The governor began to explain how despite productivity and population growth, the state has reduced its emissions. Graves interrupted him, saying, “I do appreciate that you all have taken steps, I do. But I also think it’s important to recognize that states in some cases are fundamentally different.” He pointed out that Massachusetts’ electricity prices are among the highest in the U.S.
Green New Deal
Republicans at the hearings also criticized the so-called “Green New Deal,” a set of goals floated by the progressive wing of the Democratic Party after last year’s midterm elections.
On Thursday, Rep. Ocasio-Cortez, with 60 co-sponsors, formally introduced the idea in the House as a nonbinding resolution, with Sen. Markey introducing an identical resolution in the Senate.
The 14-page document calls for “a 10-year national mobilization… to achieve net-zero greenhouse gas emissions.”
The resolution also contains a hodge-podge of goals, including achieving “maximum energy efficiency” from all existing buildings and “spurring massive growth in clean manufacturing in the United States and removing pollution and greenhouse gas emissions from manufacturing and industry.”
“A new national, social, industrial and economic mobilization on a scale not seen since World War II and the New Deal era is a historic opportunity to create millions of good, high-wage jobs in the United States; to provide unprecedented levels of prosperity and economic security for all people of the United States; and to counteract systemic injustices,” the resolution says.
Specific policy proposals to achieve these goals, however, are absent from the document. And with Republicans still in control of the Senate and the White House, any legislation attempting to codify them is almost guaranteed to fail for the next two years.
Rather, many analysts last week saw the document — and the focus on climate change among Democrats this month in general — as more of a political rallying cry for the party ahead of the 2020 elections.
“It actually will be impossible to enact a Green New Deal while Trump is in the White House, but the resolution still has two useful purposes,” Michael Grunwald wrote in Politico Magazine last week. “It’s primarily a political manifesto, a messaging device designed to commit the Democratic Party to treating the climate crisis like a real crisis, pressuring its presidential candidates to support radical transformation of the fossil-fueled economy. At the same time, the Green New Deal is a policy proposal — or at least a sketch of one, a way to launch a substantive debate over how Democrats will attack the crisis if they do regain the White House.”
“In an increasingly social-media-driven political culture, the bill’s sponsors may be looking to generate ‘likes’ … rather than votes,” ClearView Energy Partners said.
Several major contenders to be the Democratic nominee in the 2020 presidential election endorsed the Green New Deal last week.
Republicans predictably lambasted the document.
“It’s a socialist manifesto that lays out a laundry list of government giveaways, including guaranteed food, housing, college, and economic security even for those who refuse to work,” Sen. John Barrasso (R-Wyo.), chairman of the Environment and Public Works Committee, said in a statement. “As Democrats take a hard left turn, this radical proposal would take our growing economy off the cliff and our nation into bankruptcy. It’s the first step down a dark path to socialism.”
MANHATTAN BEACH, Calif. — The number of NERC Regional Entities will soon dwindle to six following last week’s unanimous approval by the organization’s Board of Trustees to enter into a termination agreement with the Florida Reliability Coordinating Council (FRCC).
During the board’s Feb. 7 meeting and without discussion, trustees authorized NERC management to terminate the amended and restated delegation agreement between the organization and FRCC and to approve transfer of its registered entities to SERC Reliability.
FRCC serves as the RE, reliability coordinator (RC) and planning authority for much of the state of Florida, the latter two functions under its member services division. Its only geographic and electrical borders are with SERC.
FRCC announced last year it would dissolve its RE division following a review of its governance structure, set in motion by NERC’s 2017 determination that REs should be separate corporate bodies from NERC-registered entities. A FERC audit in 2010 spurred FRCC to improve the separation between its RE and member services divisions.
NERC will file a petition with FERC seeking its approval of the delegated agreement’s termination and the transfer of FRCC RE’s delegated authority to SERC. It has proposed a transfer deadline of July 1.
Board Chair Roy Thilly thanked FRCC CEO Stacy Dochoda for moving the process along.
“This is a complex set of arrangements, but it’s working very smoothly,” he said.
As of March 2018, FRCC had 32 registered entities in its RE division and 22 in its member services division, including duplications.
5th RC Provider Enters the Western Grid
The number of RCs in the Western Interconnection could soon number five, said Branden Sudduth, the Western Electricity Coordinating Council’s vice president of reliability planning and performance analysis.
Sudduth told trustees and stakeholders that Gridforce, a Houston-based control center, has notified WECC it intends to offer RC services to its Gridforce Energy Management (GEM) balancing authority in northern Oregon. GEM, the lone undeclared BA in Peak Reliability’s footprint, is a member of the Northwest Power Pool.
Sudduth said WECC and NERC are reviewing the application. Gridforce has an expected go-live date of Dec. 3, when Peak will terminate all its services. Peak last summer decided to close its doors when it became apparent its budget couldn’t withstand the loss of CAISO and other members. (See Peak Reliability to Wind Down Operations.)
CAISO has signed up the bulk of Peak’s membership, but SPP has also made inroads by offering RC services to about 12% of the legacy load, primarily along the Rocky Mountains. BC Hydro will take over for its British Columbia service territory.
WECC will begin its certification visits in March at CAISO, which will go live with RC services for its own territory July 1 and for its non-members Nov. 1. BC Hydro goes live Sept. 2, and SPP will follow Dec. 3.
Peak staff will spend about two months conducting shadow operations with each of the incoming RCs to ensure continuity and shared expertise. Peak is following a detailed project management path until it hands over its RC duties.
“We have a very unique requirement of providing services for a year while closing the organization,” Peak CEO Marie Jordan said. “I haven’t closed too many companies. I’ve closed some power plants, but we always had the mother ship above us. This is truly a territory not too many of us on the leadership have been down, so [we] want to do it right.”
NERC CEO Jim Robb said he found Jordan’s presentation “confidence-inspiring.”
“You’ve made it clear the focus is on reliability, not the closure of Peak,” he said.
Robb said he was concerned about the California-Arizona seam, which was a part of the 2011 Southwest outage that led to Peak’s creation. Jordan said Peak is in the final stages of executing a seams agreement with CAISO but noted that remedial action schemes (RAS) may prove more important.
“I do think RAS schemes need to be as much of a focus as the seams agreements,” she said.
WECC RC/BA footprint | WECC
SCE’s Payne: California Prepping for ‘New Abnormal’
Southern California Edison CEO Kevin Payne welcomed NERC to sunny but chilly California, saying, “You’ve picked a pretty interesting time to come” to the state.
Payne said the state is at the forefront of a clean energy future, pointing to its renewables-heavy grid and focus on greenhouse gas reductions.
“Ironically,” he said, “the very thing we’ve worked so hard to mitigate, climate change, is impacting us in real ways. If you’re a skeptic of climate change, I guarantee you would be a believer if you lived through it like we are.”
Payne said 2018 was the “most destructive, damaging and tragic fire year” in the state’s history. Capped by the deadly Camp Fire, the last two years have seen Pacific Gas and Electric rack up $30 billion in potential wildfire liabilities, leading the utility to file for Chapter 11 bankruptcy reorganization. (See PG&E Wants to Undo Contracts, Revamp Biz in Bankruptcy.)
Former Gov. “Jerry Brown referred to the ‘new abnormal,’” Payne said. “We’re quickly preparing ourselves for the new abnormal.”
That includes hardening the grid’s infrastructure, aggressive vegetation management, installing covered conductors on thousands of miles of distribution lines and improving situational awareness by adding weather stations in the utility’s service territory. Like the state’s other investor-owned utilities, SCE filed a wildfire mitigation plan last week. (See Federal Judge to Review PG&E’s Wildfire Plan.)
“We’re working through all of this,” Payne said. “We’re getting the right policies in place, so we can move forward and focus on reliability.”
Robb Honors McIntyre, LaFleur
Robb opened his regular report by asking for a moment of silence in honor of the late FERC Commissioner Kevin McIntyre, who died last month following an 18-month battle with brain cancer. (See FERC’s McIntyre Loses Cancer Battle.)
“I’ll miss his leadership at FERC. He was a rare talent,” Robb said.
He also recognized Commissioner Cheryl LaFleur’s recent announcement that she would not be nominated for another term on the commission. (See LaFleur Announces Departure from FERC.)
“That was a bit of a blow to all of us,” Robb said. “She certainly took reliability as one of the pillars of her work at FERC. She’s been good to us.”
Robb reviewed his four priority areas with the trustees: the evolution of Western RCs; the pace of change in the resource mix; cyber and physical security; and addressing inverter-based technology. NERC defines inverter-based resources as renewable energy asynchronously connected to the grid through power electronics.
“We have to ensure these resources, which are growing at an extraordinary rate, play nicely with the rest of the grid,” Robb said.
Thilly complimented Robb for his performance since stepping into NERC’s leadership role last year. He noted Robb’s focus on a collaborative culture, “which spreads throughout the leadership at NERC and the whole company.”
“It’s been a great set of changes at the right time,” Thilly said. He then jokingly said, “I should mention, though, the honeymoon is almost over.”
Trustees Elect Case as Vice Chair
The board elected Janice Case as its vice chair, returning her to a position she also held in 2013. Case, a trustee since 2008, serves on the Finance and Audit and Technology and Security committees. She spent 25 years with Florida Progress and its Florida Power subsidiary.
The trustees also approved amendments to Texas Reliability Entity’s bylaws, following a comprehensive review to examine their consistency with the Texas Business Organizations Code, and adopted four standards as part of their quarterly standards review:
CIP-008-6, Incident Reporting and Response Planning: Modifies CIP-008 Cyber Security Incident to require reporting of cybersecurity incidents that compromise or attempt to compromise the bulk electric system, in response to FERC Order 848. Includes the Department of Homeland Security in the reporting requirements.
MANHATTAN BEACH, Calif. — The number of NERC Regional Entities will soon dwindle to six following last week’s unanimous approval by the organization’s Board of Trustees to enter into a termination agreement with the Florida Reliability Coordinating Council (FRCC).
During the board’s Feb. 7 meeting and without discussion, trustees authorized NERC management to terminate the amended and restated delegation agreement between the organization and FRCC and to approve transfer of its registered entities to SERC Reliability.
FRCC serves as the RE, reliability coordinator (RC) and planning authority for much of the state of Florida, the latter two functions under its member services division. Its only geographic and electrical borders are with SERC.
FRCC announced last year it would dissolve its RE division following a review of its governance structure, set in motion by NERC’s 2017 determination that REs should be separate corporate bodies from NERC-registered entities. A FERC audit in 2010 spurred FRCC to improve the separation between its RE and member services divisions.
NERC will file a petition with FERC seeking its approval of the delegated agreement’s termination and the transfer of FRCC RE’s delegated authority to SERC. It has proposed a transfer deadline of July 1.
Board Chair Roy Thilly thanked FRCC CEO Stacy Dochoda for moving the process along.
“This is a complex set of arrangements, but it’s working very smoothly,” he said.
As of March 2018, FRCC had 32 registered entities in its RE division and 22 in its member services division, including duplications.
5th RC Provider Enters the Western Grid
The number of RCs in the Western Interconnection could soon number five, said Branden Sudduth, the Western Electricity Coordinating Council’s vice president of reliability planning and performance analysis.
Sudduth told trustees and stakeholders that Gridforce, a Houston-based control center, has notified WECC it intends to offer RC services to its Gridforce Energy Management (GEM) balancing authority in northern Oregon. GEM, the lone undeclared BA in Peak Reliability’s footprint, is a member of the Northwest Power Pool.
Sudduth said WECC and NERC are reviewing the application. Gridforce has an expected go-live date of Dec. 3, when Peak will terminate all its services. Peak last summer decided to close its doors when it became apparent its budget couldn’t withstand the loss of CAISO and other members. (See Peak Reliability to Wind Down Operations.)
CAISO has signed up the bulk of Peak’s membership, but SPP has also made inroads by offering RC services to about 12% of the legacy load, primarily along the Rocky Mountains. BC Hydro will take over for its British Columbia service territory.
WECC will begin its certification visits in March at CAISO, which will go live with RC services for its own territory July 1 and for its non-members Nov. 1. BC Hydro goes live Sept. 2, and SPP will follow Dec. 3.
Peak staff will spend about two months conducting shadow operations with each of the incoming RCs to ensure continuity and shared expertise. Peak is following a detailed project management path until it hands over its RC duties.
“We have a very unique requirement of providing services for a year while closing the organization,” Peak CEO Marie Jordan said. “I haven’t closed too many companies. I’ve closed some power plants, but we always had the mother ship above us. This is truly a territory not too many of us on the leadership have been down, so [we] want to do it right.”
NERC CEO Jim Robb said he found Jordan’s presentation “confidence-inspiring.”
“You’ve made it clear the focus is on reliability, not the closure of Peak,” he said.
Robb said he was concerned about the California-Arizona seam, which was a part of the 2011 Southwest outage that led to Peak’s creation. Jordan said Peak is in the final stages of executing a seams agreement with CAISO but noted that remedial action schemes (RAS) may prove more important.
“I do think RAS schemes need to be as much of a focus as the seams agreements,” she said.
SCE’s Payne: California Prepping for ‘New Abnormal’
Southern California Edison CEO Kevin Payne welcomed NERC to sunny but chilly California, saying, “You’ve picked a pretty interesting time to come” to the state.
Payne said the state is at the forefront of a clean energy future, pointing to its renewables-heavy grid and focus on greenhouse gas reductions.
“Ironically,” he said, “the very thing we’ve worked so hard to mitigate, climate change, is impacting us in real ways. If you’re a skeptic of climate change, I guarantee you would be a believer if you lived through it like we are.”
Payne said 2018 was the “most destructive, damaging and tragic fire year” in the state’s history. Capped by the deadly Camp Fire, the last two years have seen Pacific Gas and Electric rack up $30 billion in potential wildfire liabilities, leading the utility to file for Chapter 11 bankruptcy reorganization. (See PG&E Wants to Undo Contracts, Revamp Biz in Bankruptcy.)
Former Gov. “Jerry Brown referred to the ‘new abnormal,’” Payne said. “We’re quickly preparing ourselves for the new abnormal.”
That includes hardening the grid’s infrastructure, aggressive vegetation management, installing covered conductors on thousands of miles of distribution lines and improving situational awareness by adding weather stations in the utility’s service territory. Like the state’s other investor-owned utilities, SCE filed a wildfire mitigation plan last week. (See Federal Judge to Review PG&E’s Wildfire Plan.)
“We’re working through all of this,” Payne said. “We’re getting the right policies in place, so we can move forward and focus on reliability.”
Robb Honors McIntyre, LaFleur
Robb opened his regular report by asking for a moment of silence in honor of the late FERC Commissioner Kevin McIntyre, who died last month following an 18-month battle with brain cancer. (See FERC’s McIntyre Loses Cancer Battle.)
“I’ll miss his leadership at FERC. He was a rare talent,” Robb said.
He also recognized Commissioner Cheryl LaFleur’s recent announcement that she would not be nominated for another term on the commission. (See LaFleur Announces Departure from FERC.)
“That was a bit of a blow to all of us,” Robb said. “She certainly took reliability as one of the pillars of her work at FERC. She’s been good to us.”
Robb reviewed his four priority areas with the trustees: the evolution of Western RCs; the pace of change in the resource mix; cyber and physical security; and addressing inverter-based technology. NERC defines inverter-based resources as renewable energy asynchronously connected to the grid through power electronics.
“We have to ensure these resources, which are growing at an extraordinary rate, play nicely with the rest of the grid,” Robb said.
Thilly complimented Robb for his performance since stepping into NERC’s leadership role last year. He noted Robb’s focus on a collaborative culture, “which spreads throughout the leadership at NERC and the whole company.”
“It’s been a great set of changes at the right time,” Thilly said. He then jokingly said, “I should mention, though, the honeymoon is almost over.”
Trustees Elect Case as Vice Chair
The board elected Janice Case as its vice chair, returning her to a position she also held in 2013. Case, a trustee since 2008, serves on the Finance and Audit and Technology and Security committees. She spent 25 years with Florida Progress and its Florida Power subsidiary.
The trustees also approved amendments to Texas Reliability Entity’s bylaws, following a comprehensive review to examine their consistency with the Texas Business Organizations Code, and adopted four standards as part of their quarterly standards review:
TPL-007-3, Transmission System Planned Performance for Geomagnetic Disturbance Events: Adopts Canadian-specific revisions to TPL-007-2, including a new variance for Canadian entities; a method to develop alternative geomagnetic disturbance planning events; and addressing Canadian regulatory approval processes for corrective action plans.
CIP-008-6, Incident Reporting and Response Planning: Modifies CIP-008 Cyber Security Incident to require reporting of cybersecurity incidents that compromise or attempt to compromise the bulk electric system, in response to FERC Order 848. Includes the Department of Homeland Security in the reporting requirements.
CARMEL, Ind. — Stakeholders are urging MISO to slow down on bigger ideas to address its disjointed resource availability and need (RAN) until it can measure the effects of three smaller related filings pending before FERC.
For the remainder of this year and through 2020, MISO’s Market Subcommittee and Resource Adequacy Subcommittee will discuss long-term methods of shoring up resource availability as reserve margins decline.
Speaking at a Feb. 5 RASC meeting, MISO Director of Resource Adequacy Coordination Laura Rauch said most of the discussions will take place independently, though the RTO may schedule joint MSC and RASC meetings on the topic.
MISO recently filed new near-term rules for load-modifying resources (LMRs) and planned outages to buy time for more comprehensive solutions. Up to the filings, stakeholders had also urged a slower approach to developing those rules. (See MISO Files New Planned Outage Rules.)
Nearly a month later, MISO is ready to take on the broader proposals, which may include changes to the annual capacity auction, loss-of-load expectation study and capacity accreditations. It said the second and third phases of the project will address “gaps in the efficient conversion of committed capacity to energy.”
So far, a number of stakeholders maintain that MISO’s timeline on the multifaceted project is too aggressive, with some saying that it should evaluate the effects of its LMR and outage filings before it moves on to long-term remedies.
“A lot of comments focused on that we’re moving too fast; the two phases are being rushed. … We do plan on working through the stakeholder process over the next few months to make sure that any solution is vetted,” MISO planning adviser Davey Lopez told stakeholders at a Feb. 6 RASC meeting.
MISO Executive Director of Market Development Jeff Bladen said the RTO is starting conversations now with an eye on recommending long-term solutions within a year and a half.
“This is a marathon, not a sprint,” Bladen said.
“At what point does MISO declare victory? Is there some point where there’s enough of a buffer that MISO stops making changes?” asked Bill Booth, consultant to the Mississippi Public Service Commission, adding, “We’re moving at warp speed.”
Rauch said the RTO will continue determining whether improvements are enough to maintain reliability by gauging whether increasingly frequent maximum generation events are more accurately predicted and managed.
“The goal is not to eliminate all emergency conditions. That’s part of our normal operations,” Rauch added.
Lopez said MISO plans to analyze the impacts of the LMR and outage filings and compare upcoming capacity auction results with prior year auctions before it proposes any changes to capacity accreditation. MISO has said it will investigate adjusting capacity accreditation “based on the ability to resolve resource risk.”
Seasonal LOLE?
Lopez asked for stakeholders’ written feedback on the usefulness of a seasonal capacity construct, an idea long pondered in MISO. The RTO last proposed a two-season capacity auction in mid-2016 before talks stalled, and stakeholder appetite for a revised proposal resurfaced last year.
Some stakeholders said MISO’s loss-of-load expectation (LOLE) study could use improvement if the RTO moves to a capacity auction structure based on either two or four seasons.
Multiple stakeholders said MISO should first examine possible technical changes to the LOLE study — which is based on an annual summer peak — in light of moving to a one-day-in-10-year reliability standard based on seasons.
“Without basic technical LOLE work, I don’t know if we can start the discussion. … I think that needs to be upfront before we can even start on the policy of this,” Minnesota Public Utilities Commission staff member Hwikwon Ham said. “Software can spit out any number you want to. That doesn’t mean you’re getting the right result on your statistical theory.”
Rauch said MISO would have to conduct research to determine which LOLE inputs and calculations would be appropriate.
A seasonal construct also raises the question of whether interconnection service should be divided by seasonal availability, Lopez said. He also said stakeholders should consider whether they prefer a single annual action with seasonal offers or multiple separate seasonal auctions.
Independent Market Monitor staff Michael Chiasson said a seasonal auction would satisfy some IMM recommendations, particularly its longstanding recommendation that resources be accredited according to their ability to deliver across varying conditions.
A day later at a Feb. 7 Market Subcommittee meeting, Bladen insisted that MISO doesn’t currently have a load forecasting problem, but an uncertain resource availability problem.
“It’s not the uncertainty itself that’s increasing. It’s the nominal impact of that uncertainty that’s increasing,” Bladen said.
Beyond LMRs
Stakeholders also asked if MISO will begin focusing on other resources besides LMRs, inquiring about possible changes to the modeling or accreditation of baseload or intermittent resources.
MISO staff said a wide array of changes are on the table and that the RTO might also consider incentives for LMRs with shorter lead times.
“We’re going to let the advice from this committee guide us,” Bladen told the RASC. He later added that while stakeholders and MISO may not have the time to examine upwards of 30 solutions, there’s still a “veritable menu” of options.
MISO said stakeholders may want the RTO to further incentivize economic demand response and improve its scarcity price formation. It also said it could reduce capacity accreditation for long-lead resources.
MISO plans to continue the RAN discussion at the March RASC and MSC meetings.
CARMEL, Ind. — MISO’s recent resource adequacy filings with FERC will affect the timeline of an otherwise unremarkable capacity auction in terms of load forecasts, stakeholders learned last week.
MISO staff confirmed the 2019/20 Planning Resource Auction numbers haven’t moved much from the previous planning year, in line with estimates made last month. (See Early MISO PRA Data Show Little Change.)
The RTO predicted systemwide coincident peak load will be about 122 GW for the period, up from the 121.6-GW prediction made in January for the planning year. The RTO’s total zonal coincident peak now stands at 125.6 GW, up from an earlier 125.3-GW prediction.
MISO now estimates an almost 135-GW planning reserve margin requirement, also up from the earlier 134.4-GW estimate. Similarly, combined local resource requirements are up slightly from 152.6 GW to nearly 153 GW.
“A lot of the data is pretty close to the data we presented in January,” Tim Bachus, MISO capacity market administration analyst, said during a Feb. 6 Resource Adequacy Subcommittee meeting.
Final preliminary data will be presented during the March RASC meeting. MISO will conduct its seventh annual PRA during the second week of April.
In some cases, PRA data deadlines have already passed for resources hoping to participate in the auction — particularly load-modifying resources. Generation owners were also expected to provide the Independent Market Monitor with data to calculate reference levels by Feb. 12, while load-serving entities have until Feb. 15 to request revisions to their coincident peak demand figures.
LMR Registration Confusion
Existing and new LMR registrations, usually due Feb. 1 and Feb. 15 respectively, will be due March 1 only if FERC approves a Tariff filing meant to ensure LMRs are available as promised. MISO said it expects FERC to rule on the matter by Feb. 20, and a more detailed LMR registration survey under the RTO’s proposal is available now.
If the filing is approved, MISO will ask some LMRs with a lead time greater than two hours and that are available fewer than nine months out of the year to submit their monthly megawatt availability and a documented required notification time necessary to begin generating. (See MISO Moves to Examine Long-term Supply Measures.) MISO will allow LMR owners that have already registered their asset according to the current Tariff to amend their registration surveys.
If FERC rejects the filing, MISO will revert to its current LMR registration process, with LMRs not already registered disqualified from auction participation.
Some stakeholders said the competing timelines are creating confusion. Others pointed out that several LMRs have already submitted registration in accordance with MISO’s current Tariff. MISO staff said it would reopen registrations to make sure the new data requirements are met if approved.
Manager of Capacity Market Administration Eric Thoms reassured stakeholders that, should FERC reject the filing, the RTO would not use LMRs’ additional data, and the current process would stand without change.
Stakeholders asked if MISO was satisfied with this year’s load forecast data supplied by LSEs.
“There are always a few numbers that might be outside the curve,” Bachus said, adding that MISO determined there were good reasons for the discrepancies after reaching out to LSEs.
“In the end, there were no concerns about any numbers that may have seemed out of line,” Bachus said.
As in years past, stakeholders continued to question why MISO combines the forecast data for Iowa and Missouri in Local Resource Zones 3 and 5 and all of MISO South. The RTO has long combined PRA data in zones where pivotal suppliers are sparse and their private information could be revealed. Stakeholders again asked MISO to separate the data by zone to provide a clearer picture of resource adequacy.
Meanwhile, MISO will on March 25 send out its annual resource adequacy survey in cooperation with the Organization of MISO States. Completed surveys are due from LSEs and independent power producers by April 15. The RTO will present results in June and July.
CARMEL, Ind. — MISO proactively managed its eighth maximum generation event in six years last month despite the difficulty of pulling together the forecast leading up to the episode, RTO staff reported last week.
Ron Arness, MISO director of Central Region operations, said “a significant amount of uncertainty” characterized the Jan. 30-31 event, spurred by a polar vortex bringing record cold conditions.
High load, fuel supply issues and the possibility of equipment failure coupled with substantial voluntary load management, such as school and business closings, made load profiles uncertain over the period, Arness said. MISO called the maximum generation event beginning 2:38 a.m. ET on Jan. 30 and terminated it at 11 a.m. the following day.
“We had some extreme temperatures … and because of the actions of you as members and MISO took, we reliably maintained service. It was essential because public safety was critical at that time,” Arness told stakeholders at a Feb. 7 Market Subcommittee meeting.
MISO originally forecasted a 104-GW peak load on Jan. 30, though the actual peak clocked in at 101 GW as temperatures sunk to -30 degrees Fahrenheit in some parts of the balancing area.
“We thought we were going to be short, and then we weren’t,” Arness said. “Even though temperatures were colder than we predicted, this voluntary load curtailment” scaled down load.
To produce its regional weather forecasts, MISO uses two separate third-party weather forecasters, both of which rely on multiple weather models.
MISO said that for much of the event, it experienced increased imports in response to its emergency conditions pricing. On Jan. 30, spot natural gas prices nearly doubled to $7.42/MMBtu and the average real-time LMP quadrupled to about $108/MWh. By Jan. 31, the real-time LMP dropped to about $49/MWh, still about double the energy price two days prior.
“Really the intent of that cold weather alert is so members can update their offers and unit availability,” Arness said, stressing that MISO is better able to manage the market with the most accurate offer and commitment information.
“Thank you to all your companies that worked so hard to keep the lights on,” Chris Miller, of FERC’s Office of Energy Market Regulation, told members.
MISO max gen timeline | MISO
Winter Winds, but Few to Harness
MISO operators were further stymied by lower wind generation than expected during the arctic blast.
Wind output during the morning peak Jan. 30 was about 4 GW below forecast as the worst of the cold struck the Midwest. Wind output averaged 4.3 GW and 4.7 GW on Jan. 30 and 31, respectively, compared with about 13 GW for the two days prior to the event.
“It was cold and the wind was blowing, but we suspect that there were significant cold weather cutoffs. We did expect some cutoffs due to the cold — about 1 GW — but we didn’t expect this magnitude,” Arness said.
“This is something we have not seen since MISO has been in existence,” he added.
Arness said MISO staff will continue to investigate the drop in wind output, as well as other factors during the event. The RTO will review wind generator availability during cold temperatures, including maintaining a list of wind generators that have cold weather shutoffs installed, he said.
“What we’re looking for is lessons learned and to enhance our preparedness for future events,” Arness said.
LMR Data Forthcoming
All told, MISO requested about 2,500 MW worth of load-modifying resources during the event. LMR performance reports are expected later.
Stakeholders asked if MISO would consider decoupling its LMR dispatch from its emergency operating procedures so LMRs can be used outside of a declared emergency. Under MISO’s emergency procedures, LMRs are classified as emergency-only resources, requiring the RTO to declare an emergency before dispatching them.
Executive Director of Market Operations Shawn McFarlane said a December Tariff filing would allow MISO to issue scheduling instructions for LMRs as early as 12 hours ahead of a called emergency, allowing the resources to activate and be ready to deploy during an emergency.
Stakeholders questioned whether MISO remains confident about in that approach.
“We can’t deploy emergency resources when it’s not an emergency,” Executive Director of Market Development Jeff Bladen said.
Arness said MISO will continue to dissect the event with stakeholders in public meetings later in February and March.
Customized Energy Solutions’ David Sapper asked for a pricing analysis around the event, given that average energy prices two days before the event hovered around the usual $26/MWh and $27/MWh, even as temperatures ranged from -20 to 2 F.
MISO staff promised to return with more pricing information.
FOLSOM, Calif. — CAISO’s Board of Governors unanimously approved a proposal Thursday meant to ensure that bidders from outside the ISO deliver electricity as promised or face more stringent financial penalties.
“The existing charge [for non-delivery] is relatively ineffective,” Brad Cooper, CAISO’s manager of market design policy, told the board in his presentation. That’s because participants rarely exceed a 10% monthly threshold when the charge kicks in. The new policy does away with that threshold.
Currently, “if intertie declines are less than 10% of total transactions, no charge applies,” the ISO wrote in an Aug. 15 issue paper. Anything more than a 10% failure-to-deliver rate can result in a charge of up to $10/MWh.
The lack of a financial incentive to follow through on bids can cause headaches, CAISO said in the paper.
“When an intertie resource receives a market award to import energy into the balancing authority area but does not deliver the awarded energy, the grid operator must maintain system balance by increasing internal supply or finding another intertie resource to import from,” it said.
Grid reliability and stable pricing depend on expectations being met, Cooper said at Thursday’s board meeting.
“When exports don’t deliver, they can cause intertie congestion,” he said. And “undelivered imports in a critical hour can have a big effect.”
The revised policy is also meant to curb speculative bidding — when a market participant submits a bid and doesn’t deliver because it can’t find the energy it promised or can’t find it at the right price.
When the 10% threshold was enacted in 2007, ISO computers couldn’t distinguish between an intertie “decline” and a reliability curtailment, officials said. That meant that reliability curtailments, which weren’t the fault of the market participant, could still count toward the decline charge.
The bar was set high at 10% to avoid penalizing participants who were unable to deliver because of unforeseeable problems.
Now the ISO’s system can distinguish between curtailments and non-deliveries, meaning the 10% threshold can be eliminated. Instead, non-delivery charges will be assessed in 15-minute intervals and “non-delivery will be subject to a charge equal to 50% of the maximum of the 15-min market or the five-minute real-time dispatch LMP, with a $10/MWh minimum, plus any imbalance energy,” according to the ISO.
Cooper said most stakeholders supported the plan as a way to reduce speculative bidding and to enhance reliability.
Severin Borenstein, a University of California Berkeley professor attending his first meeting as a newly appointed CAISO governor, asked planners to clarify why the charge applies to interties but not inside the ISO’s system.
Keith Casey, CAISO’s vice president for market and infrastructure development, explained that if an intertie bid — always scheduled an hour ahead of delivery — doesn’t materialize, the ISO can’t clear additional intertie energy until the next hour, but internally it can resort to the five-minute market to cover the shortfall.
The New York Public Service Commission on Thursday authorized utilities to spend $31.6 million to build up to 1,075 fast-charging electric vehicle stations and recover costs from ratepayers over seven years (18-E-0138).
The program is intended to help spur sales of EVs by reducing people’s “range anxiety” — the fear of running out of juice on the road — and to achieve Gov. Andrew Cuomo’s Charge NY goal of 10,000 EV charging stations by the end of 2021 and 800,000 zero-emission vehicles by 2025.
The commission’s Feb. 8 order outlines a flow of actions, including annual reviews, that “are smart and timely steps to enable new and needed infrastructure at sensible budgets and at sensible payment structures,” PSC Chairman John B. Rhodes said. “It puts a wide range of partners in a position to invest their money in our agenda for the benefit of all New Yorkers.”
In a related case (18-E-0206), the PSC in November rejected tariff filings for residential EV charging from all the major utilities in the state and ordered them to file revisions that implement time-of-use rates equal to the traditional residential customer charge. (See NYPSC OKs CCA, Rejects Residential EV Charging Tariffs.)
The new proceeding grew out of a joint petition last April by the New York Power Authority, along with the state’s Department of Environmental Conservation, Department of Transportation and Thruway Authority, seeking rate relief for DC fast-charging (DCFC) facilities for EVs.
The state’s Department of Public Service held a technical conference on the issue last summer, and in November the utilities joined the state agencies in filing a consensus proposal for the program.
Rate Design
Mary Ann Sorrentino, chief of electric rates and tariffs for the DPS, testified that rate design was the PSC’s main concern.
Mary Ann Sorrentino, N.Y. DPS
“To capture cost savings from potential technology cost declines, the draft order requires that initial incentive amounts be tied to the year in which the station qualifies for the program,” she said.
Sorrentino said plugs must have a 50-kW minimum charging capability to qualify for the program and that higher incentives will be provided to plugs with a minimum simultaneous charging capability of 75 kW.
Within 90 days of Thursday’s order, the New York State Energy Research and Development Authority must disburse the $31.6 million in unencumbered legacy system benefits charge (SBC) funds to the state’s six regulated utilities in the following amounts: Con Ed ($6.4 million); Orange and Rockland Utilities ($1.66 million); Central Hudson Gas & Electric ($4.4 million); Niagara Mohawk Power ($9 million); New York State Electric and Gas ($5.1 million); and Rochester Gas & Electric ($5 million).
The SBC provides funding for NYSERDA programs targeting energy efficiency, research and development and the low-income sector.
Commissioner Diane Burman
Commissioner Diane Burman brought up the $128 million New York received as its share of Volkswagen’s national settlement for flagrant emissions standards violations, which the state has earmarked for clean transportation measures such as promoting EV use.
“I understand there’s a separate track for that; I’m not looking to get involved in stuff that’s outside our jurisdiction,” Burman said. “To the extent that it complements us … it is extremely important that we are complementing each other in a way that makes sense. Here we’re talking about taking unencumbered legacy funds that seem to never, ever be ending over at NYSERDA, and utilizing them now for part of this.”
The state estimates EV sales were up 50% last year from 2017, with more than 43,000 EVs on the road by October, one-third of them battery electric and the rest plug-in hybrids.
“EVs, as is well known, have a chicken-and-egg problem,” Commissioner Gregg C. Sayre said. “Chargers aren’t being built because there aren’t enough EVs, and EVs aren’t being bought because there aren’t enough chargers. This item helps us get out of that cycle.”
Notable Differences
Commissioner Gregg Sayre
The PSC decided to minimize some of the “notable differences” contained in the consensus proposal.
“For example, pursuant to the consensus proposal, the Con Ed and Orange and Rockland per-plug incentives were to provide a combined benefit in conjunction with delivery rate discounts offered under the Business Incentive Rate [BIR] and Economic Development Rate, respectively, whereas the other utilities’ per-plug incentives were designed assuming that DCFC stations will not receive other delivery rate discounts,” Sorrentino said.
The Con Ed and O&R proposals were also unique in that they contained a separate load-factor incentive whereby station owners would earn a $500 incentive annually for achieving a 5% load factor, and $1,500 annually for achieving a 10% load factor, she said.
The commission found “the load-factor incentive to be unnecessary at this time, as station owners have a natural incentive to maximize station utilization,” Sorrentino said.
Bridget Woebbe, N.Y. DPS
Under Con Ed’s tariff, the BIR was available to owners of EV quick-charging stations with a minimum aggregate charging capacity of 100 kW and a maximum aggregate demand of 2,000 kW in New York City and Westchester County.
“This BIR has been open to electric vehicle quick-charging station developers since April, and that market has not materialized,” testified Bridget Woebbe, assistant counsel for the DPS. “Removing the restrictions really allows site hosts that are providing a direct capital investment by building the critical infrastructure to receive the appropriate incentive to deliver the public good of the DCFC.”
