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December 25, 2025

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UPDATED: Stakeholders Approve WEIS Market Launch

Stakeholders in SPP’s Western Imbalance Service (WEIS) market on Monday unanimously approved its Feb. 1 launch, the last major milestone in a project that began in 2019.

Bruce Rew, SPP’s senior vice president of operations, broke the news during the RTO’s joint quarterly stakeholder briefing, saying the grid operator is “excited” to be operating a power market in the Western Interconnection.

The WEIS Project leadership team, comprising the eight-member Western Markets Executive Committee (WMEC) and representatives from the Western Area Power Administration’s (WAPA) Colorado Missouri and Upper Great Plains West balancing authority areas, met with staff Monday to determine whether to transition from final system testing to a live marketplace.

Following the vote, WAPA tweeted its thanks to customers, stakeholders, SPP, fellow participants and employees “for supporting this monumental effort.”

SPP now joins CAISO in offering a power market in the Western Interconnection.

The vote on the launch had been delayed from Friday after some participants wanted more time to test the WEIS systems’ functions and interfaces.

David Kelley, SPP’s director of seams and tariff services, said last week that staff and stakeholders were trying to “button up some final loose ends.”

“Giving the weekend for some of that to occur would allow for greater confidence in the decision and the vote to take place,” Kelley said on Friday.

Market participants had asked for additional time to see bid-to-bill data with modeling changes they requested, an SPP spokesperson said. That led staff to extend parallel operations, with the WEIS market system running alongside the participants’ current systems, to Jan. 26. Parallel operations had originally been scheduled to end Jan. 14.

Staff has also identified seven “enhancements” that are in yellow status but deemed ready to be addressed after the WEIS market launches.

“We do have plans for those. They’re not problematic,” Customer Relations Manager Don Martin told WEIS stakeholders Friday.

SPP is managing the WEIS market on a contract basis for eight utilities. However, seven of those — Basin Electric Power Cooperative, Deseret Power Electric Cooperative, the Municipal Energy Agency of Nebraska, Tri-State Generation and Transmission Association, and WAPA’s Upper Great Plains West, Rocky Mountain Region and Colorado River Storage Project utilities — have said they are interested in becoming SPP RTO members. (See Western Utilities Eye RTO Membership in SPP.)

SPP also serves as an RC for about 12% of the Western Interconnection. It will add about 3.45 GW of generating capacity to its RC footprint — eight generating resources that are part of Gridforce Energy Management’s BA in Washington, Oregon, Arizona and New Mexico — effective April 1. (See SPP Expands its Western RC Footprint.)

MMU: No Frequent Constraints

SPP’s Market Monitoring Unit told a joint meeting of the WMEC and the Western Markets Working Group (WMWG) Friday that the WEIS market will begin operations without frequently constrained areas (FCAs).

The Monitor analyzed real-time data from Nov. 1, 2019, through Oct. 31, 2020, looking at Western Interconnection constraints monitored by the SPP RC. It found four areas, all in Colorado, with scenarios resulting in at least 100 binding hours.

It defines FCAs as the market footprint areas that both experience high levels of congestion and are associated with one or more pivotal suppliers. It says a supplier is pivotal when some or all of its output is necessary for reliable operations within a defined area.

The Monitor said it will re-evaluate the FCA “designations at least annually.”

Last 3 Open WRRs Approved

The WMWG and WMEC both unanimously approved the final three open revision requests to the WEIS protocols:

      • WRR17: adds documentation to outline how dynamic schedules used to transfer imbalance energy between the market’s balancing authorities will be handled in settlements.
      • WRR18: corrects the real-time loss adjustment factor’s description to accurately reflect its true calculation (“total BA state estimated load without losses/total BA state estimated load with losses”).
      • WRR19: corrects the settlement sign conventions to state that supply imbalance energy is positive and obligation imbalance energy is negative.
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Sierra Club Pans Utility Climate Efforts

Despite pledges to reduce emissions, many of the nation’s largest utilities plan to continue using coal and natural gas-fired generation through 2030, threatening efforts to mitigate climate change, the Sierra Club said in a report Monday.

The environmental group said U.S. utilities must eliminate coal and reduce greenhouse gas emissions by at least 80% by 2030 to limit global warming to 1.5 degrees Celsius (2.7 degrees Fahrenheit), the threshold many climate scientists say is crucial to avoiding the worst impacts of climate change.

“There are three key things utilities must do to enable us to avoid catastrophic warming: They must retire existing coal plants by 2030, terminate plans to build new gas plants and build clean energy much faster,” it said.

The study was based on a review of integrated resource plans and public announcements by the 50 utilities that hold the biggest fossil fuel generating fleets. The 50 companies, which include 79 operating companies, own half of all remaining coal and gas generation in the U.S.

“We find there is a stark difference between utilities’ existing coal and gas generation (1,310 million MWh) and how much clean energy they plan to add this decade (only 250 million MWh),” the group said. “In other words, despite 33 of these companies having a public climate goal, there is an enormous gap between utilities’ current practices and what they need to do to protect people and the planet.”

The companies in the study own 68% of remaining coal generation but have committed to retire only one-quarter of that capacity by 2030, the organization said.

The club noted that Duke Energy, Dominion Energy and Southern Co., which are responsible for more than 12% of the nation’s power sector carbon emissions, each have set corporate climate goals pledging to reach net-zero emissions by 2050. “Yet these companies’ investment plans include large amounts of new gas and lack adequate build-outs of clean energy. Duke and Southern Co. both score an ‘F’ in our analysis, and Dominion scores a ‘D.’ All three will miss their own decarbonization targets unless they change their plans.”

Southern Seeks ‘Orderly Transition’

Southern, which has promised to reduce its carbon emissions 50% by 2030 from a 2007 baseline, told RTO Insider that it was “embracing an orderly transition” of its coal fleet in a process that considers affordability, reliability, safety, environmental impacts and resilience. It said it expects 2020 to be the first time in modern history that the company obtained less than 20% of its generation from coal.

“In employing this robust and analytical approach, GHG emissions have dropped by 44% since 2007, and electricity remains affordable and reliable in our service territories,” it said. “We now expect to achieve our intermediate 50% reduction goal well in advance of 2030.”

Duke: ‘Critical Point’

Duke said the report “fails to recognize all the great progress we’re making.”

The company has pledged at least a 50% reduction in emissions from 2005 levels by 2030. As of 2019, the company says its reductions totaled 39%, putting it “well ahead of the industry average.”

“Our country is at a critical point in addressing the important issue of climate change,” Duke CEO Lynn Good said in a statement Jan. 19 supporting President Biden’s decision to rejoin the Paris Agreement on climate change. “At Duke Energy, we’re taking aggressive action to address this challenge while delivering affordable, reliable and increasingly clean energy. This is what our customers, communities and stakeholders expect from us and what we expect from ourselves.”

Dominion did not immediately respond to requests for comment on the Sierra Club’s critique.

The Future of Gas

The Sierra Club said affordability is not an obstacle to the energy transition, citing a study by Energy Innovation Policy and Technology and Vibrant Clean Energy that concluded local wind and solar could replace about two‑thirds of the U.S. coal fleet at a lower cost to ratepayers. It also noted a report by the University of California, Berkeley and GridLab that found zero-carbon sources could supply 90% of the nation’s electricity by 2035 while reducing costs.

While utilities have reached a consensus on phasing out coal — barring a breakthrough in carbon sequestration technology — the future of natural gas remains a subject of intense debate. (See Gas Going Way of Coal? Not So Fast, Panelists Say.)

Some utilities say gas-fired generation will be necessary for the foreseeable future to support intermittent wind and solar resources. Some 32 of the operating companies included in the study plan to build more than 36 GW of new gas capacity through 2030.

The Sierra Club acknowledged that gas plants’ direct carbon emissions are only half as carbon-intensive as coal-fired plants. But when upstream methane emissions from extraction, processing and transportation are included, “the climate impact of a gas plant is doubled,” the group said. “Overall, the replacement of coal generation by gas generation is not good news for the climate.”

“The scenario of building no new natural gas sounds simple, but it’s the most expensive option for our customers and actually requires coal units to operate longer,” Duke spokeswoman Erin Cuthbert said. “It also relies heavily on emerging technologies and could present challenges in reliability for the families, businesses and industries who rely on us.”

Duke last year said it would seek to reach net-zero methane emissions for its natural gas distribution companies by 2030 by eliminating cast iron and bare steel main piping; deploying technologies to increase its measurement and monitoring of methane emissions; and increasing leak surveys from every five years to every three years.

It said it is also directing its gas procurement for distribution and power generation “toward suppliers with low methane emissions, striking a balance between responsible procurement and maintaining affordability for our customers.”

Duke is a member of ONE Future, a coalition of 37 natural gas production, gathering, processing, transmission, storage and distribution companies working to reduce methane emissions to 1% of total production or less by 2025.

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California Energy Commission Updates Long-Term Forecast

The California Energy Commission updated its 2020-2030 forecast Monday to account for the slowdown caused by the coronavirus pandemic, increased electric-vehicle charging and a projected doubling of battery storage, among other factors.

Commissioners and staff members also paid tribute to Vice Chair Janea Scott, who is leaving for a post in the Biden administration.

In the annual energy forecast update, the anticipated amount of battery storage will double from the previous forecast of 1,300 MW to 2,600 MW by 2030, said Nick Fugate of the CEC’s Energy Assessments Division.

“Battery storage adoption is occurring rapidly,” Fugate said. “We see this just in examining the interconnection data.”

EVs are expected to proliferate and contribute to load growth over the next decade, he said. However, the economic impacts of COVID 19 have been “disrupting sales across all vehicle classes, EVs included,” he said.

The forecast assumes a recovery from those effects over time. It projects there will be 3.3 million zero-emission vehicles (ZEVs) on the road by 2030, mostly battery-powered.

The updated forecast did not account for Gov. Gavin Newsom’s order in September that all new passenger cars and trucks sold in California must be ZEVs by 2035, but the next forecast will include it, Fugate said. (See Can California Meet Its EV Mandates?)

EV charging will produce 14,000 GWh of new demand by 2030 under the current forecast, he said.

Lower growth in population, household formation, employment and income will reduce demand over the next three years, as will decreased commercial and industrial use of electricity, he said.

Forecasting is one of the CEC’s core responsibilities and lays the groundwork for procurement and planning at the California Public Utilities Commission and CAISO. The rolling blackouts in mid-August and close calls over Labor Day weekend caused the CEC to re-examine its forecasts as part of a root-cause analysis of the blackouts requested by Newsom.

Commissioner Andrew McAllister said the forecast would not have changed significantly because of the severe heat waves that partly caused the summer shortfalls.

“It really held up well,” McAllister said. The CEC, CPUC and CAISO remain focused on ensuring reliability this summer and beyond, he noted. (See New CAISO CEO Vows Urgency on Resource Adequacy.)

Scott Leaving

Commissioners and staff spent nearly 90 minutes at the beginning of Monday’s business meeting praising Scott, who is set to become counselor to President Biden’s nominee for Interior Secretary, Rep. Deb Haaland (D-N.M.). Monday’s meeting was Scott’s last.

Scott and most of her fellow commissioners have served together for the last eight years, working as a team to pursue the state’s clean energy goals, Chair David Hochschild said.

“It’s a bittersweet day for us because it’s really hard to lose you,” Hochschild told Scott. “You have been at the core of the commission and all that we’ve done together,” including allocating billions of dollars for cutting-edge energy research and development projects, he said. Scott led the CEC’s research and development portfolio, which includes the Electric Program Investment Charge (EPIC). “Everything you’ve touched, you’ve made better,” he said.

Scott, a well known figure in energy circles, served as deputy counselor for renewable energy at the Interior Department from 2009 to 2013 under the Obama administration.

“Her leadership was noticed … and she was recruited by Gov. Jerry Brown and his team to come to California,” Natural Resources Secretary Wade Crowfoot said. Few people have been “as consequential to the state’s energy vision over the last decade” as Scott, he said.

Her departure means Newsom now has vacancies to fill on the CAISO Board of Governors, the CPUC and the CEC — the three entities largely responsible for energy in California. (See CPUC’s Randolph Named CARB Chair.)

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ISO-NE Planning Advisory Committee Briefs: Jan. 21, 2021

Eversource last week presented the ISO-NE Planning Advisory Committee with plans for two projects that would replace copper conductor and shield wire and 345-kV structures at a cost of nearly $500 million.

The copper conductor and shield wire project would cover 673 structures in Connecticut, Massachusetts and New Hampshire at an estimated $311.1 million. The in-service dates on the project range from the second quarter of this year through the fourth quarter of 2023.

The 345-kV replacements include 567 structures in the same states at about $181 million, according to Eversource’s Chris Soderman, who put forward both projects to the PAC. The work is expected to take place this year and next.

Soderman said Eversource periodically tests samples of copper conductor and shield wire obtained from existing lines during repairs and maintenance. Both materials are susceptible to thermal degradation as well as deterioration because of environmental factors.

Recent test results indicate that outer copper conductor strands have visible verdigris and black oxide in addition to excessive elongation in some strands, potentially caused by overheating. There was also severe corrosion of shield wire, and copper conductors are no longer an industry standard, making spare parts difficult to obtain. Failure of copper conductor or shield wire presents a safety hazard and creates risks to the transmission system’s reliable operation.

Soderman added that Eversource transmission lines with copper conductor or shield wire tend to be old. Copper conductor has not been installed since 1960 and shield wire since 1990. Most of the company’s transmission lines containing these materials also suffer from other age-related deficiencies and deterioration such as wood pole asset condition issues, steel lattice tower deterioration and lack of secure, high-speed telecommunications infrastructure. Soderman said many of those issues could be addressed when performing the replacements. Ultimately, Eversource will replace 80.1 miles of copper conductor and 157.6 miles of shield wire.

One stakeholder questioned Soderman about Eversource spending hundreds of millions of dollars replacing 115-kV lines with lines of the same ratings as part of the project and asked if the utility is considering an upgrade to 345-kV lines for future grid needs. Soderman said the company is reviewing possible upgrades but is seeking to strike a balance between current and future grid needs. The utility is also awaiting results of the Future Grid Initiative reliability study to better understand projected grid needs. (See ISO-NE Provides Initial Feedback on ‘Future Grid’ Study.)

Eversource manages approximately 1,250 miles of 345-kV overhead lines and over 9,000 345-kV structures. The majority of the New England 345-kV system was constructed in the 1960s and 1970s, and the structures targeted by these projects are typically wood, single-circuit structures in an H-frame configuration. Eversource will replace 6.3% of its wooden structures with light-duty tubular steel poles. The new installations must comply with current clearance and strength code requirements.

Soderman said the use of drones in inspections has resulted in a significant increase in identified defects, which indicate substantial decay and decreased load-carrying capacity of aging 345-kV wood structures. High-definition cameras on drones allow inspectors to see possible damage from all angles and take better photos of insect and woodpecker damage, pole top rot, severe fracturing, and hardware and insulator damage.

Most of the work for both projects will take place in Connecticut, where replacement of 30.1 miles of copper conductor and 70.7 miles of shield wire will cost $151 million and cover 322 structures. The 345-kV replacements in that state will include 414 structures at the cost of $135.4 million.

New Chair

Peter Bernard, PAC chair since October 2016, will step down after February’s meeting to spend more time on other duties in the RTO’s system planning department, where he is the manager of transmission planning. Bernard joined ISO-NE in 2009, following more than 15 years with National Grid, and has been directly involved in implementing FERC Order 1000 practices and procedures for the RTO during his tenure.

ISO-NE is proposing Jody Truswell to fill the role of PAC chair, according to a  memo announcing Bernard’s departure. Truswell is a senior project coordinator for transmission service at ISO-NE and the project manager for all offshore wind interconnection requests. She would become chair for the PAC’s meeting in March.

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SPP Adds Decarbonization Future to 20-year Study

Acknowledging environmental and political realities, SPP staff and stakeholders have added an accelerated decarbonization future to the RTO’s 20-year long-term assessment.

Developed by the Economic Studies Working Group, the future is designed to reflect the change of administrations in D.C. and aggressive energy and environmental policy changes. It retires all coal and oil generation, driven by a 93 to 95% emission reductions target in 2042 from 2017 levels. Environmental regulation assumptions are based on changes in federal policy, mandated carbon cuts and a carbon tax.

The future, one of four in the 2022 20-year assessment, also assumes higher solar, wind and energy storage resource additions than SPP’s normal Futures 1 and 2 because of changes in environmental policy and technology that lower capital costs and increase energy conversion efficiency.

“It makes good sense for us to study these things, given the political implications and voluntary reduction measures in the footprint,” ITC Holdings’ Alan Myers, the ESWG chair, told the Markets and Operations Policy Committee during its virtual meeting Jan. 12.

“It’s extremely important to consider how fast and aggressive environmental policy changes will affect SPP,” said Casey Cathey, the RTO’s director of system planning. “We have companies that desire this; the political climate … all these variables are pushing the envelope of renewable energy more than we’ve seen the last few years.”

The accelerated decarbonization future assumes that by 2042 SPP will have 65 GW of wind capacity and 48 GW of solar capacity, with almost 17 GW of energy storage. The grid operator already has 26 GW of installed wind capacity on its system and another 39.9 GW of proposed projects are under some form of study in its generation interconnection queue.

Other Futures

The future was one of two added to the two futures developed as part of the 2022 Integrated Transmission Plan (ITP): a business-as-usual reference case (Future 1) that reflects continued industry trends and environmental regulations, and an emerging technologies case (Future 2) driven primarily by the assumption that electric vehicles and distributed generation will affect energy growth rates. Future 1 predicts 41 GW of wind capacity and 19 GW of solar, and Future 2 foresees 50 GW of wind and 27 GW of solar.

“These are good futures to extend out. We’re saving additional work on the overworked engineering staff,” Myers said.

The fourth future, the SPP-MISO zero hurdle rate (Future 4) focuses on the potential benefit of greater market efficiency between SPP and MISO. Future 4 sets hurdle rates between the two RTOs to zero, with all other input modeling assumptions the same as Future 3.

Both Future 3 and Future 4 assume a moderate increase in SPP’s load because of increased electric transportation and electric home heating, resulting in the grid operator become a winter-peaking RTO.

Asked how SPP could ensure a quality study when the overall peak load is just over 51 GW, Cathey said the model will adjust solar and wind around conventional resources, filling in the valleys when renewable energy drops.

“It’s not just a matter of looking at 51 GW as the overall peak load. It’s a process of doing the right siting,” he said. “What we’re ultimately trying to do is determine what actually will be built … and try to simulate that. We’re trying to get ahead of the game and not wind up with congestion costs.”

The ESWG developed the futures with input from the MOPC and the Strategic Planning Committee. They will be used to create the year 2042 market economic models that will be analyzed in the assessment.

Additional sensitivities will be performed and eventually scoped out by altering some of the futures assumptions, Cathey and Myers said. Some of the potential sensitivities include load, hurdle rates for exports, gas prices and retirements.

The MOPC unanimously approved the scopes of both the long-term assessment and the 2022 ITP, which adjusts the futures with several assumptions about fossil retirements, storage and renewable capacity. Futures 1 and 2 are weighted 50/50 in the 2022 scope.

Cathey promised a more robust report on the 2022 plan during the governance meetings in April.

STEP Down

The committee also approved the 2021 SPP Transmission Expansion Plan (STEP) report that lists the grid operator’s endorsed and approved transmission projects for a 20-year planning horizon. The current plan includes all ongoing network upgrades or those where construction has been completed, but not all closeout requirements fulfilled.

The current STEP’s value has been reduced to $3.2 billion from $5.2 billion in 2019 and $4.6 billion last year.

“That represents a lot of projects that have closed out,” Cathey said.

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California Lawmakers Focus on Building Decarbonization

Legislators in Sacramento introduced a spate of bills this session to ban natural gas from new construction, promote hydrogen as an alternative fuel source and increase demand response to head off future blackouts.

A number of bills deal with building decarbonization, including measures by Sen. Dave Cortese, a Democrat who represents much of Silicon Valley. Cortese introduced a package of measures to electrify public and private structures.

“California must commit to the rapid decarbonization of our buildings to remain a global leader in the face of our climate crisis,” Cortese said in a statement.

The bills he put forth would mandate that state buildings become carbon neutral by 2035 (Senate Bill 30), instruct state agencies to develop new building decarbonization standards (SB 31), and require all cities and counties to update their general plans with the aim to decarbonize buildings (SB 32).

Other decarbonization measures include Assembly Bill 33, which would ban new gas connections in public buildings after Jan. 1, 2022 and prohibit utilities from extending gas lines to new customers. The measure by Assemblyman Phil Ting, a San Francisco Democrat, was sent to the Assembly Committee on Utilities and Energy for consideration.

The move toward building decarbonization in California and other Western states is gaining momentum as state and local governments seek to reduce carbon emissions from natural gas furnaces, water heaters and stoves. (See Cap-and-trade Bill Emerges in Wash. Senate.)

Utilities such as the Sacramento Municipal Utility District are partnering with developers to build all-electric homes and communities.

More Calif. Measures

Additional 2021-22 bills deal with grid reliability after last summer’s rolling blackouts and the continued use of public safety power shutoffs to prevent electrical equipment from sparking wildfires.

Sen. Bill Dodd, a Democrat who represents Napa Valley and serves on the Senate Energy, Utilities and Communications Committee, introduced SB 99, the Community Energy Resilience Act of 2021, to require the state to implement a grant program for local governments to develop community energy resilience plans and ensure that a reliable electricity supply is maintained at critical facilities and in areas most likely to experience a loss of electrical service.

Another Dodd bill, SB 204, seeks to bolster demand response by large industrial users during times of tight supply, including by increasing incentives for curtailing energy use.

“The bottom line is that blackouts due to imbalanced supply and demand are completely unacceptable,” Dodd said. “We need to be proactive to prevent the risk of future blackouts.”

Sen. Nancy Skinner, D-Oakland, introduced SB 18 to boost adoption of hydrogen produced using renewable power sources such as solar energy.

“Green hydrogen offers many climate and energy co-benefits, including better utilizing curtailed power and better integrating renewable resources into the electrical grid to achieve greater than 100 percent zero-carbon energy and put renewable electricity to use to decarbonize many other sectors of the economy,” the bill says.

Skinner’s bill seeks a state “strategic plan for accelerating the production and use of green hydrogen” and recommendations on “how to overcome market barriers and accelerate progress in green hydrogen production and use.”

The fuel source is a potential competitor to battery-powered electric vehicles and could supplement natural gas in existing pipelines, advocates say.

Bills introduced in the 2021-22 session may fare better than energy-related measures in the previous session. In 2020, the start of the pandemic meant many bills died in committee as lawmakers stayed home or focused on measures to fight the coronavirus outbreak when they were in session.

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MISO Reevaluating Value of Loss Load as Monitor Pushes $10,000/MWh

MISO on Friday said it will soon present proposals for reformulating its value of lost load (VoLL) while its Independent Market Monitor once again urged the RTO to nearly triple the current value during a scarcity pricing workshop teleconference.

Monitor David Patton said MISO should bump its VoLL to $10,000/MWh from the current $3,500/MWh, an increase the Monitor has been recommending for more than three years.

Patton said different areas of the footprint place different importance on avoiding interruption of service. Referring to a Lawrence Berkeley Labs model with 2018 data, Patton said MISO residential outage costs range from $3,600 to $3,900/MWh depending on customer income, only “escalating modestly” from the current VoLL. However, commercial and industrial customers place a much higher value on interruptions, ranging anywhere from $32,000/MWh for a non-manufacturing customer to $73,000/MWh for manufacturers. He said commercial and industrial VoLL can go even higher, but those customers would probably have installed backup generation.

Patton said he weighted those amounts based on MISO load data to identify an average value of $23,000/MWh. However, he said the RTO should use a “more reasonable” and more economic $10,000/MWh.

“Very few shortages will occur in that range,” Patton explained of the upper bounds of the operating reserve demand curve (ORDC).

MISO’s ORDC based on VoLL, begins at $3,300/MWh, dropping to $2,100/MWh for much of the curve when the RTO clears 8% of its requirement level. At 89%, the level falls to MISO’s original $1,100/MWh, remaining there until 96% or more of the requirement is cleared, when the curve flattens at $200/MWh.

The Monitor is calling for a curve that eliminates step-based pricing in favor of a gently sloped descent from $10,000/MWh.

Patton said shortage pricing is important because MISO’s capacity market doesn’t provide sufficient performance incentives. He said the growth of intermittent resources, which lead to “more output uncertainty and more frequent shortages,” means economic reserve pricing will become more critical. Higher scarcity prices will provide a “natural buffer” for non-intermittent resources to stave off retirement, he said.

He added that a higher VoLL will better ensure that MISO can cover its load in shortage conditions, competing with PJM’s more attractive pricing.

“When both MISO and PJM are in a shortage, there’s no question that generators will sell to PJM, whether the generators are in PJM or MISO,” Patton said. “Certainly, it’s not completely solved. I think [this] will go a long way in ensuring our prices are more in line.”

Patton said even with the increase, PJM will still produce higher shortage prices more of the time.

FERC Filing on the Horizon

MISO Principal Adviser of Market Design Mike Robinson said the RTO is using the Monitor’s analysis as a “starting point” for updating pricing but must also account for the footprint’s geographic diversity.

The RTO has not updated VoLL pricing since 2009. Robinson acknowledged MISO’s reliability-based vertical demand and supply curve “do not meet” in a way that signals new, appropriate price ranges.

Director of Market Design Kevin Vannoy said MISO hopes to file an updated VoLL with FERC in June. He said staff will appear before the Market Subcommittee during spring meetings to discuss alterations and ORDC changes.

Some stakeholders said MISO was on an ambitious timeline considering it hadn’t yet decided if VoLL should apply to force majeure events or used to price dead buses. (See MISO Questions VOLL Pricing During Abnormal Events.)

“It just seems like MISO is going about reestablishing VoLL without first discussing where VoLL can applied,” Xcel Energy’s Kari Hassler said.

Great Plains Institute’s Matt Prorok asked MISO to consider the increasing electrification of essential services when valuing lost load.

“You’re right, those will affect the values,” Robinson said.

Akshay Korad, research and development engineer at MISO, said the RTO would have to update its LMP cap when it pursues a VoLL change because LMPs are capped at VoLL. Korad said the cap was a “design decision made at the beginning of the market that was never revisited afterwards.” He said MISO and stakeholders should decide whether to continue capping LMPs at the new VoLL or another value or stop capping LMPs altogether.

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PJM MRC/MC Preview: Jan. 27, 2021

Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability and Members committees on Wednesday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

Consent Agenda (9:05-9:10)

B. The MRC will be asked to endorse proposed revisions to Manual 6: Financial Transmission Rights addressing the enforcement of FTR bid limits at the corporate entity level. Revisions include adding a bullet to Section 6.6 regarding “FTR Auction Business Rules” denoting the rule for FTR auction bid limits at the corporate entity level. (See “FTR Bid Limits Changes,” PJM MIC Briefs: Dec. 2, 2020.)

C. Members will be asked to endorse proposed revisions to Manual 12: Balancing Operations resulting from the periodic review. The changes include updating the out-of-date two settlement terminology to day-ahead market terminology in the markets database application and adding references to the Dispatch Interactive Map Application and reliability assessment and commitment tool.

D. The committee will be asked to endorse proposed revisions to Manual 13: Emergency Operations resulting from the periodic review. Changes include an updated note in Section 2.2: Reserve Requirements increasing the proportion of contingency reserves that can consist of interruptible load from 25% to 33%.

E. The MRC will be asked to endorse proposed revisions to Manual 18: PJM Capacity Market conforming to the PJM MIC Briefs: Jan. 12, 2021.)

F. Stakeholders will be asked to endorse proposed revisions to Manual 38: Operations Planning resulting from the periodic review. The revisions were unanimously endorsed at the Operating Committee meeting Jan. 13. (See “Manual Endorsements,” PJM Operating Committee Briefs: Jan. 13, 2021.)

Endorsements/Approvals (9:10-11:30)

1. Manual 14C Revisions (9:10-9:30)

The MRC will be asked to endorse proposed revisions to Manual 14C: Generation and Transmission Interconnection Facility Construction as part of the biennial cover-to-cover review. Stakeholders voted to delay the revisions at the MRC meeting Dec. 17 after concerns arose over some of the proposed manual language. (See “Manual 14C Delayed,” PJM MRC/MC Briefs: Dec. 17, 2020.)

2. Real-time Values Market Rules (9:30-9:50)

Members will be asked to endorse a solution package addressing real-time values (RTV) market rules and corresponding revisions to Manual 11: Energy & Ancillary Services Market Operations and the tariff and Operating Agreement. Stakeholders endorsed PJM’s package of updates to RTV that call for additional penalties for generation operators that abuse the rules. (See “Real-Time Values Market Rules,” PJM MRC/MC Briefs: Dec. 17, 2020.)

3. PRD Credits Disposition (9:50-10:10)

The MRC will be asked to endorse a proposed solution package addressing the disposition of price-responsive demand (PRD) credits and corresponding revisions to Manual 11: Energy & Ancillary Services Market Operations, Manual 18: PJM Capacity Market, OA, tariff, and Reliability Assurance Agreement. PJM’s settlement rules call for revenues associated with PRD to be credited to the load-serving entity for an area and do not address the roles of electric distribution companies (EDCs) or curtailment service providers (CSPs), meaning some LSEs are paid for PRD service supplied by EDCs and CSPs. (See “PRD Credits Disposition,” PJM MRC/MC Briefs: Dec. 17, 2020.)

4. Stability Limits in Markets and Operations (10:10-10:50)

Members will be asked to endorse a proposed capacity constraint solution package and corresponding OA and tariff revisions regarding stability limits capacity constraints. The proposal addresses the allocation of limits to multiple units by stating that the limit will apply to the sum of the output of the affected units plus ancillary service megawatts. (See “Stability Limits Review,” PJM MIC Briefs: Dec. 2, 2020.)

5. Black Start Unit Testing, CRF, Involuntary Termination, MTSL and Substitution Rules (10:50-11:30)

Stakeholders will be asked to endorse proposed solution packages addressing black start unit testing, involuntary termination, substitution rules, capital recovery factor (CRF) and minimum tank suction level (MTSL), and corresponding revisions to the tariff, Manual 12: Balancing Operations, Manual 14D: Generator Operational Requirements and Manual 15: Cost Development Guidelines. The black start issue has been lingering for months, leading to heated discussions. (See Gen Owners Balk at Change to PJM Black Start Rates.)

Members Committee

Consent Agenda (1:20-1:25)

B. Members will be asked to approve proposed revisions to Manual 34: PJM Stakeholder Process addressing the preference for status quo. The change provides clarifying language to affirm that the preference over the status quo 50% requirement is binding. (See “Manual 34 Revisions,” PJM MRC/MC Briefs: Nov. 19, 2020.)

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ISO-NE Provides Initial Feedback on ‘Future Grid’ Study

ISO-NE said last week that stakeholders’ proposed schedule for the Phase 1 reliability and market analyses in the Future Grid Initiative is “aggressive but achievable” if there are no delays or changes in assumptions or scenarios.

NEPOOL asked ISO-NE in late December to provide feedback on the stakeholder-developed framework document that outlines the modeling for the project, which is intended to predict the impact of states’ policies to reduce carbon emissions and electrify transportation and buildings.

Carissa Sedlacek, ISO-NE’s director of planning services, told a joint meeting of the NEPOOL Markets and Reliability committees Jan. 19 that the RTO has the software to perform all four of the Phase 1 studies in the framework document first brought before the committees in December: simulations of production costs and ancillary services, a resource adequacy screen and a probabilistic resource availability analysis. The RTO said, however, that it lacks the tools to conduct the three Phase 2 analyses — revenue sufficiency in the capacity market and transmission thermal and voltage impacts — recommending NEPOOL hire a consultant. (See New England ‘ Future Grid’ Study Takes Shape.)

Sedlacek said the RTO’s ability to produce a Phase 1 report by May 2022 as requested depends on the “final clarity” of the assumptions and the ability to supply necessary model input data in a “timely manner.”

ISO-NE plans to use staff from past annual economic studies for most of Phase 1 but said the work could delay completion of any additional economic studies requested this year. If ISO-NE is asked to conduct another economic study, the RTO said it would be performed after completing the 2020 economic study for National Grid, which has an expected finish date of June 1.

It said that the Future Grid’s study’s reference to “current state energy and environmental laws” should also mention current market rules and assume the laws and tariff rules in effect as of Dec. 31, 2020.

To aid in comparing study results, the RTO added that it “strongly” recommends using a single target year in studies rather than 2035 for some scenarios and 2040 for others.

ISO-NE said it expects to conduct the Phase 1 work concurrently with its evaluation of the potential pathways part of the Future Grid Initiative which will start next month. The pathways being considered are a Forward Clean Energy Market or Integrated Clean Capacity Market, an Energy Only Market, carbon pricing and alternative resource adequacy constructs. (See Report Outlines NEPOOL ‘Pathways’ to a Future Grid.)

Sedlacek said the RTO would continue to review Phase 1 of the framework to identify any needed clarifications, and it may take up to three months to fully develop and define all study inputs. For the February MC/RC meeting, the RTO will develop a detailed plan for conveying updates on the status of the Phase 1 analyses. It plans to report its progress on the work monthly at the Reliability Committee. Detailed presentations of both interim and final results could be held via additionally scheduled MC/RC meetings.

Schedule

Study assumptions for the first phase of the report are expected to be completed by March 1. The final production cost simulation is scheduled for September 2021 to March 2022, and the ancillary services simulation from September 2021 to January 2022. MARS analyses will occur between October 2021 and January 2022. Drafting of a final report is expected to begin in February 2022.

Dates have not been set for the revenue sufficiency analysis and system security analyses in Phase 2, but they will not start before September 2021.

ISO-NE said there is no model for studying the detailed, operational dispatch needs of the future system — with significant inverter-based resources, interaction between transmission and distribution systems, and evolving load profiles. The RTO is developing a model internally but says it will be a “time-intensive … multiyear effort.”

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NY Grid Study Pushes Meshed OSW Transmission, Coordination

New York state energy agencies on Tuesday released a three-part study that urges faster permitting, planning and approval processes to build the transmission necessary to accommodate the nearly 40 GW of new renewable energy plugging into the grid over the next two decades.

The Initial NY Power Grid Study Report recommends that transmission planners increase their reliance on NYISO’s stakeholder processes, particularly for developing public policy projects. It says the most urgent needs are to link Long Island’s expected 3 GW of offshore wind energy with the mainland and to beef up the infrastructure needed to import 6 GW of OSW into New York City.

The state’s Department of Public Service and the New York State Energy Research and Development Authority (NYSERDA) prepared the study, supported by The Brattle Group and Pterra Consulting, among others.

“‘Initial’ means it’s the 2021 installment, and ‘full’ means it is complete at about 750 pages of work,” Public Service Commission Chair John Rhodes, said in announcing release of the report at a meeting of the state’s Climate Action Council.

The PSC ordered the report last May, as directed by the Accelerated Renewable Energy Growth and Community Benefit Act (Case No. 20-E-0197). (See NYPSC Launches Grid Study.)

The study comprises three components, examining transmission needs for OSW and bulk system needs for land-based renewables out to 2040, as well as needs on the sub-bulk level.

“We think it’s very well done. We know it’s informative, has many interesting findings and is a major milestone in terms of creating the information foundation for us to craft the right kind of transmission future for the state,” Rhodes said.

Procuring 9 GW of OSW by 2035 is vital to meeting the goals established by the Climate Leadership and Community Protection Act, which mandates that 70% of electric power in New York come from renewable resources by 2030 and that electricity generation be 100% carbon-free by 2040.

Local transmission and distribution (Phase 1) projects already under development appear sufficient to integrate land-based renewables, although some might be accelerated, the report said.  Other more preliminary (Phase 2) projects might be pushed forward in order to attract investment in solar and wind development Upstate.

“In particular, [New York’s] Zero Emissions Study results suggest that additional bulk transmission from Upstate into the New York City area (from Zone H to Zones I, J and K) will likely become cost effective as the state approaches 2040 and congestion costs increase,” the report said.

OSW Scenarios

In calling for the start of development of a tie-line between Long Island and Zone I or J, the study said that “all studies indicate that additional tie-line capacity would be needed by 2035–2040 as renewable requirements grow and emissions limits tighten. Advancing such a project would provide additional value earlier if constraints into New York City force more than 3,000 MW of OSW into Long Island and mitigate curtailments associated with real-world operating conditions not captured in the studies’ simulations.”

The report also urged a multidisciplinary planning and coordination effort for routing up to 6 GW of OSW generation into New York City and interconnecting it with the city’s substations.

“However, overcoming cable routing limitations in New York Harbor, space constraints in substations in Manhattan, and permitting complexities in both the Harbor and along the Long Island coastline (including approaches to New York City through the Long Island Sound) will require careful planning of OSW transmission cable routes and points of interconnection,” the study said. “Creating the option for a meshed offshore network by linking the offshore substations of several individual OSW plants near each other is valuable because a meshed configuration can achieve a more reliable and resilient delivery of OSW generation.”

The study concluded that a decision to implement a meshed system can — and possibly should — be delayed pending federal approval of new wind energy areas, as long as New York officials ensure that any projects with radial connections are built with an option to integrate into a meshed system later.

In its comments related to the study, NYISO said transmission congestion and curtailment patterns drive bulk transmission expansion, which the study contends will be necessary to integrate all the new renewable energy resources being developed under state clean energy policies.

To inject OSW energy, smaller megawatt amounts at more points of interconnection could potentially require less transmission expansion, NYISO said.

However, “based on the cable routing study conducted by the DPS’s technical consultant, there appear to be limited available cable routings through New York Harbor. If each project has independent radial connections, opportunities for necessary cabling to achieve the full offshore wind goal of 9,000 MW will be limited,” The ISO said.

“The study makes clear that to overcome interconnection challenges and achieve this [9 GW] goal, New York needs carefully planned offshore wind cable routes and points of interconnection that will ensure reliable, resilient delivery of offshore wind energy to power New York homes and businesses,” Janice Fuller, Anbaric’s Mid-Atlantic president, told RTO Insider. “Governor Cuomo has called on the market for creative proposals to meet this critical challenge.”

Local T&D Cost Allocation

The report found that Phase 1 local transmission projects would unbottle delivery of an estimated 6.6 GW of renewable generation, while proposed Phase 1 distribution projects could tap another 2 GW. The study estimates that the more preliminary Phase 2 project proposals for local transmission could provide 12.7 GW of renewable integration benefits, based on the headroom calculations, while Phase 2 distribution proposals could support an estimated 2.8-4.3 GW.

Both utility and NYISO transmission planning processes should be improved to recognize the unique advantages that advanced technologies such as dynamic line ratings can provide, the study said. For example, commercial-scale applications for dynamic line ratings “have demonstrated a 20-30% increase of average annual transmission capacity above static ratings (e.g., with a 10% increase during 90% of the year, 25% during 75% of the year, and 50% during 15% of the year), while maintaining or enhancing system reliability.”

The power grid study also recommends allocating the costs of these projects state-wide on a load ratio share basis, as recommended by the state’s investor-owned utilities, which in November jointly filed a report on transmission and distribution investment. Representatives from each company joined a technical conference to outline their policy recommendations and propose projects to state officials. (See Meshed OSW Tx Grid May Work Best, NY Officials Hear.)

The IOUs include Avangrid subsidiaries New York State Electric and Gas and Rochester Gas and Electric; Central Hudson Electric and Gas; Con Edison and its subsidiary Orange and Rockland; and National Grid subsidiary Niagara Mohawk Power. Collectively the utilities propose to spend $7 billion on transmission and distribution upgrades by 2025 and an additional $10 billion over the following five years.

The IOUs’ comments on the new grid study reiterated points from their earlier report and incorporated learnings from the technical conference Nov. 23, noting “the fundamental need” for local transmission and distribution investment to support the integration of clean energy resources. “In other words, the zero emissions grid presentation recognized that there is a clear interdependence between the local and bulk transmission system upgrades; without resolving the congestion and curtailments on the LT&D system, the value to customers of new bulk transmission investments and renewable generation will be limited,” they said.

Con Edison identified three immediately actionable projects around New York City, estimated at $860 million. The utility on Dec. 30 filed a petition with the PSC seeking approval to recover project costs through its rate plan capital budget, and also for up to $4 billion for the second phase of six projects to create points of interconnection, including two new “NYC Clean Energy Hubs,” several new feeders and the rebuilding of two area stations.

Multiple Intervenors, a coalition of large industrial, commercial and institutional energy customers, submitted comments on the new grid study emphasizing that “customer funds are not unlimited, particularly in the aftermath of the economic recession caused by the COVID-19 pandemic.” The group urged the commission “to ensure that customers — and especially energy-intensive/trade-exposed businesses that are price-sensitive — are not burdened with excessive or unnecessary costs.”

New York City said the PSC should deny Con Edison’s requests for pre-approval as the report does “not provide sufficient information to provide a rational basis for such a decision,” and should also consider mechanisms for cost containment to help control the costs of the additional infrastructure that will be needed.”

The New York Power Authority (NYPA) said that a cost allocation approach in which NYSERDA would use System Benefits Charge funds to pay for transmission improvements supporting state policy goals would be “extremely difficult to exercise with NYPA” because its customers do not pay the charge, nor does NYSERDA have legal authority to charge NYPA’s municipal customers.

NYPA supports a proposal for the PSC to authorize a retail charge that would be distributed as appropriate among utilities pursuant to a commission-approved adjustment mechanism, which “means cost recovery would be set within retail rates and would not require a proceeding at FERC or any additional approval.”

NYISO Views

The state will likely need new transmission system facilities if more renewable resources are assumed to locate in Western New York, Northern New York and the Southern Tier as development trends suggest, the ISO said.

The grid operator said that NYSERDA awards of renewable energy credits to date support the conclusion that renewable investments will concentrate in certain geographic areas, and that its 2019 Congestion Assessment and Resource Integration Study (CARIS), released last July, provides insights into the potential value of additional transmission capability across the state.

“In the 70×30 Scenario simulations, approximately 11% of the annual total potential renewable energy production would be curtailed across the New York system,” NYISO said.

The power grid study said that more work will be necessary to quantify existing headroom in various transmission-constrained areas on the local and bulk transmission systems and “to identify high-priority, high-value locations that should be targeted with transmission upgrades. These studies should be based on both a power-flow model that better measures headroom capacity and a production simulation model — ideally aligned with the NYISO’s economic planning process assumptions and modeling tools — that can estimate annual curtailments and the extent to which proposed upgrades can reduce these curtailments.”

Based on its interconnection queue, over 90% of the land-based renewable capacity proposed outside New York City and Long Island is in NYISO Zones A through E, leaving less than 10% in Zones F and G, NYISO said.

The ISO referred to its own climate change impact and resilience study and to a decarbonization pathways study by NYSERDA, saying that both 2020 reports support the need for firm capacity to meet multi-day periods of low wind and solar output, a need most pronounced during winter periods of high demand for electrified heating and transportation.

Regarding bulk system storage resources, NYISO said a model should reflect their operational charging and discharging cycles as well as the probability of their availability.

NYISO also supports the use of its public policy process to solicit competitive solutions, a process it says should now take approximately 18 months following the PSC’s identification of such a transmission need.

The ISO’s Market Monitoring Unit, Potomac Economics, questioned NYISO’s benefit/cost analysis methodology for local transmission planning, saying that if “it relies on biased assumptions, there is a risk that viable alternative solutions that are more cost-effective or do not rely on ratepayer guarantees will be crowded out.”

In particular, the Monitor said that the CARIS 70×30 case was never designed to be an accurate forecast of the power system in 2030 and hence does not provide a reasonable basis for evaluating the benefits of individual transmission proposals.

“First, we recommend developing economic criteria for future resource inclusion in the forecast model and using multiple realistic scenarios when assessing projected curtailment. Second, we recommend changes to the LBMP, capacity value, cost of capital and period of analysis assumptions that will more accurately quantify projects’ benefits and risks,” the Monitor said.