Search
December 25, 2025

Posted on

CAISO Advances Summer Readiness Plan

CAISO introduced a straw proposal Wednesday that aims to attract supply this summer and head off shortfalls like those that led to rolling blackouts in August and energy emergencies in September.

Propelled by those concerns, the ISO is moving ahead on its “market enhancements for summer 2021 readiness” stakeholder initiative at an unusually fast pace. It began advancing the measure in earnest in early January and scheduled it to be adopted by the Board of Governors in late March, with implementation scheduled for June 1.

The proposal took the form of a slide presentation only, not a written proposal as would normally be the case, because of time constraints. It is part of a series of fast-tracked measures being pursued by the ISO and the California Public Utilities Commission in anticipation of summer heat waves and capacity deficiencies as the state transitions from fossil fuels to renewables.

It and other measures are intended to address issues identified in a root-cause analysis of the summer shortages submitted to Gov. Gavin Newsom by CAISO, the CPUC and the state Energy Commission at Newsom’s request. It identified a variety of problems including transmission constraints, questionable exports from the ISO during tight supply conditions and market practices that undermined supply. (See Summer Readiness Sought by CAISO, CPUC.)

“This initiative’s goal is to prepare the CAISO’s operations and market ahead of this summer,” James Friedrich, market design policy specialist, said in his presentation. The “initiative is part of several measures to better access available supply, protect grid reliability and avoid rotating power outages during extreme heat waves. In addition to reliability, the CAISO has the responsibility to ensure its markets are operated efficiently, including mitigating market power and ensuring rational price formation.”

CAISO Summer Readiness Plan
| Shutterstock

The proposal deals with import incentives during tight load conditions, scarcity pricing enhancements and coordination with the interstate Western Energy Imbalance Market (EIM), among other changes. (See Western EIM Questions Performance in Shortfalls.)

For example, it proposes reviewing the performance of the ISO’s resource sufficiency evaluation (RSE) as part of its EIM participation. The re-evaluation would address defects identified in prior workshops such as accounting for resources that are derated as part of the capacity test and eliminating the double counting of mirror resources.

Two proposed enhancements seek to improve market incentives during times of tight supply. One would improve day-ahead market scheduling incentives, and a second would improve real-time incentives.

Another part of the straw proposal involves increasing the real-time market’s prices under certain conditions, including when the ISO issues a day-ahead market alert, or a warning or emergency in real time. The proposal would scale prices to the $2,000/MWh threshold established by FERC in Order 831. The order required ISOs and RTOs to raise the hard caps on supply bids from $1,000 to $2,000; offers over $1,000 require suppliers to justify their costs.

CAISO’s Market Surveillance Committee said in September that the ISO needs to consider implementing scarcity pricing to obtain energy during heat waves and supply shortages. (See CAISO Adds Scarcity Pricing to Policy ‘Roadmap’.)

Making sure storage resources are charged in strained conditions is another component of the straw proposal. Hundreds of megawatts of additional storage are scheduled to come online by this summer. A lack of storage for renewable resources last summer led to shortages when solar ramped down in the evening but demand from air conditioning remained high.

Comments on the straw proposal are due this Wednesday, with a final proposal expected by the end of the month.

Posted on

Decommissioning Fund for Comanche Peak Tops $1.3B

The Texas Public Utility Commission last week approved a change to the decommissioning funds for Vistra Energy’s Comanche Peak Nuclear Power Plant.

During its Jan. 29 open meeting, the PUC signed off on an order that allows Vistra’s Luminant subsidiary to continue its annual decommissioning funding amount of $20.1 million for the plant’s two units. However, the order adjusts the funds’ allocation to 72.3% from 57.1% for Unit 1 and to 27.7% from 42.9% for Unit 2 (50945).

The net after-tax value of the units’ trusts total more than $1.3 billion, with nearly $624 million allocated for Unit 1 and $692.5 million for Unit 2. The plant said external and internal analyses indicates it will cost $1.729 billion to decommission and completely dismantle the facility in 2019 dollars, assuming a 10% contingency.

The commission said Comanche Peak “demonstrated that the funds in its nuclear decommissioning trusts are being invested prudently” and are following its investment guidelines.

Comanche Peak Decommissioning Fund
Comanche Peak Nuclear Power Plant | The Nuclear Decommissioning Collaborative

Unit 1, which began operating in 1990, is licensed until February 2030. The license for Unit 2, which opened three years later, expires in 2023.

While numerous nuclear plants have received extensions of their original 40-year licenses, others have been shut down as uneconomic, and five reactors totaling 5.1 GW of capacity — Indian Point 3 in New York, and Byron (two units) and Dresden (two units) in Illinois — are scheduled to close this year.

“Given Comanche Peak is one of the youngest plants in the country, significant decisions on license renewal are a few years away, but the plant is currently well positioned, and we have no plans to close it prematurely,” a Vistra spokesman told the Houston Chronicle in 2019.

Other Action

In other actions, the PUC approved a financing order that allows Entergy Texas to issue $539.9 million in transition bonds to recover hurricane-related costs (37247).

It also denied the city of Seymour’s request to overturn an administrative law judge’s December ruling allowing four people to intervene in its request for a declaratory order confirming that Tri-County Electric Cooperative has no grandfathered corridor rights for retail service within its city limits (49726).

Also last week, the commission announced it had promoted agency veteran Connie Corona to the new position of deputy executive director. She was previously the PUC’s chief program officer, guiding the market analysis, customer protection, infrastructure, rate regulation and legal divisions.

“Connie is a walking encyclopedia of industry knowledge who makes everyone around her more focused, productive and effective,” Executive Director Thomas Gleeson said. “We are truly fortunate to have her in such a critical role on our team.”

Posted on

SPP Successfully Launches Western Market

SPP successfully launched its Western real-time balancing market at midnight Sunday, making it the first RTO with power markets in both the Western and Eastern Interconnections.

The RTO has said its Western Energy Imbalance Services (WEIS) market will lower wholesale electricity costs, increase price transparency and mitigate congestion for its participants. The market joins the reliability coordinator services SPP has been offering 12 entities in seven states since 2019; the grid operator will expand its RC function in April. (See SPP Expands its Western RC Footprint.)

“This will be a historic moment for SPP to launch this market … on time, and under budget,” CEO Barbara Sugg told stakeholders last week.

SPP Western Market
SPP celebrated its WEIS market launch Monday. | SPP

The WEIS market centrally dispatches energy from the region’s participating resources every five minutes. It is contract-based and does not require its participants to be SPP members. However, most of its participants have since indicated they are committed to evaluating becoming RTO members. (See Western Utilities Eye RTO Membership in SPP.)

WEIS market participants include:

  • Basin Electric Power Cooperative
  • Deseret Power Electric Cooperative
  • Municipal Energy Agency of Nebraska
  • Tri-State Generation and Transmission Association
  • Western Area Power Administration (WAPA)
  • Wyoming Municipal Power Agency

WAPA’s agreement includes the firm loads and resources of Pick-Sloan Missouri Basin Program–Eastern Division in the Upper Great Plains Western Area balancing authority footprint, the Loveland Area Projects and Salt Lake City Area Integrated Projects in the Western Area Colorado Missouri balancing authority footprint.

“Our electricity markets have played a big role in lowering costs, integrating renewables and enhancing reliability in the East, and we’re excited to see a new part of the country begin to see similar benefits,” Sugg said in a statement. “I’m hopeful this is just the beginning of valuable partnerships between SPP and western utilities that will help them and the customers they serve meet their financial, reliability and renewable-energy goals.”

SPP has long eyed expansion into the Western Interconnection. It explored a relationship with the Mountain West Transmission Group several years ago, but the effort was scuttled by Xcel Energy’s decision to join CAISO’s Energy Imbalance Market.

The RTO became the Western Interconnection Unscheduled Flow Mitigation Plan’s administrator in 2018 and it has been hired by the Northwest Power Pool to develop its regional resource adequacy program. (See NWPP Program Taking Shape for Q3 Launch.)

Posted on

FERC Awaiting RTO Responses on Order 2222

The upcoming RTO stakeholder processes on Order 2222 are “where the rubber meets the road” for distributed energy resources’ participation in the markets, FERC Commissioner Neil Chatterjee told an Energy Bar Association webinar Wednesday.

Chatterjee was the FERC chair in September when the commission issued Order 2222, which directed RTOs to open their capacity, energy and ancillary service markets to aggregated DERs. (See FERC Opens RTO Markets to DER Aggregation.)

The order requires RTOs to allow DER aggregators to register as market participants under models that accommodate their physical and operational characteristics. FERC defines DERs as any resource located on the distribution system, a distribution subsystem or behind a customer meter, including energy and thermal storage, intermittent and distributed generation, energy efficiency and electric vehicles.

Chatterjee said the RTO compliance processes would be “interesting to watch” because, like Order 841, “we baked into the order a fair amount of flexibility on certain issues.” Compliance filings are due July 19. (See related story, MISO to Seek Extension on Order 2222 Plan.)

FERC Order 2222
Clockwise from top left: Kristin Swenson, MISO; Mike Blackwell, MISO; FERC Commissioner Neil Chatterjee; Lorenzo Kristov, independent consultant; ; James Pigeon, NYISO and Karin Herzfeld, FERC. | Energy Bar Association

“For example, we provided some flexibility for each region to determine the locational requirements for DERs to participate in an aggregation,” said Chatterjee, the webinar’s keynote speaker. “As another example, we require each RTO to establish rules that address the requirements related to metering and the hardware and software necessary for DER aggregations to participate, recognizing that there’s always a push and pull between technical needs and the potential burdens on new market participants that they create.”

Chatterjee noted a projection that there will be almost 19 million EVs on U.S. roads by the end of the decade. “But the truth is those EVs will be off the road more than they are on the road,” he said. As charging infrastructure develops, he said, EVs will be “virtually able to work in concert to provide grid-level services.”

“That’s an easy way to think about the potential of Order 2222, but the true beauty of the rule is that it’s technology-neutral,” Chatterjee added. “So as new technologies emerge, our market rules will be able to accommodate them.”

Chatterjee said that when he visited the National Renewable Energy Lab in Colorado in October, he learned the scientists had been tracking Order 2222. “They viewed it as a catalyst for the work they’re doing on new technologies for the clean energy transition,” Chatterjee said. “It was deeply gratifying to know that our work at the commission was driving such significant change.”

Panel Discussion

Following Chatterjee’s keynote, a panel discussed approaches among RTOs for Order 2222 compliance, market impacts of DER proliferation, jurisdictional issues relating to DER adoption, and the impact of DERs on grid reliability and resilience.

“It’s striking to me the brilliance of how this [order] is written,” said Tricia DeBleeckere, planning director in the Minnesota Public Utilities Commission’s regulatory analysis division. “Whatever outcome or however this order plays out, it’s going to get what FERC’s intention is, which is a path for DERs to a market, whatever that market might be.”

Lorenzo Kristov, an independent consultant and former principal at CAISO, emphasized that the coordination between DER aggregators, utilities and RTOs is “really going to be crucial to both having efficient competition and also increasing participation in the wholesale market by DERs.”

FERC attorney Karin Herzfeld said the commission needed to recognize the interests state and local regulatory authorities have in Order 2222, which “actually requires the RTOs and ISOs to coordinate with all of these entities.”

“I think that the role provided to distribution utilities and their view of the aggregations is going to be huge,” Herzfeld said. “That’ll be a big thing that the stakeholder processes will be wrestling with in the near future.”

Chatterjee, whose term ends in June, said it would be an “understatement” to say he was proud of Order 2222.

“To me, the beauty of Order 2222 is its simplicity,” Chatterjee said. “Don’t get me wrong. I fully understand that the details underpinning the rule, and the compliance work that stakeholders are engaged in right now with the RTOs, is hugely complex.”

Chatterjee said at the core of the order is a “rather simple and elegant premise.”

“We should eliminate any hurdles facing DER aggregations in our markets, so they can line up and compete with traditional resources to provide all the energy and ancillary services and capacity that they have to offer.”

Posted on

New Jersey BPU OKs $205M EV Spending by PSE&G

The New Jersey Board of Public Utilities last week approved a settlement trimming Public Service Electric and Gas’ proposed electric vehicle infrastructure program to $205 million over six years (Docket # EO18101111).

PSE&G had proposed spending $364 million on EVs and an additional $179 million on energy storage. Under the settlement, the BPU deferred the storage spending and $45 million in spending to electrify school buses while reducing spending on residential smart charging, Level 2 mixed-use charging and public DC fast charging by 18%. “Cross program investments,” such as information technology, were slashed by almost three-quarters.

More than 20 parties, including the state Ratepayer Advocate, commission staff and EV maker Tesla, signed the stipulation of settlement. Two charging companies and several environmental groups declined to endorse the agreement.

The BPU approved the settlement as “a fair and reasonable resolution” of the matter.

In accordance with the BPU’s September 2020 minimum filing requirements (MFR) order, the board deferred action on PSE&G’s proposed $45 million “vehicle innovation fund” for medium- and heavy-duty vehicles (MHDVs) such as school buses. Provisions relating to utilities’ “last resort” ownership of EV charging stations also will be deferred under the MFR order. (See NJ BPU Outlines ‘Shared Responsibility’ EV Plan.)

Energy Storage

The settlement also excludes PSE&G’s proposed energy storage initiatives, which will be the subject of a separate proceeding authorized by the board in June 2019.

PSE&G proposed spending $13.1 million on “solar smoothing” storage systems to prevent rapid power fluctuations resulting from changes in cloud cover; $38.6 million in “distribution deferral” projects to supplement the operating capacity of substation transformers; $20 million in “outage management” spending to reduce the peak load on substations to reduce the number of mobile transformers; $25.7 million on microgrids for critical facilities; and $11.9 million to reduce peak use at public sector facilities, improve resilience, and reduce transmission and distribution investments.

Storage “as part of the charging ecosystem is best addressed in conjunction with MHDV charging uses,” the board said. “As agreed upon in the stipulation, the proposals advanced by PSE&G concerning an [energy storage] program will appropriately be held in abeyance in this proceeding pending future policy guidance from the board.”

Charging Providers, Environmental Groups Dissatisfied

Charging providers Greenlots and Electrify America declined to support the settlement, with the former complaining that it did not include MHDV initiatives or provisions allowing the utility to own charging stations as a “last resort.”

Royal Dutch Shell’s Greenlots said the PSE&G program is overly reliant on private market investment: “The private market has proven inadequate to electrify New Jersey’s transportation sector at the scale and speed required to adequately support existing rates of EV adoption, let alone meet the state’s statutory commitments in the [Plug-In Electric Vehicle Law] and the more rapid timetables called for in the 80 x 50 Report,” in which the state outlined its plans to reduce greenhouse gas emissions to 80% below 2006 levels by 2050.

Volkswagon’s Electrify America said that demand charges for DC fast chargers are too high. “The proposed rate structure, while addressing many concerns, has not reduced the demand charges to the degree necessary to allow Electrify America to price its product at a reasonable price (for example, gasoline equivalency) without covering ongoing energy expenses for the foreseeable future nearly every time someone charges their vehicle, with no ability to recover investments even with support from a make-ready program,” it said.

Filing jointly, Environment New Jersey, the Environmental Defense Fund, Natural Resources Defense Council and Sierra Club said the settlement fails to ensure the state will meet its goals on vehicle electrification, storage and MHDV charging. They said the board should order a rapid timeline for the proceeding on the utility’s MHDV and storage proposals. They also expressed concern that the stipulation does not include utility investment.

In approving the settlement, the board reiterated its commitment to Gov. Phil Murphy’s goal of having 330,000 EVs in the state by 2025.

“The board finds that the funding levels included in the stipulation are adequate and that the ‘shared responsibility’ model adopted in the MFR order and in the stipulation appropriately prioritizes private investment over utility ownership,” it said. “Ownership and operation of EV charging stations should be driven by the market, and, therefore, EVSE [electric vehicle service equipment] infrastructure companies, site owners and property management companies are the preferred owners and operators of EVSE.”

It noted that the MFR order allows utilities to file a petition to own charging for the “occasional and narrow instances” where it is appropriate.

Rebates

Under the settlement, PSE&G will provide the following rebates to offset installations of charging infrastructure:

Residential

      • up to $1,500 of the make-ready cost (utility meter to charger stub) for up to 40,000 charger stubs (maximum $60 million).
      • up to $5,000 of the make-ready cost (service upgrade) for up to 4,000 locations ($20 million).

Mixed Use Commercial Level 2 (240-volt) chargers

      • up to $7,500 of the make-ready cost (utility meter to charger stub) for up to 3,500 charger stubs ($26.25 million).
      • up to $10,000 of the make-ready costs (service upgrade) for up to 875 locations ($8.75 million).

DCFC Public Charging

      • up to $25,000 of the make-ready cost (utility meter to charger stub) for up to 1,200 charger stubs ($30 million).
      • up to $50,000 of the make-ready cost (service upgrade) per location for up to 300 locations ($15 million).

Incentives are contingent on the charging station being capable of sending and receiving communications via Wi-Fi or cellular network and participants agreeing to share session-level charging data with PSE&G.

PSE&G will collect reimbursement for the spending through the technological investment charge (TIC). The utility’s 2018 proposal would have raised annual bills for a typical residential customer by $1.24. The order did not estimate the cost of the reimbursements under the settlement.

Other Action

In other action, the board approved:

      • the appointment of Commissioner Bob Gordon as hearing officer for Rockland Electric Co.’s proposed $6.7 million EV program (Docket No. EO20110730).
      • a waiver allowing drivers to provide alternative documentation for participation in the Charge Up New Jersey EV incentive program in response to delays in the Motor Vehicle Commission’s processing of drivers’ license renewals as a result of the coronavirus pandemic (Docket No. QO20030262).
      • a memorandum of understanding with Northeast Energy Efficiency Partnerships and the Rutgers Center for Green Building, to “convene and engage” stakeholders in a collaborative to develop a New Jersey Zero Energy Building Roadmap (Docket No. QO21010002).
Posted on

Study: No Silver Bullet for Fossil-Climate Legal Tension

Customers were at the center of a panel discussion last week that highlighted what can happen when new state climate laws conflict with those currently governing fossil fuels.

While people are working to address those policy conflicts, Dale Bryk, senior fellow for energy and the environment at Regional Plan Association, said “we’re not doing as well as we could” because the issues states face in implementing their climate ambitions are “very complicated.”

A case study published in Energy Law Journal casts light on policies under New York’s Climate Leadership and Community Protection Act (CLCPA) that are inconsistent with other state polices that support residential customer access to natural gas.

“If you make mistakes in this area, and you get it wrong, someone’s heat will go off,” Bryke said. “People are conservative in thinking about it and really want to get it right.”

Bryk is former New York deputy secretary for energy and environment. She joined the discussion about the case study, “Harmonizing States’ Energy Utility Regulation Frameworks and Climate Laws,” during a webinar Friday hosted by the Institute for Policy Integrity and Environmental Defense Fund.

The study by Justin Gundlach and Elizabeth B. Stein explained New York’s current gas market dilemma as stemming from two separate laws: CLCPA, which makes little room for fossil gas in the future energy system, and New York Public Service Law, which establishes reliable natural gas service as being in the public interest. The study said there are similar policy equations in California, Colorado and New Jersey.

By putting the example of the natural gas sector in New York under the microscope, the study demonstrated how a just transition to net-zero emissions is not a certainty under the state’s laws as written. The study said that a just transition should be among the principles that guide reform.

The movement of gas customers to electrification to meet CLCPA goals could leave remaining customers with higher bills to pay, as the gas utilities’ pool of customers diminishes, the study said. Furthermore, those customers who cannot transition likely are the most vulnerable community members.

Rory Christian, principal at Concentric Consulting Group, said that as markets advance electrification, low-income families need to be protected.

“You have many low-income homeowners, affordable housing developers and rental tenants which lack the financial means, the resources or capability to make this conversion, so we need to align those incentives in a just and equitable manner to ensure that those with the greatest need can take advantage of this opportunity and be a part of the transition,” he said.

Christian said that a key factor in an equitable transition is addressing how utility rates are set under current regulations.

“Understanding that the current rate regime is based to develop and maintain the system as it is, we need to reconsider how rates are deployed and how they’re developed to ensure that customers who have to transition and will transition do not experience unexpected spikes in costs as a result,” he said.

The pathway to long-term success, he added, means looking at all existing laws and regulations to “minimize the potential for creating a wider economic divide between the haves and have-nots as the pace of electrification quickens.”

Gas utilities, however, are regulated in a way that ensures they are structured to sell gas.

Utilities are driven to expand their customer base and build large infrastructure, Bryk said, adding that they make money based on the rules that government sets for them.

“If we want utilities to be in a different business, if we want them to be in the business of providing heat at least costs over the long term, and we want them to be in the business of designing a just and equitable transition … then we need to set the rules … that will drive them to do that,” she said.

Government, she added, is giving utilities conflicting signals.

“Let’s stop doing that,” she said.

Fuel Neutrality

The case study suggested that fuel neutrality should be another principle that guides legal and regulatory reform related to climate ambitions.

“Codifying into statute or regulation clear preferences or biased parameters that favor a given technology or fuel … can burden future policymakers … with obligations that they may eventually find to be incompatible with the best means of achieving long-term policy objectives,” the study said.

In addition, neutrality ensures incumbent fuels and technologies remain open to competition.

The gas system example in New York shows the challenges electric heat pumps or building management systems are having competing with gas service. The study said that newer services and technologies, such as heat pumps, are not a part of utilities’ networked systems and they would force new policy to be inclusive of non-utility providers.

This change, the study said, “could strain traditional notions of the commission’s jurisdiction and role.”

Safe Transition

A third principle for reform raised in the study made clear the nature of states’ challenges in cleaning up human activity.

The study said that a safe transition must be achieved that balances protecting people from the consequences of human-made climate change and protecting people in the process of social transformation.

“In the long term, this means recognizing that until the transition is substantially complete, we will have to continue maintaining, repairing and/or replacing infrastructure components that pose an imminent risk to physical safety, even though we are also likely to be shutting down other components simultaneously,” the study said.

Consequently, policymakers will have to support values that are contradictory and adopt rules that depart from how infrastructure is governed currently.

Posted on

ERCOT Technical Advisory Committee Briefs: Jan. 27, 2021

Its work complete, the ERCOT task force working on the real-time co-optimization of energy and ancillary services is living on borrowed time.

Staff told the Technical Advisory Committee on Wednesday that when the group next meets in February, it will be asked to sunset the Real-time Co-optimization Task Force (RTCTF) and instead focus on the Passport Program and its “three-and-a-half-year trek.”

“This is our first time out of the gate,” said ERCOT’s Matt Mereness, who chaired the RTCTF, in referencing the work that lies ahead. “We could probably have a one-day meeting on some of these topics.”

In the task force’s stead, Mereness said staff are proposing that the TAC develop a Passport Program implementation working group or task force in the coming months. He suggested that policy and analysis items from the RTCTF’s work be parceled out to some of the committee’s subcommittees this year, when business requirements and designs will be developed.

ERCOT’s Board of Directors in December approved nearly three dozen revision requests by the task force and a separate group developing policies and principles for energy storage resources (ESRs). (See “Passport Program to Take off in 2021,” ERCOT Board of Directors Briefs: Dec. 8, 2020.)

That work is now being taken up by the Passport Program, which faces a 2024 deadline to combine real-time co-optimization’s and ESRs’ implementation with that of ERCOT’s energy management system (EMS) upgrade. Storage and distribution generation functionality will be added before 2024, with Passport “tying up any loose ends.”

The program will expand ERCOT’s real-time market to clear energy and ancillary services every five minutes, bringing the grid operators in line with most others. The day-ahead market, which is already co-optimized, will allow virtual ancillary service offers, while the operating reserve demand curve’s price adders will be replaced by converting it into demand curves for each service, reflected in real-time energy and ancillary service prices.

ESRs will be modeled and dispatched as a single device that charges as load and discharges as a generator. Devices within the distribution system will still be dispatched with improved mapping techniques.

Passport has a total budget of $85.5 million. The bulk of that is attributed to real-time co-optimization ($51.6 million) and the EMS upgrade ($27.1 million).

“We have limited resources and funding beyond the [Passport] projects,” Mereness said, noting staff have already been reviewing protocol changes to ensure their impact analyses don’t affect the program. “The ones that did had a small impact, small enough and discrete enough that we didn’t want to stop what’s in flight.”

He said additional budget details will be shared with ERCOT’s Board of Directors during its Feb. 9 meeting.

Staff Loosens Transmission Outage Restrictions

Healthier reserve margins have allowed staff to loosen some restrictions around planned transmission outages during ERCOT’s summer months (May 15 to Sept. 15).

Outages will still be prohibited from noon through 9 p.m. on 345-kV lines, with 138-kV and 69-kV lines barred from planned outages during that same time should they affect generation dispatch. However, planned 345-kV bus outages and transformer outages will be allowed, and 138-kV outages will be limited to seven continuous days and restoration times of less than six hours.

No outages will be allowed that alter system topology either before or after a contingency. Transmission owners will still have the same list of potential exceptions as the previous two years.

The grid operator goes into this summer with a reserve margin of 15.5%, almost double the 8.6% margin it took into summer 2019. Last year’s reserve margin was 12.6%. (See Solar Power Boosts ERCOT’s Reserve Margins.)

“Even with higher reserve margins, we think it makes sense to leave some restrictions in place for planned outages,” said Dan Woodfin, ERCOT’s senior director of system operations. “This will allow the TOs to do some work during the summer that was maybe not allowed during the last two.”

Lange, Blakey to Lead TAC

The TAC approved nominations to leadership positions for 2021, choosing South Texas Electric Cooperative’s Clif Lange as its chair and Just Energy’s Eric Blakey as its vice chair. Because Lange was not able to participate in last week’s meeting, Blakey wound up chairing.

“It’s such an honor to even be a member of this group. We very much appreciate your support,” Blakey said upon assuming his virtual position. “Last year was very challenging, but I hope there are fewer challenges this year so we can get together.”

The committee also confirmed the leadership for its subcommittees: incumbents Martha Henson (Oncor Electric Delivery) and Melissa Trevino (Occidental Chemical) for the Protocol Revision Subcommittee; Jim Lee (American Electric Power) and John Schatz (Luminant) for the Retail Market Subcommittee; Chase Smith (Southern Power) and Katie Rich (Golden Spread Electric Cooperative) for the Reliability and Operations Subcommittee; and Resmi Surendran (Shell Energy) and Ivan Velasquez (Oncor) for the Wholesale Market Subcommittee.

Members OK Another SCT Directive

The TAC endorsed another in a series of directives tied to Southern Cross Transmission, a proposed HVDC line in East Texas that would ship more than 2 GW of energy between the Texas grid and Southeastern markets. (See “Members Debate Southern Cross’ Bid to be Merchant DC Tie Operator,” ERCOT Technical Advisory Committee Briefs: Feb. 22, 2018.)

Staff recommended that any DC tie facility with an initial energization date or that is replaced after Jan. 1 have at least a 0.95 power factor leading/lagging reactive power capability for voltage support. A Nodal Protocol revision request (NPRR) will need to be drafted to codify the endorsement.

The Southern Cross DC tie’s imports and exports will cause reactive losses on the ERCOT system because its facilities are not currently planned to have any reactive capability to support system voltage. According to a staff report, thermal limits will be reached before voltage limits during summer peak imports. The same report indicated the system has enough margin to support up to 1,289 MW of export before voltage limits are reached.

“We’re still trying to work through all the angles of this concept,” said Cratylus Advisors principal Mark Bruce, speaking for the Southern Cross developers. “Southern Cross is not necessarily opposed. There are ways to get there. … We’ll be interested in the specific NPRR language.”

Virtual Meetings Likely to Last into May

ERCOT’s Kristi Hobbs told stakeholders that they should expect to continue holding virtual meetings through at least May, continuing a practice that has been in place since last March when the COVID-19 pandemic exploded. Staff have been encouraged to work from home and discouraged from traveling, while outside visitors have been restricted from the grid operator’s facilities.

“We continue to monitor the case trends [and] all the government guidelines, as well as how things are progressing with vaccine opportunities,” she said. “We want to see how the vaccine rollout goes and the success of that vaccine.”

Hobbs promised to return to the TAC in April for another update, following another checkpoint with staff in late March.

RUC Hours Consistent with 2019

ERCOT’s reliability unit commitment (RUC) usage for 2020 remained comparable to 2019, staff told the committee, with 224 instructed resource-hours resulting in 220.1 effective RUC resource-hours. The prior year’s numbers were 228 and 201.7, respectively.

All the resource-hours were for local thermal congestion or voltage concerns, with 83% of the total stemming from damage caused by Hurricane Hanna and associated congestion in the Rio Grande Valley.

Staff also told the committee the Board of Directors will be told in February that the system administration fee is forecast to be adequate for 2022. The fee has remained at 55.5 cents/MWh since 2019.

Market participants had asked for more advance notice of any future administration fee increases during the 2016-2017 budget process. Staff deliver that forecast during the Finance and Audit Committee’s first meeting of the calendar year.

‘Significant’ Price Corrections Defined

The committee unanimously approved its combination ballot by a 30-0 margin. The ballot included the Southern Cross directive, 11 NPRRs, three revisions to the Planning Guide (PGRRs), and single changes to the Resource Registration Glossary (RRGRR) and the Settlement Metering Operating Guide (SMOGRR).

Among the endorsed changes was NPRR1024, drafted in response to the recent spate of price corrections in the day-ahead and real-time markets. (See “Board Approves 2 Sets of Price Corrections,” ERCOT Board of Directors Briefs: Oct. 13, 2020.)

Staff promised the board in October that they would work with stakeholders to reduce price-correction requests by better defining “significance,” the only threshold for determining which market errors require board-approved corrections. NPRR1024 defines “significance” as:

      • the absolute value change to any single day-ahead market (DAM) settlement point price at a resource node or day-ahead market-clearing price for capacity (MCPC) is greater than 5 cents/MWh;
      • requiring ERCOT to change more than 10 DAM settlement point prices and day-ahead MCPCs; or
      • the absolute value change to any DAM settlement point price at a load zone or hub is greater than 2 cents/MWh.

Members voted separately on another Protocol change when Morgan Stanley’s Clayton Greer indicated he would vote against NPRR994. The measure, which passed 29-1, clarifies which transmission improvement projects associated with the interconnecting new generation resources should be classified as “neutral” projects, including new substations, and delineates which interconnection facilities are considered before ERCOT performs an economic analysis.

“I don’t think it’s in compliance with the spirit of the original order that established the gen interconnect process at ERCOT,” explained Greer, who also opposed the measure at the subcommittee level. “The process as it has been up until five years ago was run in compliance, but it has moved away from that. … It would restrict a generator’s ability to get their energy out to market.”

The rest of the combo ballot included:

      • NPRR1034: creates a new protocol section (Frequency-Based Limits on DC Tie Imports or Exports) that enables ERCOT to establish import or export limits on DC ties and avoid the risk of unacceptable frequency deviation during an unexpected loss of one or more DC ties during the import/export. Staff will be able to curtail DC tie schedules on a last-in-first-out basis to address this risk.
      • NPRR1040: establishes compliance metrics for ancillary service supply responsibility.
      • NPRR1044: requires generation resources and ESRs to develop and implement subsynchronous resonance mitigation plans to address vulnerabilities in the event of six or fewer concurrent transmission outages, an increase from the current threshold of four or fewer.
      • NPRR1048: changes certain required system-adequacy reports to being aggregated “by forecast zone” instead of being aggregated “by load zone.” Forecast zones have the same boundaries as the 2003 congestion management zones: North, South, West and Houston.
      • NPRR1049: removes the requirement to obtain board approval to add, delete or change a DC tie load zone and also removes the 48-month waiting period before such actions can go into effect.
      • NPRR1050: changes the summer projected commercial operations date deadline from the start of the summer peak load season to July 1.
      • NPRR1051: removes the administrative price floor of -$251/MWh from all day-ahead settlement point prices.
      • NPRR1052: ensures that energy storage systems registered as settlement-only generators will continue to have their injections and withdrawals settled at load zone pricing until nodal pricing for injections and withdrawals is approved and implemented.
      • NPRR1053: establishes an exemption from ancillary service supply compliance requirements for any qualified scheduling entity (QSE) representing an ESR whose ability to charge is restricted during a Level 3 energy emergency alert event. The change also clarifies that the compliance exemption does not impact the QSE’s financial responsibility because of the AS insufficiency.
      • NPRR1054: removes all references to Oklaunion Exemption from the protocols and adjusts the affected sections’ remaining language accordingly. The coal-fired Oklaunion plant was retired in October.
      • PGRR085: adds a requirement for resource entities, interconnecting entities (IEs) and TOs to provide reports benchmarking the power system computer-aided design (PSCAD) model against actual hardware testing and to provide parameter verification documentation confirming model settings match those implemented in the field.
      • PGRR086: clarifies that resource entities and IEs must provide dynamic model data and model-quality tests to complete a full interconnection study application.
      • PGRR087: clarifies that remedial action schemes should not be relied upon to resolve planning criteria violations.
      • RRGRR027: clarifies that resource entities and IEs must provide dynamic model data and model-quality tests to complete a full interconnection study application. PSCAD models should be required before the applicable quarterly stability assessment deadline.
      • SMOGRR024: makes modifications to accommodate telemetered auxiliary load and allows a site to comply with NPRR1020.
Posted on

MISO Closes Loophole for Late-stage Interconnection Projects

MISO interconnection customers with signed agreements will no longer be able to abandon generation projects without assuming additional financial risk, thanks to FERC’s approval of a new rule.

The commission on Thursday approved a tariff revision that gives MISO the ability to use payments submitted by interconnection customers under generator interconnection agreements (GIAs) to lessen the burden on other interconnection projects, should the latter customers cancel projects after signing the agreements (ER21-525).

MISO said the change has a “narrow and specific goal:” closing a “loophole” that had allowed developers to pull the plug on all-but-certain generation projects without risking additional capital.

Now, instead of transmission owners returning a GIA’s unused payments to interconnection customers terminating generation projects, the funds will go to MISO. The grid operator will determine whether the funds are needed to cover any negative impacts on other projects that entered the interconnection queue at the same time.

The new rule goes into effect Feb. 1, in time for the next round of GIA execution.

MISO said that it previously had no way to compensate the remaining projects for unexpected network upgrade costs incurred when another project canceled its executed agreement.

“These customers have the option to terminate their interconnection after a GIA, and MISO has no milestone fees at that point to mitigate the harm,” MISO counsel Jackson Evans explained to stakeholders last fall during a Planning Advisory Committee meeting.

Under the RTO’s existing milestone-forfeiture process, developers make milestone payments when they enter the interconnection queue. It can then use those funds at earlier points in the process to mitigate the financial harm imposed on the queue’s remaining projects when others are withdrawn. Those rules no longer apply when a project reaches GIA execution, and the milestones become the initial payment to transmission owners.

The grid operator said it wanted to remove any “financial incentive” an interconnection customer might have by waiting until after an executed GIA to withdraw a project.

“The harm caused from one interconnection customer’s utilization of the post-GIA termination loophole also has the potential to impact the larger queue through additional withdrawals,” MISO explained in its filing. “The unmitigated reallocation of costs from one GIA termination could turn a financially viable project into a non-viable project, which may cause a second GIA termination, which may cause further terminations, resulting in cascading terminations and restudies.”

MISO said its plan had the support of “almost all stakeholders.”

The grid operator said it had found recent examples of harm caused by post-GIA project terminations. Using its 2016 and 2017 cycles of project entrants, it said one of three post-GIA withdrawals in the 2016 cycle had a nearly $5.5 million net financial impact on remaining interconnection customers, and one of six withdrawals in the 2017 cycle had an almost $10.5 million impact on other developers. The other withdrawals had no financial impacts.

MISO said FERC has “previously recognized that when an interconnection customer utilizes the post-GIA termination loophole, it has the potential to cause harm to MISO’s administration of the queue.”

Posted on

NWPP RA Program Taking Shape for Q3 Launch

The Northwest Power Pool is moving to wrap up the design phase of its regional resource adequacy program, stakeholders heard Friday.

“We are closing in on the tail end of the detailed design,” NWPP President Frank Afranji said during a status update on the program, which is about a year in the making. (See NWPP Planning Resource Adequacy Program.)

Next stop: rollout of a “nonbinding” version of the RA program, a milestone NWPP is “hoping” to achieve in the third quarter of this year, Afranji said. (See NWPP Effort Quickly Ramping Up.) Under that version, participants will be asked to offer “forward showings” of resource adequacy and availability seven months in advance of the summer and winter capacity periods, but they would not be penalized for failing to meet their showing requirements.

The full binding program is slated for a 2024 rollout.

The urgency for a comprehensive RA program has been building in the West after an extended heat wave last summer forced Experts Urge West to Address RA Shortfall Immediately.)

“It’s a right-now problem, not a five-years-from-now problem,” Arne Olson, senior partner with Energy and Environmental Economics, said at the time.

Afranji was almost understated in his agreement with that sentiment. “As many of you know, the region has been at risk of a capacity deficit situation,” he said Friday.

Perhaps presciently, NWPP began to address that situation last summer when it implemented an interim program allowing participants to give and receive RA assistance on a voluntary basis during high-stress periods on the grid in summer and winter. Afranji said 12 participants signed up for the summer program, with one trade occurring during the summer heat wave. Ten participants have joined the winter program, which has seen no trades so far, something Afranji said could be attributed to relatively mild conditions and COVID-19 pandemic load patterns.

But NWPP’s initial nonbinding RA program is rapidly taking shape. Afranji pointed out that the program recently attracted its 20th participant in Xcel Energy’s Public Service Company of Colorado. NWPP has also engaged SPP to Develop NWPP Resource Adequacy Program.) The law firm Wright & Talisman has been retained to provide advice on regulatory and legal issues.

The nonbinding program provides the template for the binding one, and not much has changed in the proposed program structure since NWPP revealed initial details last summer. NWPP still envisions a bilateral — rather than “organized” — market, meaning participants themselves will determine what resources to procure instead of a central market operator. Participation will be voluntary, although participants must follow program requirements or face penalties once the binding period begins. NWPP will establish policies describing how parties can join and leave the program.

Program Mechanics

As conceived, the RA program will consist of two binding seasons, summer and winter, with NWPP classifying spring and fall participation as “advisory.” The winter season will run from Nov. 1 to March 15, and summer from June 1 to Sept. 30. Participants will need to provide their forward showings seven months ahead of a binding season, followed by a two-month “cure” period to allow participants to make adjustments in the event of deficiencies.

Capacity accreditation will be based on methodologies “appropriate” for each resource type participating in the program, said Geoff Moore, principal originator with Portland General Electric. Variable energy resources such as wind and solar will be accredited based on effective load-carrying capacity (ELCC), while run-of-river hydro will be scored based on ELCC analysis and historical data. Thermal units will rely on unforced capacity values.

Program designers are still contemplating how to credit storage hydro as they look to a “common hydro model that considers [the] appropriate set of water conditions allowing [the] program administrator to verify data,” according to NWPP.

Fred Heutte, Northwest Energy Coalition senior policy associate, asked whether NWPP is coordinating with the Bonneville Power Administration and Northwest Power and Conservation Council on storage hydro modeling.

Moore noted that BPA is a member of NWPP’s Steering Committee, as well as working groups dealing market design, operations and hydro. “So, they’re covering the board, working with us there. We also have other hydro entities — Powerex and a lot of the Mid-Columbia counties,” a few of which operate public utility districts with significant hydro resources.

“Right now, we think we’ve got the initial hydro methodology, and we’re doing some testing. A lot of data has been provided to SPP, and once that comes back, we’re going to start to refine that and go from there and figure out what the next steps are,” Moore said.

Similarly, accreditation for pumped storage, demand-side resources and behind-the-meter solar are still being worked out.

Charles Hendrix, SPP manager of compliance and advanced studies, said the final phase of the detailed design will include treatment of demand response resources. That will entail, in part, examining how other RA programs deal with DR.

“You can look at demand response as a load modifier or a capacity resource,” Hendrix said. DR used as a load modifier would translate into a reduction in a participant’s net peak demand. If functioning as a capacity resource, DR would count toward load-serving capability but also be backup with planning reserves.

Hendrix said NWPP should consider requiring any load-modifying DR resources participating in the RA program to demonstrate a testable ability to follow through on load reduction and not be permitted to “economically opt out” of performance in the way that many bilaterally contracted resources in the West can opt out of delivery and pay liquidated damages to a buyer.

“Demand response resources acting as load modifiers need to show they can act as such,” he said.

‘All in it Together’

For what the NWPP refers to as the “operational program” — the day-to-day workings of the RA effort — the organization is proposing that program participants only be authorized to call on pooled capacity based on the formula: load + contingency reserves > forecasted peak load + planning reserve margin (PRM) – forced outages – VER underperformance + VER overperformance. A participant could only draw a pooled capacity volume equal to the amount that its load exceeds its reliability metrics. The program administrator would ask participants not experiencing loads above their RA obligations to assist those in need.

Charles Cates, SPP manager of operations engineering analysis and support, said one of the program’s primary objectives is to access the diversity of the region’s resources to ensure reliability.

“A lot of this is driven by diversity,” Cates said. He called the bilateral nature of the program “more of a light touch” in the provision of RA because it does not dictate how participants must operate or what resources to dispatch.

Cates said the program will allow the region to maintain a lower overall capacity margin than if each participant were to go it alone, reducing the need to build or contract for new capacity.

“On top of that, because it’s sort of this ‘we’re all in it together approach,’ participants are able to look at their PRM and hold that back and have a market for their surplus, instead of just worrying about their own footprint.”

NWPP plans to hold another status update webinar regarding the RA program in the second quarter.

Posted on

MISO Annual Transmission Spending Tracks Downward in 2021

The cost of MISO’s 2021 Transmission Expansion Plan is set to ring in substantially below last year’s spending level, the RTO revealed during its South subregional planning meeting Tuesday.

Proposed investment for MTEP 21 stands at $2.85 billion for 350 projects, substantially below MTEP 20’s final $4.05 billion spend for 493 projects. The relatively modest numbers do not include any possible projects under the grid operator’s long-range transmission plan, which will rely on MTEP 21 futures. (See MISO Begins Longterm Tx Modeling.)

Broken down, the draft MTEP 21 contains $723 million worth of baseline reliability projects, $331 million in generator interconnection projects and nearly $1.8 billion spend in the “other” project category, which includes other reliability projects, load growth projects, age and condition-based projects and projects driven by other local needs.

“All of this is preliminary. More information and details will be coming up,” Senior Manager of Expansion Planning Edin Habibovic said.

MISO will finish power flow modeling for MTEP 21 in late spring. After collecting transmission owners’ planning criteria last year, the RTO is now conducting assessments of proposed reliability projects to ensure they’re the most cost-effective solutions. It will also study member-submitted alternatives to project proposals, an effort expected to continue until May.

Making a Case for Long-term Transmission

RTO executives appeared before state regulators to bolster justification for its long-range transmission plan. The first such projects could be approved under MTEP 21.

“Roughly 85% of the footprint has some kind of clean energy goal,” Executive Director of System Planning Aubrey Johnson told state regulators during an Organization of MISO States teleconference on Monday. “This is not going to be achievable without some kind of transmission.”

Clean energy pledges from MISO states and utilities are accumulating quickly. Minnesota this week accelerated its 100% carbon-free electricity pledge by a decade, to 2040. However, the state’s two largest utilities, Xcel Energy and Minnesota Power, are still targeting 100% carbon-free goals by 2050.

MISO expects renewables to account for 25% of its capacity by 2039.

“The question becomes do you have sufficient arteries to deliver this power,” Johnson said.

Americans for a Clean Energy Grid this week compiled studies concluding that grid capacity should double or triple in the near future to reliably accommodate an evolving resource mix.

Johnson said MISO will consider lessons learned from its last long-term planning effort, the 2011 Multi-Value Project portfolio, in which projects were analyzed for benefits as a bundle, not individually. MISO has said projects resulting from its newest long-term plan will be assessed on an individual basis, though there is a chance that some complementary projects could be paired up and considered as one.

“It’s not lost on us the regulatory challenges of a portfolio of projects — some that didn’t get regulatory approval until 2019,” Johnson said, referring to the $492 million Cardinal-Hickory Creek line from southwest Wisconsin to Iowa, the last of the 17-project Multi-Value portfolio in line for a groundbreaking ceremony.

During a subregional planning teleconference on Jan. 27, Clean Grid Alliance’s Natalie McIntire said she’s interested in how MISO will avoid “corridor fatigue” with the long-term package, where the general public tires of dealing with new routes and construction.