NYISO on Thursday kicked off an effort to create a market participation model that would allow an energy storage resource (ESR) and one or more generators to be located at a single point of interconnection, share the same point identifier (PTID) and act as a single resource.
“The HSR participation model will only apply to aggregations located at a single physical location and may not allow for swapping aggregations,” said Christina Duong, market design specialist for distributed resource integration, who presented the initiative at the Installed Capacity/Market Issues Working Group. “The DER model only allows resources up to 20-MW injection capability, but the HSR model will accommodate resources of all sizes.”
The distributed energy resources participation model provides market rules for DERs to participate in NYISO’s energy, ancillary services and ICAP markets. The ISO’s market design is complete, with the FERC Order 2222 filing due in July. The DER model permits aggregation of resources across multiple locations, and an individual resource may leave or join aggregations at the start of a calendar month.
Because the peak operating times for wind and solar systems occur at different times of the day and year, hybrid storage systems are more likely to produce power when needed. | DOE
State initiatives such as renewable energy credit procurements incent developers to couple storage with intermittent renewable assets, which benefits the grid by reducing the output volatility and improving the availability of intermittent resources.
NYISO believes a new HSR market participation model will improve grid flexibility and resilience by enabling new resource types to provide their full capabilities, Duong said.
Evolving Grid Services
One stakeholder asked if the ISO is trying to build off the three existing participation models, or do something new.
“We do want to make this a different model rather than just expanding and making ESR 2.0 or CSR 2.0, so this is going to be a separate and distinct model,” Duong said.
Another stakeholder asked about combining two distinct resources into one PTID, and whether the ISO will be able to discern performance of the individual resources, for example a solar farm and a battery.
“That brings up some concerns we have been having internally during preliminary discussions of how much do we need to know and how much telemetry do we need in order to see for each of the components within this aggregated model, so those are steps and concerns that we’re trying to walk through,” Duong said.
Speaking about a related study on grid services from renewable generators, Michael DeSocio, NYISO senior manager of market design, said that in the immediate future, “maybe we can offer up ways that these resources can provide existing services [operating reserves, regulation, voltage support service and black start service], and as we develop new services, this will inform how these resources could provide those services.”
The ISO focuses on the attributes necessary to provide the service, and any resource capable of meeting those attributes is eligible to provide the service, DeSocio said.
“We’re focused here on discussing what are the capabilities that renewables can provide with regard to their ability to curtail their output or maybe be willing to spill energy so they can provide services and determine whether that capability can be used to meet the attributes we require for the market,” DeSocio said. “And all of this is built around reliability, keeping the lights on for New Yorkers.”
PJM proposed allowing generators deemed to be critical for determining interconnection reliability operating limits to recover their required upgrade costs.
PJM has proposed developing a cost recovery mechanism for generators forced to upgrade their facilities to comply with certain NERC Critical Infrastructure Protection (CIP) standards regarding interconnection reliability operating limits (IROLs).
Darrell Frogg, senior engineer for generation at PJM, provided a first read of the problem statement and issue charge of the proposal at last week’s Operating Committee meeting.
An IROL is any system operating limit that, if exceeded, could jeopardize the entire grid. PJM is required to develop a list of “IROL-critical” facilities, Frogg said, which means the limits mostly derive from those facilities. Generators on the list may then be required to upgrade. Generation owners have no control over the IROL-critical designation, with PJM in its role as the reliability coordinator solely responsible for the list.
| PJM
Frogg said PJM was making the proposal on behalf of generator owners because the classification of a generator as IROL-critical is considered critical energy/electric infrastructure information.
If approved, stakeholders would study the relevant CIP standards, review how a generator’s status is determined by PJM and consider the types of costs that generators incur from being designated. Stakeholders would also look at how other RTOs and ISOs have addressed the issue, such as FERC OKs Payment Rules for IROL Facilities.) Stakeholders would also discuss which costs should be recovered and how, and ensure the entire process is transparent.
The OC will be asked to approve the issue charge at its next meeting. Frogg said PJM hopes stakeholders will be able to make a recommendation to the Markets and Reliability Committee in three to six months. He said work updates would also be provided to the Market Implementation Committee.
David Mabry of the PJM Industrial Customer Coalition said there are “potentially significant” incremental compliance costs in the issue charge. He wondered if the OC is the proper venue to discuss the issue given the possible links to multiple committees in the issue charge.
“I’m wondering whether we ought to bring the problem statement to the MRC for approval and let the MRC decide where this is best addressed,” Mabry said.
Frogg said PJM had internal discussions to determine the best committee to deal with the issue and found that the manuals allow the OC to work out proper market incentives. PJM, however, will continue internal discussions before the next OC meeting, he said.
Resource Tracker Ownership Endorsed
Stakeholders unanimously endorsed a “quick fix” to address information entered into the Resource Tracker application used by PJM.
The proposal includes changing “market participants are requested” to the “generation owner, or designated agent, is required” to confirm resource ownership by Nov. 1. Last year PJM requested owners of 1,503 resources to confirm their information. Of those resources, 60 did not confirm by Nov. 1. As of Feb. 1, four have yet to confirm information.
The issue charge will now go to the MRC for a final vote in April.
TLR Buy-through Quick Fix
Stakeholders also unanimously endorsed a quick fix regarding the transmission loading relief (TLR) buy-through congestion process.
Chris Advena, senior lead engineer for PJM, reviewed a problem statement and issue charge to remove the process from Schedule 1, section 1.10.6A of the OA. Advena first brought the issue to the OC in February. (See “TLR Buy-through 1st Read,” PJM MRC/MC Briefs: Feb. 24, 2021.)
TLR buy-through is the tool PJM uses to curtail interchange transactions that cause loop flow to the RTO around the time emergency procedures are being conducted to reduce the impact on a flowgate or a transmission facility. The process was created when PJM was fully within the Mid-Atlantic region and was issued more frequently than it is today, according to the RTO.
PJM is seeking final approval at the Members Committee meeting April 21.
Manual Changes Endorsed
Stakeholders unanimously endorsed two different manual changes resulting from the periodic review by acclamation.
Matthew Wharton, PJM reliability engineer, reviewed changes to Manual 37: Reliability Coordination. The changes included correction of grammatical errors, updated links and added language for an alternative method for simulating transfers.
Jeff McLaughlin, PJM senior lead engineer, reviewed changes to Manual 02: Transmission Service Request. The minor changes included fixing broken hyperlinks, updating reference document names and the consolidation and relocation of two sub-sections to a “more appropriate section” of the manual.
Both manual sections will now go for final endorsement at the March 29 MRC meeting.
SPP raked in another $27.87 million in market-to-market (M2M) settlements from MISO during December and January, pushing its total to $168.11 million since the two grid operators began the process in 2015.
MISO owes SPP $16.35 million in M2M settlements for December and $11.53 million for January. They were the third and fourth straight months the process has settled in SPP’s favor above the $10 million mark, though neither month approached November’s record of $22.87 million. (See SPP, MISO See $22.8M in M2M Settlements.)
Temporary and permanent flowgates were binding for more than 2,750 hours during the two months.
The grid operators exchange M2M settlements for redispatch based on the non-monitoring RTO’s market flow in relation to firm flow entitlements held by each RTO.
SPP’s market-to-market settlements with MISO have exploded in its favor. | SPP
M2M settlements have been in SPP’s favor 15 of the last 16 months and 54 times in 71 months since the process began.
SPP staff shared the results during a March 11 conference call with the Seams Advisory Group. The group met for the first time since its name change from the Seams Steering Committee. Its February meeting was canceled because of a winter storm that put much of the Midwest into a deep freeze.
SPP, MMU Request Waivers from FERC
SPP and its Market Monitoring Unit filed a joint request March 11 with FERC asking for a limited waiver of three tariff provisions as the Monitor works to verify and calculate actual cost reimbursement for energy offer curves above $1,000/MWh during the February winter storm (ER21-1331).
SPP and its Monitor have proposed extending the 35-day deadline for market participants to submit information for offers above $1,000/MWh to be recovered through make-whole payments. The entities are asking for a 75-day deadline from the Feb. 11-20 operating days.
The RTO and Monitor are also proposing a 105-day deadline — instead of the normal 45 days from an operating day — to review the cost submissions. They additionally propose to waive the limitation on a market participant’s ability to dispute consecutive settlement statements.
Numerous offers exceeded SPP’s $1,000/MWh cap, and prices peaked at $4,274/MWh during the event. The Monitor is reviewing the offers under FERC orders 831 and 831-A, which require that energy suppliers receive a reasonable opportunity to recover their actual costs of providing energy.
NERC is considering accelerating the schedule for its cold weather standard project (Project 2019-06) after last month’s winter storm that led to prolonged mass outages in Texas lent a fresh urgency to the effort, project leaders told the standard drafting team (SDT) in a conference call Monday.
NERC Senior Standards Developer Jordan Mallory told participants that the team will seek permission from the Standards Committee to shorten the next formal comment and ballot period, scheduled to begin April 2, to 25 days from the standard 45. That will enable members to respond to comments and move to final ballot by May 14; if it is approved by stakeholders, the proposal will be submitted to NERC’s Board of Trustees when it meets on June 11.
The update may represent a shift in NERC’s thinking following February’s winter storm. In the immediate aftermath of the crisis, representatives said the organization was “not accelerating, but increasing [the] urgency” of the standard development effort and said the joint ERCOT: Grid was ‘Seconds and Minutes’ from Total Collapse.)
Members of the Texas National Guard assist a motorist stuck in the ice during February’s extreme winter conditions in Abilene, Texas. | The National Guard
In a webinar the same month, the team for Project 2019-06 said that the joint inquiry had not affected the schedule for its effort and that it expected development to wrap “by the end of the year.” (See Cold Weather Standards Team Sticking to Year-end Target.)
SPP’s Matthew Harward, chair of the SDT, said that the board “has requested the acceleration of the timeline.” However, in a follow-up conversation via email with ERO Insider, a NERC representative emphasized that “no action [has been] taken at this time” and that staff will work with the Standards Committee “to determine the timeline regarding the cold weather standards.”
Leaders See Positive Momentum
Harward acknowledged during Monday’s call that the revised schedule would require more intense work. He reminded members that “a lot has happened” during the most recent formal comment and ballot, which began on Jan. 27 and closed on Friday.
The ballot asked stakeholders for their approval of three updated standards: EOP-011-2 (Emergency preparedness), IRO-010-4 (Reliability coordinator data specification and collection) and TOP-003-5 (Operational reliability data). Proposed changes to the standards, respectively, included:
new requirements for cold weather preparedness plans on the part of generator owners, along with data specifications and collections for balancing authorities and annual maintenance and inspection requirements;
data specification requirements for reliability coordinators; and
data specification requirements for transmission operators.
None of the three standards met the two-thirds segmented-weighted threshold required for approval; IRO-010-4 came closest with 66.22%, while TOP-003-5 received 64.35% and EOP-011-2 had 49.39%. SDT leaders were nonetheless positive about the results, with Mallory observing that first ballots for standard projects “[are] usually a lot lower” and thanking team members for their outreach to industry after February’s webinar.
Over the next 11 days, the team will work through stakeholders’ questions and objections, particularly for EOP-011-2; a common concern expressed in comments was whether this standard, which addresses operational considerations, was a good fit for requirements relating to cold weather preparedness.
More Standards Actions Possible
Some stakeholders, particularly in areas where cold weather is commonplace, remain unconvinced that new, binding standards are needed at all — a theme in all of the previous comment periods for the project. (See Gen Operators Cool to Winter Preparedness Standard.) However, other respondents — notably Brandon Gleason of ERCOT — urged NERC to be even bolder in light of the recent emergency.
“ERCOT supports the proposed requirement to mandate weatherization plans as an important first step in ensuring reliability. However, an effective reliability standard would need to include clear and enforceable metrics, which the plan must be designed to achieve,” Gleason said. “It is apparent based on the February 2021 extreme cold weather event that having a plan may not be sufficient by itself to ensure reliability. ERCOT would support a subsequent reliability standard project in order to specify these clear and enforceable metrics.”
Harward echoed Gleason’s comment when he noted that last month’s storm “may result in additional requirements or standards development work.” But he reminded attendees that their mandate was to address only the recommendations of FERC and NERC’s joint report on the Jan. 17, 2018, cold-weather event in the South Central U.S. and warned against the temptation to overreach. (See NERC Panel Delays Action on Cold Weather Prep.)
“[Our] proposed standards may only be a first step in the evolution of cold weather preparedness for the industry, but it is a first step that we must take, and it is necessary and vital that we do this work,” Harward said. “I just ask you to be diligent so that we don’t let the scope creep or wander too far down rabbit holes, and … stay focused on the job ahead of us.”
Oregon Gov. Kate Brown can expect a raft of policy recommendations to land on her desk this spring prescribing how her state can build a comprehensive — and equitable — electric vehicle charging network.
But a number of the proposals will be difficult to implement — at least in the short term, according to one consultant working with the state’s Transportation Electrification Infrastructure Needs Analysis (TEINA) Advisory Group.
Established by Oregon’s Department of Transportation (ODOT), the group — comprising representatives from investor- and municipally owned utilities, municipalities, environmental organizations, labor groups, AAA and General Motors — must provide the governor with an EV charging infrastructure study by June.
“I just want to acknowledge that we won’t be able to solve all of the problems coming out of this study,” Rhett Lawrence, policy manager with consulting firm Forth, said Tuesday in presenting a set of draft recommendations during a virtual meeting of the TEINA group.
Oregon Senate Bill 1044, passed in 2019, established objectives related to the adoption of light-duty zero-emission vehicles (ZEV), including a goal of 250,000 ZEVs registered by 2025. The bill additionally set targets that ZEVs comprise 25% of all registered vehicles and 50% of all new vehicle sales in the state by 2030, with the sales target rising to 90% in 2035. The state currently has about 32,000 registered ZEVs, well short of SB 1044’s 2020 target of 50,000 vehicles.
A key challenge for Oregon’s EV adoption goals will be building sufficient infrastructure in areas classified as “Rural” (light green) and “Frontier” (dark green). | Oregon Office of Rural Health
As in other states, Oregon’s EV adoption rates evince a sharp urban-rural divide. While 65% of the state’s residents live in areas classified as urban, nearly all EV ownership is concentrated in those zones, confronting policymakers with the challenge of how to build reliable EV infrastructure to support people who live and travel through the state’s sparsely populated regions. Within urbanized areas, the state faces the additional problem of how to make EV chargers readily available to low-income residents and city dwellers living in multifamily buildings where off-street charging is unavailable.
Because of those complexities, Lawrence counseled the TEINA group to divide its policy recommendations into three categories based on the degree of difficulty for implementation: Enable, Accelerate and Drive. The recommendations are the product of a series of “listening sessions” with residents and stakeholders from across the state.
Putting the User First
Topping the lowest-difficulty category — “Enable” — is the recommendation that Oregon policymakers develop standards that create a consistent experience for EV drivers even as they use different charging network platforms throughout the state.
“This is something that came up in almost every listening session,” Lawrence said.
That consistent user experience would extend to expectations around the reliability and redundancy of chargers.
“You need confidence that anywhere you go in the state that you find a charger that will work,” Lawrence said. He suggested that once the state develops the standards, it could build them into the requirements of any state-funded grant programs intended to help finance construction of charging stations. Charging service providers could themselves begin to work together to create uniform standards, he added.
Another recommendation would see the Oregon Public Utility Commission and municipally owned utility governing bodies “enable and encourage” utilities to use ratepayer funds to build the underlying transmission infrastructure needed to support EV charging networks.
“EV make-ready funding should be made available to provide adequate electrical infrastructure up to and past the meter to install EV charging at places such as workplaces and multiunit-dwellings (MUDs),” the draft document said.
Kelly Yearick, program manager at Forth, suggested that Oregon could use revenues from its Clean Fuels Program to fund DC fast chargers (DCFCs), the Level 2 chargers in areas of high population densities to allow for charging by people living in MUDs.
Yearick also said utilities might need to alter rate designs to reduce demand charges — the flat fees utilities charge to recover costs from investments — for charging stations in areas that will see lower use. Those fees compromise the economics of charging stations in rural areas, where a smaller pool of potential EV drivers need a relatively larger proportion of stations because of the distances typically traveled in those areas.
Other “Enable” recommendations include:
incentivizing charging stations in highly traveled corridors through low-interest state loans;
directing local jurisdictions to develop or follow state guidelines to streamline charging station permitting;
developing EV charging education programs “to improve the general public’s awareness of this infrastructure and enhance the user experiences at EV charging stations”;
developing uniform guidelines on EV charging station signage and placement;
coordinating with local jurisdictions to develop public-private partnerships for charging electric bikes and scooters.
Getting to the ‘Hard Work’
The “Accelerate” category consists of policy recommendations “that could speed up the deployment of electrification infrastructure with medium difficulty of execution and implementation for the key players over the medium term.”
Included is a recommendation that the state offer incentives or direct grants for public charging stations, particularly in rural and low-income areas. Lawrence pointed out that some charging stations will face power supply issues, especially in rural areas where the distribution system may not be equipped to handle the load. “State funding can help bridge that gap in how you deal with power supply issues,” he said.
A second recommendation in the category calls for the state to adopt building requirements that require a minimum built-in electrical capacity for all new developments as well as “reach codes” that allow local jurisdictions to exceed state mandates.
A third recommendation would see the state direct municipally owned utilities to invest in DCFC projects.
The “Drive” category includes longer-term recommendations considered more difficult to implement, including state funding for EV charging infrastructure on state-owned property such as parks or workplaces. Another recommendation would see the state requiring a certain percentage of parking spots be EV-ready by an undetermined date.
“We need to acknowledge that’s easier said than done,” Lawrence said, noting that the funding structure for such a program is still uncertain.
The TEINA Advisory Group will review a final draft study document containing the recommendations at a public meeting on May 11.
During Tuesday’s meeting, ODOT Program Manager Mary Brazell pointed out that the group will be taking on additional follow-on studies, including for hydrogen fuel cells and electric bikes.
“TEINA isn’t the end; it’s just the beginning of where we are, and we hope to engage with you as we complete that [infrastructure] document, but beyond as well, when we really get to the hard work, which is implementing this,” Brazell said.
Massachusetts lawmakers are set to pass a major climate bill that would create new roles for critical state agencies in meeting the goal of net-zero emissions by 2050, Sen. Mike Barrett (D) said Saturday.
“The climate issue has picked up velocity recently … and some key agencies have been slow to pivot,” Barrett said at a webinar hosted by MassEnergize, an organization that helps communities reduce greenhouse gas emissions.
Barrett said that the Massachusetts House of Representatives likely will pass the legislation Wednesday. A Senate vote on the climate bill was delayed last week by Senate Minority Leader Bruce Tarr (R), who requested more time to review the final version of the bill with amendments from Gov. Charlie Baker. (See Vote on Mass. Climate Bill Delayed in Senate.)
The bill rewrites the mission of the Massachusetts Department of Public Utilities (DPU) to align its existing regulatory goals under the overarching job of reducing emissions in the state.
“The job of the DPU needed to be modernized and given a 21st century look,” Barrett said.
The bill also directs Mass Save, a collaborative of Massachusetts’ natural gas and electric utilities, to demonstrate that its efforts to reduce emissions are working. The state program advises residents on how they can lower their utility bills and reduce energy consumption.
The collaborative has not been taking its role in reducing climate change as seriously as it could be, Barrett said.
Powering residential and commercial buildings makes up 27% of emissions in Massachusetts, according to data from the Massachusetts Department of Environmental Protection.
“In the deep plumbing of this bill, we say to Mass Save, ‘Every time you evaluate initiatives — every time you choose to replace a light bulb without talking about heat pumps — we want you to weigh your choices and consider the social value of greenhouse gas emissions,’” Barrett said.
The bill also requires Mass Save to state in its three-year plan how much it will reduce emissions. And the secretary of the Executive Office of Energy and Environmental Affairs will be required to set an emissions reduction goal for Mass Save at the start of every new three-year period.
The DPU will need to report to the Massachusetts legislature whether Mass Save met its goal within 18 months of the conclusion of each three-year period.
The goal of these requirements is to increase transparency between state agencies and the legislature to ensure major state agencies with a high profile “pull in the same direction as the other important actors in the emissions reduction scene,” Barrett said.
The Board of Building Regulations and Standards (BBRS) also faces changes under the climate bill. The agency will have a fundamental role in determining how much new construction in Massachusetts will reflect emissions reductions goals, but the BBRS does not have a full-time staff of professionals. The bill moves the task of designing the next stretch of energy code from BBRS to the Department of Energy Resources, which has a full-time staff of energy experts, Barrett said.
State legislators also will add four green building-conscious members to the BBRS’s board of directors, so the board “has a solid climate-aware majority to guide its fortunes going forward,” Barrett said.
Massachusetts’ battery storage program lowered utility costs and reduced battery payback periods for multifamily affordable housing, according to a report by Clean Energy Group (CEG).
ConnectedSolutions, a battery storage program under the state’s energy efficiency initiative Mass Save, uses customer-sited batteries to reduce peak network energy use.
CEG’s analysis found the incentives offered under ConnectedSolutions made solar and battery storage projects a better financial choice for multifamily affordable housing units. Without the incentive program, the renewable energy resource would not be a feasible economic investment for facilities serving these communities, the report said.
The program is accessible to any resident or business interested in participating, but the report analyzed six different affordable housing properties in Massachusetts.
“It is clearly evident from the work here that in multifamily affordable housing in Massachusetts, introduction of the ConnectedSolutions program has been a real advantage to these projects and is improving the finance ability and bankability of installing solar plus storage,” Todd Olinsky-Paul, senior project director at CEG, said during a webinar hosted by the nonprofit.
The ConnectedSolutions program pays customers who discharge stored battery energy to the grid. Customers enter a contract with the utility to participate in the program. They have the option to discharge energy to the grid when the utility needs it to accommodate electricity demand peaks across the network. Payment is based on performance.
Affordable housing properties with solar plus storage, like the Residences at Melpet Farm seen here in Dennis, Mass., are benefiting through participation in a program that supports utilities during peak network demand. | Preservation of Affordable Housing
The program, the report said, offers benefits to multifamily housing units that could not always be achieved by using storage to offset property-specific demand charges.
Participants “are rewarded for their performance during three-hour dispatch windows, achieving greater economic returns by delivering more power for a longer duration than systems optimized for managing onsite demand to reduce utility demand charges, which typically targets much shorter peak periods,” the report said.
The revenue potential of a battery that participates in the program is not limited by the size of the load of the multifamily housing unit at which is it sited. And that revenue potential provides an incentive to install a larger battery than would otherwise be used for demand charge management only.
CEG’s analysis found a 14% reduction in utility bills for the units with ConnectedSolutions, compared to a building that relies solely on demand charge management.
Rates of return on the investment in solar plus storage with ConnectedSolutions improved by 26% for nonprofit affordable housing units and 36% for tax-exempt affordable housing units compared to demand charge management alone.
The payback period, or time it takes to recover the cost of the investment, decreased by 70% with the ConnectedSolutions program for both nonprofit and tax-exempt units, the report said.
And utilities like the program because it allows them to procure storage without having to own the storage, Olinsky-Paul said, adding that “utilities need that load reduction.”
Traditional energy sources used during peak periods emit higher amounts of carbon and are costly to maintain even when they are idle, he said.
Utilities also receive performance incentive payments for running these programs, and participating helps the state reach its climate goals.
Eversource and National Grid have expanded the program to other states they serve, including Connecticut and Rhode Island.
“And these programs are designed to reach overburdened communities, which need efficiency improvements,” Olinsky-Paul said.
Texas Gov. Greg Abbot (R) on Friday rejected Lt. Gov. Dan Patrick’s (R) call to fire Public Utility Commission Chair Arthur D’Andrea, who has steadfastly refused to reprice billions of ERCOT market transactions during that occurred the February storm that almost collapsed the grid.
On Friday evening, Patrick called on Abbott to replace D’Andrea, the lone electric regulator left standing, when he fills the PUC’s other two vacancies, saying D’Andrea “demonstrated little competence and questionable integrity” during several hours of testimony before the State Legislature on Thursday.
Abbott responded by saying he agrees with D’Andrea’s refusal to reprice the market. “The governor does not have independent authority to accomplish the goals you seek,” Abbott told Patrick. “The only entity that can authorize the solution you want is the legislature itself. That is why I made this issue an emergency item for the legislature to consider this session.”
Texas Lt. Gov. Dan Patrick (left), in a rare appearance on the Senate floor, questions PUC Chair Arthur D’Andrea before the Jurisprudence Committee on March 11. | Texas Senate
ERCOT’s Independent Market Monitor has said those transactions are an error, a position its director reiterated before the Senate’s Jurisprudence Committee on Thursday.
“I believe ERCOT has the authority to correct the price, if ordered to do so,” Monitor Carrie Bivens said.
The Monitor revised the initial $16 billion down to $5.1 billion on Thursday after receiving meter information and other additional data. Saying it had considered day-ahead market positions, hedging activity, and offsetting supply and demand positions by multiple entities under the same corporate umbrella, the IMM said real-time market transactions net out to $4.2 billion. Ancillary service charges — which the Monitor said ERCOT improperly priced above the $9,000/MWh cap — should be reduced by an additional $900 million, it said.
The IMM noted that its calculations included only contracts settled by ERCOT, not futures contracts.
The market transactions in question were incurred when ERCOT extended emergency conditions for 32 hours after it stabilized the grid on Feb. 17 and stopped shedding load. The decision kept the grid operator’s $9,000/MWh scarcity pricing — enabled by a Feb. 15 PUC emergency order — in place through the morning peak of Feb. 19.
ERCOT CEO Bill Magness argued the decision wasn’t an error during his testimony before the Senate committee, saying it was “an intentional and carefully considered decision to protect human health and safety while stabilizing the electric grid.”
ERCOT CEO Bill Magness explains the decision to keep scarcity pricing once the load sheds ended. | Texas Senate
“It is clear to me there is a difference of opinion of whether there was a billing error or there was a deliberate decision to take action to save the lives of Texans in their homes. That issue will ultimately be decided by courts,” Abbott told Patrick.
Abbott, who last week added legislation to correct “any [ERCOT] billing errors” to the legislators’ priority list, appointed D’Andrea to the commission in 2017. He named him as the chair when DeAnn Walker resigned earlier this month. (See PUCT’s Walker Steps Down from Commission.)
The lieutenant governor’s ire was raised by D’Andrea’s continued insistence that repricing 32 hours of market transactions at the $9,000/MWh systemwide cap would lead to additional bankruptcies and other unforeseen circumstances. The chairman said he lacked the authority to retroactively change the prices and questioned the Monitor’s contention of a billing error. (See Texas PUC Won’t Reprice $16B Error.)
That was enough to bring Patrick to the Senate floor during D’Andrea’s testimony for what he said was only the second time he questioned a witness during his six years in office.
“It’s a highly unusual circumstance, isn’t it?” Patrick asked D’Andrea.
“Very,” D’Andrea responded.
Armed with a transcript of D’Andrea’s testimony earlier that day to the House of Representatives’ State Affairs Committee, Patrick said, “I have to be candid with you: I just don’t know what to believe. Much of what you said this morning was not true. It was speculation. It was exaggeration.”
Patrick noted that the Lower Colorado River Authority (LCRA) had issued a statement after D’Andrea recounted a conversation to the House in which he said the public utility’s CEO, former Secretary of State Phil Wilson, had said repricing the market transactions “would bankrupt them.”
“At no time did LCRA ever make such a comment to Chairman D’Andrea,” LCRA said in a Twitter thread. The utility, which generates and sells power, said repricing the entire market “would actually benefit LCRA” but admitted repricing ancillary services charges, estimated by the IMM to amount to $900 million, “could substantially harm LCRA.”
“That testimony you gave in the House was incorrect,” Patrick told D’Andrea.
“I would love to verify that with him, because what I heard him say was their preference was we just reprice the energy,” D’Andrea said. “He said, ‘If you do both … if you reprice ancillary services, we will owe a massive amount of money.”
Patrick continued to hammer D’Andrea, referring to a March 9 phone call between the two and Patrick’s chief of staff and a senior adviser — “I have earwitnesses,” the lieutenant governor said — during which they discussed the chairman’s reaction to ERCOT’s decision to extend scarcity pricing.
PUC Chair Arthur D’Andrea answers questions before the House State Affairs Committee on March 11. | Texas Senate
In testimony to the House and Senate, D’Andrea said he woke up the morning of Feb. 18 and saw a market notice from ERCOT alerting participants that, although load was no longer being shed, scarcity pricing was being extended through the morning peak of Feb. 19. He said his chief of staff was “panicked,” but D’Andrea said he called Magness “and he talked me down.”
“Remember what you were telling me in real time?” Patrick asked.
“That it was a mistake and wrong impression,” D’Andrea said. “That was my first impression. I woke up that morning thinking that it didn’t make [economic] sense.
“I’ve told this story a million times the last few weeks,” he continued. “I told [the chief of staff], ‘Let me check this. This is possibly a mistake. This decision was made at 1:30 [a.m.].’ I called Bill and said, ‘Please explain this to me.’ He said, ‘We had a lot of industrial load still out. If we let the prices drop, the load’s going to come back on.’”
D’Andrea said he thanked Magness for making the decision under pressure. “I think it was heroic,” he said.
Magness testified that he made the decision after consulting with Walker. He said that while the grid had been stabilized, dropping prices could have led more industrial load and demand-response customers to come back on, plunging the ERCOT grid back into controlled outages.
“We were so concerned about not going back into rotating outages that, based on what we knew, it was the best decision,” Magness said. “Given the emergency context, I just can’t tell you that I regret the decision.”
“You have to put lives first, as painful as it is to deal with now,” D’Andrea said. “We’d just been through three nights of load shed. We didn’t want a fourth. I just thought we would deal with the economic fallout later.”
D’Andrea’s responses did little to satisfy Patrick, who kept insisting the chairman had the authority to direct EROCT to reprice the 32 hours of scarcity prices. He pointed to a section of the ERCOT Protocols (9.5.12 Suspension of Issuing Settlement Statements for the Real-Time Market) as proof.
The language says the grid operator’s Board of Directors “may direct” ERCOT to suspend real-time settlement statements’ issuance “to address unusual circumstances.” However, Patrick omitted the next sentence, which reads, “Any proposal to suspend settlements must be presented to the Technical Advisory Committee for review and comment, in a reasonable manner under the circumstances, before such suspension.”
In his Friday statement, Patrick said the state’s Public Utility Regulatory Act gives the PUC authority to direct ERCOT to lower the prices, an apparent reference to section 39.151’s language that says the grid operator “is directly responsible and accountable to the commission.”
Twenty-eight of the state’s 31 senators joined Patrick last week in signing a letter urging D’Andrea to “immediately correct” the prices, saying that is “squarely within [D’Andrea’s] authority, whether by your own action or an order to ERCOT.”
“I don’t think I have that authority to order them to reprice,” D’Andrea said. “I have to follow the protocols because that’s what people who play in the market expect. We’re the ones that delegate to ERCOT the protocols. Those are law in my world. I have to act lawfully.”
“It’s pretty clear the rules give you that authority,” Patrick said. “Even if the governor of the state of Texas told you to correct this error … are you saying that you would not obey that?”
“I’ve worked for him for a decade, and he’s never asked me to do something that I thought was illegal,” D’Andrea responded.
“We have to have someone we think is credible,” Patrick said. “You say things in the morning, and you say things in the afternoon that are totally different. It’s hard to really accept you as a credible witness.”
Patrick said he found IMM Bivens to be the day’s only credible witness. For her part, Bivens agreed that D’Andrea and Magness were faced with a difficult decision over whether to allow the scarcity prices to continue Feb. 18-19.
IMM Director Carrie Bivens testifies before the Texas Senate. | Texas Senate
“This was a very difficult decision for us, as well,” she said. “We weighed the pros and cons. At the end of that analysis, we really believe this was an error, and the error should be corrected.”
Bivens said she discussed the situation with both Magness and Walker on Feb. 18. As the IMM monitored the market, it saw “significant” reserves coming online, with “room for more,” she said.
She said the $5.1 billion is real money. “That’s money that has left the system and is not coming back. That is the money that would change hands if our recommendation was put in place.”
Committee Chair Joan Huffman (R) asked Bivens whether it would be possible for the market players to negotiate an “equitable solution.”
“I believe there’s a way,” she said, without offering further details. “I believe it’s complicated, and the longer we wait, the more complicated it gets.”
The problem is the Intercontinental Exchange (ICE), which offers more than 50 futures contracts in ERCOT and four options contracts. The exchange has been proactively making it clear to state regulators and lawmakers that repricing the transactions would “undermine the stability of the futures markets.”
D’Andrea said he discussed the situation last week with ICE, New York banks and the Dallas Federal Reserve and said, “They’re all afraid of [repricing].” When a House representative said he had a communication from ICE that the exchange was delaying final settlement on some ancillary services transactions, D’Andrea said he had heard from ICE President Trabue Bland that “‘that ship has sailed.’”
In a letter to D’Andrea, Bland pointed out that ICE is regulated by the Commodity Futures Trading Commission. “CFTC and international regulations could not be clearer: When a contract is settled, it must be treated as final. Repricing the ERCOT contracts days or weeks after the settlement will cause chaos in the futures markets.”
“Removing one domino by repricing ERCOT for the outage week will have cascading effects in other markets and may cause bigger problems than the repricing solves,” ICE told a state Senate committee. “Changing these observed prices now destroys the value of any hedge. This is the slippery slope ICE Futures US is encouraging the state of Texas to avoid at all costs.”
“There is no clawing that money back. There is no unwinding the ICE transactions,” D’Andrea said.
“In the universe of best practices, it would have been best if the error had not occurred,” Bivens said. “Second-best would have been the repricing of the market to occur quickly. Now that the ERCOT derivatives market has been settled, we recognize that creates complications for certain entities that use those markets.”
ERCOT has a 30-day window to settle transactions with its market participants. Because the PUC’s emergency order went into effect Feb. 15, that would place the deadline for any possible resettlements as early as Wednesday.
The state’s largest public power utility, Brazos Electric Power Cooperative, has declared bankruptcy, and dozens of retailers are thought to be nearing insolvency as well. Asked if he anticipated the bankruptcies, D’Andrea said, “I knew we were making some decisions that were inflicting real pain on people in the market.”
For now, D’Andrea said he needs to repair his relationship with Bivens.
“I really regret that this hearing has pitted us against each other in a strange way,” he said. “I can’t solve this problem for Texans without the IMM standing next to me. This hearing has us against each other, and I can’t have that.”
Generation and distribution planning in North Carolina are going to become more holistic, transparent and integrated as the state moves toward its goal of a net-zero electric grid by 2050. The questions before the North Carolina Utilities Commission during a technical conference held March 9 was how, and how fast the state, its regulators and its risk-averse investor-owned utilities will get there.
The half-day session was a first step in North Carolina’s efforts to reimagine its planning processes, following two years of work on a task force organized by the National Association of Regulatory Utility Commissioners and the National Association of State Energy Officials, said Chris Ayers, executive director of the NCUC Public Staff. Ayers and Commissioner Daniel Clodfelter were two of North Carolina’s representatives on the task force, which rolled out a suite of planning road maps and tools at the NARUC Winter Policy Summit in February. (See Tx Planning Must Be ‘Highly Coordinated,’ Regulator Says.)
North Carolina worked with Hawaii and Puerto Rico to develop a roadmap for aligning resource and distribution planning processes that have historically been developed separately, Ayers told the commission. “You’re going to hear the phrases ‘holistic planning,’ ‘open and transparent process’ [and] ‘open access,’” he told commissioners as he introduced a detailed diagram with arrows running back and forth between parallel components of the roadmap.
As part of the NARUC-NASEO Task Force on Comprehensive Electricity Planning, North Carolina helped develop this holistic process for integrating resource and distribution planning, presented to the NCUC on March 9. | NARUC
“This is a dual linear process,” Ayers said. “There are various steps that provide influence later in the planning cycle to ensure that the data is transferred and utilized in the appropriate steps. There are a lot of inter-cycle linkages that enable feedback loops without stalling the process.”
The aligned resource and grid planning processes begins with setting common goals and objectives, determining principles and metrics, assessing available distributed energy technologies and undertaking a granular forecast of load and resources, Ayers said. Those steps inform a needs assessment and the evaluation of potential DER solutions, providing the foundation for initial drafts of integrated resource and distribution plans.
“What I want to highlight here is how the different steps serve to inform later steps in the process,” Ayers said. “The process is going to produce a final distribution system plan, and it’s going to produce a final integrated resource plan. But then as soon as we’re done planning, these outputs are going to immediately feed into the next cycle.”
Sushma Masemore, North Carolina’s state energy director, followed Ayers with a presentation linking the need for grid transformation to the state’s 2019 Clean Energy Plan. The plan’s goal is to reduce electric power sector greenhouse gas emissions by 70% below 2005 levels by 2030 and to be carbon neutral by 2050. New technology, changing fuel prices, public goals and threats from climate change are all transforming the electricity system, which will require exploring “beyond the traditional generation, transmission and distribution planning process,” she said.
In the past decade, North Carolina has sustained five extreme weather events causing damages in excess of $1 billion, including Hurricane Florence in 2018, which resulted in $17 billion in damages, Masemore said. The urgency for grid planning transformation comes from the customers and local governments themselves, who “are constantly in a state of emergency responding to these disasters and extreme weather events. We need to figure out how we can reduce some of that constant emergency,” she said.
The state’s two investor-owned utilities, Duke Energy and Dominion Energy, did not seem to share the same sense of urgency for transforming their grid planning processes. Mark Oliver, Duke’s managing director of integrated systems planning, consistently said that the company would be working slowly on their own approach to integrated planning, called Integrated System & Operations Planning (ISOP), because it considers non-wires technologies, such as energy storage, to not yet be cost-effective.
Several groups have already criticized Duke’s 2020 IRP. A report published by the Energy Transition Institute in January 2021 found that Duke’s existing and proposed investments could strand around $5 billion in costs for Duke customers. A group of 14 clean energy and community organizations gave Duke a failing grade on its IRP for not adequately addressing climate change and reducing ratepayers’ energy burdens. The NCUC will hold a public hearing on the IRP this Tuesday.
Arguing for slower change to protect grid reliability and affordability, Oliver said the forecasts and case studies Duke is using to refine its ISOP process will be not fully integrated into its IRP until 2022. Even then, he did not expect significant change in the utility’s DER investments.
“Any given year, we spend 20% of our capital on capacity upgrade-related investments,” Oliver said. “Within that 20%, a relatively small proportion [of potential non-wires solutions] appears economic as we look at current technology costs, and we expect that trend to continue for the next three to five years.”
During Duke’s recent fourth-quarter earnings call, Executive Vice President and CFO Steve Young said the company is planning $59 billion in capital spending over the five-year planning period ending in 2024, about 70% of which will be for clean energy and “green infrastructure.” Capital investments from 2025 to 2030 are expected to grow between $65 billion and $75 billion, Young said. (See Duke Plans for $59 Billion in Capital Investment.)
Robert Wright, Dominion’s director of grid planning and asset management, presented on his company’s integrated distribution planning efforts. Moving from planning for capacity, reliability and interconnection separately to an integrated process is a moment of transition for Dominion, Wright said.
However, Wright said this transition is still in its early stages, saying Dominion would rate a 2 on a 5-point scale. Wright described two battery storage pilots and one microgrid pilot on Dominion facilities in Virginia. The battery projects, which are expected to be in service by the end of this year, will be focused on ensuring efficient operation of the technology, Wright said. Echoing Duke’s concerns, he said, “The economics and other aspects of these installations as compared to traditional solutions warrant equal scrutiny to make sure we are making the best decisions for our system as well as for our consumers.”
Representatives from North Carolina’s 26 unregulated electric cooperatives spoke next, discussing the new Distribution Operator (DO) platform they are deploying to improve reliability and optimization across the cooperative grids. Connecting the cooperatives, which serve 2.5 million people in the state, can help the grid handle sudden weather swings and reduce congestion, the presenters said. There have been three pilots testing the DO system, one each with PJM, Duke, and Blue Ridge Energy, a member cooperative.
The PJM and Duke pilots showed that the DO system can use non-market DERs and demand response across multiple distribution points to alter load and “meet abnormal system conditions with non-market resources,” said John Lemire, director of grid management at the North Carolina Electric Membership Corporation (NCEMC). The Blue Ridge pilot showed that communication between the DER management system and the co-op’s DERs could make real-time load decisions based on current weather conditions.
Charles Bayless, senior regulatory counsel at NCEMC, underlined the importance of continuing these projects with multiple stakeholders. “To meet the state’s energy goals in an economic and efficient manner, we need to continue the coordination between EMC, the co-ops, and Duke [Energy Carolinas], [Duke Energy] Progress and Dominion and keep this coordination going between the parties,” he said.
Like the co-ops, public power utilities are also collaborating with the IOUs on improving resource and grid planning, said Kathy Moyer, vice president of operations at ElectriCities, a nonprofit representing the state’s public power and municipal utilities. The organization is working with Duke to provide network resource data and communicate with member communities monthly about capacity needs, transmission upgrades and new delivery points, Moyer said.
But ElectriCities’ DER management system is a fairly new program that is still developing, she said. “As we are moving from a centralized to a decentralized grid, we are preparing our members with interconnection standards, and we are their technical support for integrating those DERs. Currently, we are seeing very low penetration rates, but we are starting to get some more traction,” she said.
The Washington House of Representatives passed a bill Tuesday to encourage all-electric heating designs in publicly owned or leased facilities.
The Democrat-controlled House approved House Bill 1280 by a 57-39 party-line vote. It is now in the Senate Environmental, Energy & Technology Committee.
When publicly owned or leased facilities are built or renovated, the bill would require that an all-electric design — one that would not use fossil fuels for heating — be considered as an option.
Rep. Alex Ramel (middle) is chief sponsor of a bill that would require publicly owned or leased facilities to consider implementing an all-electric heating design during construction or renovations. | State of Washington
“House Bill 1280 takes one small but important step in that direction,” said Rep. Alex Ramel (D), the bill’s chief sponsor. He noted that an all-electric design was installed during the renovation of an elementary school in his hometown of Bellingham — the only time that he is sure this has been done in Washington.
Only a few people from state agencies and energy-conservation organizations testified at two February hearings, all in support of the bill. No one testified against it. Supporters contended the bill would not add any significant costs to new or renovated buildings. They also said all-electric heating systems are cost-efficient and that installing such systems would head off potential later retrofits.
“This will encourage architects to design buildings free of fossil fuels,” Julie Blazek of HKP Architects said at a Feb. 17 hearing. During a Feb. 19 Capital Budget Committee vote, committee Chair Steve Tharinger (D) said: “This does provide some data and guidance” in comparing building designs.
However, Rep. Mary Dye (R) argued that all-electric heating systems are less efficient and reliable than fossil fuel systems, leading to extra costs for taxpayers footing the operating bills. Rep. Mike Steele (R) said all-electric buildings would put extra strains on the Northwest power grid.
