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November 6, 2024

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ERCOT, PUC Say Grid is Ready for Winter Weather

The new year began in Texas with an arctic cold front sweeping away the previous week’s 80- to 90-degree temperatures and bringing ice, snow and a brutal reminder of last February’s destructive winter storm.

This time around, ERCOT has inspected 324 generation plants and transmission facilities to check compliance with new winterization rules. The Public Utility Commission has tweaked market rules to allow the grid operator to set aside more operating reserves and to do so sooner. And effective New Year’s Day, ERCOT’s systemwide offer cap has been set at $5,000/MWh, down from the $9,000 cap that sent several retailers and cooperatives into bankruptcy after the February storm.

Electricity usage during the cold snap was down too, over 20 GW less than the record peak demand on Feb. 14 that the ERCOT grid was unable to handle. The return of springlike temperatures later this week, exemplifying the dry La Niña conditions expected this winter, has further eased concerns.

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Alison Silverstein

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“Easy peasy,” energy consultant Alison Silverstein, a former FERC and PUC staffer, said Saturday. “Pretty sure ERCOT can handle this shift.”

But another February storm, which became energy Twitter’s story of the year?

ERCOT, the PUC and Texas Gov. Greg Abbott say the system is ready.

“Texans can be confident the electric generation fleet and the grid are winterized and ready to provide power,” said Woody Rickerson, ERCOT vice president of grid planning and weatherization.

“The lights will stay on,” promised PUC Chair Peter Lake during a December press conference. (See Texas PUC Chair Lake: ‘The Lights Will Stay On’).

Texas power plants “are good to go,” Abbott tweeted.

The problem is, the same can’t be said of the natural gas system, which has borne the brunt of the blame from FERC, NERC and others for the storm’s outages because of fuel unavailability. A Federal Reserve Bank of Dallas study has estimated it will cost as much as $50,000 to winterize a wellhead. (See FERC, NERC Release Final Texas Storm Report.)

Texas lawmakers passed legislation requiring both the electric and gas industries to weatherize against extreme temperatures. However, a loophole allows gas facilities to opt out for a nominal fee. The gas network is being mapped to determine those facilities critical to power production, but that process isn’t expected to be finished until 2023.

Yes and no — thanks to the power plant winterization initiative.

“The odds are much, much lower that half of ERCOT’s generation fleet will fall to freezing weather,” Silverstein told RTO Insider. “But because neither the gas producers and pipelines have made comparable efforts to winterize their production, we have no guarantee that freeze-ready natural gas plants will have fuel to burn.”

Silverstein said ERCOT’s more conservative operating plans and a better statewide communications plan to improve awareness of winter-weather threats and potential electric shortfall could also help avoid repeats of another major winter power outage, similar to those of 2011 and 2021.

“If they can get through 2022 without another major outage or call for conservation, that’ll look like success,” Silverstein said. “But that’s a sadly low bar.”

Energy-only No Longer?

PUC, ERCOT and their stakeholders are also taking a second look at the grid operator’s energy-only market, which pays generators only when they are providing energy to the market. The PUC has developed a two-phase process, with a Phase 1 implementation plan due Jan. 10.

The second phase will evaluate a proposed backstop reliability service and a load-side reliability mechanism that Lake has been pushing since October. ERCOT staff have promised to provide a report on what it will take to design and build each of the Phase 2 proposals on Feb. 15, the one-year anniversary of when the outages began. (See PUC Forges Ahead with ERCOT Market Redesign.)

PUC staff issued a memo laying out the Phase 2 proposals and requesting stakeholder input. The commissioners received 54 filed comments before a Dec. 10 deadline but have yet to publicly address those comments.

Lake has favored the load-side reliability mechanism, but the other three commissioners have offered some pushback. The mechanism will be developed according to a set of principles that include offering economic rewards and providing “robust” penalties or alternative compliance payments based on a resource’s ability to meet established standards; building on ERCOT’s existing renewable energy credit trading program framework; providing a forward price signal to encourage investment in dispatchable generation; using dynamic pricing and sizing to ensure reliability needs are met without over-purchasing reserves; and mitigating market-power concerns for generation companies that also serve retail customers. (See Study Suggests Texas LSEs Can Provide Reliability.)

The proposed backstop reliability service would procure accredited new and existing dispatchable resources as an insurance policy to help prevent emergency conditions. The service’s principles include nonperformance penalties and clawbacks for noncompliance; deploying resources in a manner that doesn’t negatively affect real-time energy prices; and allocating costs to load based on a load-ratio share basis measured on a coincident net-peak interval basis.

“Phase 2 … is a grab bag of a bunch of different ideas with basically no specifics. It’s unclear, confusing, and it’s impossible to tell what it will mean for the market,” Stoic Energy President Doug Lewin said. “The regulatory uncertainty around this vague ‘blueprint’ will likely slow down development from lots of different developers, including storage developers.”

The renewable industry has criticized backstop reliability, saying there are ways to improve reliability without favoring generation. They point to storage, demand response, energy efficiency and real-time co-optimization, which has been pushed back to 2024, at the earliest.

“We saw comments from [clean-energy buyers] that really pointed to the risk of the commission trying to add new reliability costs to renewable energy,” said Colin Meehan, a clean-energy analyst, during a December virtual panel discussion. “Their members represent about 500,000 employees in the state of Texas. These are … big businesses that are very concerned about the commission’s moves to add costs to renewable energy.”

“Renewables are clearly very important to our energy future, but the Texas PUC is considering changes that would make renewables more expensive at the behest of Gov. Abbott and his fossil fuel industry contributors,” Environment Texas Executive Director Luke Metzger said in a statement. “That could lead some projects to get canceled or scaled back, making the grid less reliable and dirtier. That’d be like cutting out our nose to spite our face.”

Metzger issued the statement after ERCOT last week released its latest long-term look at its expected capacity. Texas already leads the nation in wind production, with the grid operator listing more than 28 GW of installed capacity. The grid already has more than 10 GW of solar, a number that is expected to exceed 19 GW by the end of 2022.

That doesn’t take into account second thoughts developers might have, given the regulatory uncertainty over ERCOT’s future market design. Texas politicians were quick to blame renewables for the February disaster, but half of the grid’s thermal generation was inoperable during that time.

On Sunday, more than 10 GW of thermal generation was unavailable during the year’s first cold snap.

Silverstein is among the many stakeholders calling for a more significant reliability analysis to determine exactly what reliability issues need to be solved.

“That is not at all clear. … [It] requires a significant amount of sophisticated analysis that nobody has done at ERCOT and no one has done anywhere else either,” she said.

Unless the commission “commits to a slower, more deliberate pace with more transparent analysis and broader consideration of options,” Silverstein said, the market design’s second phase will be “another disaster for those of us in the public and industry who want to see Texas’ electric system and market follow a thoughtful, stakeholder-informed, analytically based, transparent and provably reasonable policy development process with outcomes that are demonstrably reliability-improving and cost-effective.”

Lewin said the PUC wasted “precious time” on the load-side reliability mechanism, “an extremely unpopular idea which had the support of only a handful of stakeholders out of scores of commenters.”

“The PUC spent very little time on ideas with more support,” he said, listing needed improvements to black start, increasing energy efficiency and demand response, and finding ways to increase storage. “I hope there’s a pivot to focus on changes that will meaningfully increase reliability.”

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Build Back Better and Beyond: Insights for the Year Ahead

While the fate of the Build Back Better (BBB) Act — and its $555 billion in funding for clean energy tax incentives and other programs — was knocked off the front pages toward the end of the year by the resurgence of COVID-19, the bill will likely reclaim some attention this month.

Triggered by Sen. Joe Manchin’s (D-W.Va.) pronouncement Dec. 19 that he would not support the Democrats’ $2 trillion budget reconciliation package in its current form, the holiday cliffhanger had Senate Majority Leader Chuck Schumer (D-N.Y.) declaring a vote on the bill would be held this month. (See Manchin Says ‘No’ on Build Back Better).

But, as reported by POLITICO, Manchin wants the bill to go through a full committee process in the Senate, which could take months. Also, his top priority for a reworked BBB appears to be rolling back the 2017 tax cuts, something that has thus far not been a part of the bill.

BBB has become a political football in a highly politicized midterm election year, with COVID, inflation and ongoing supply chain issues providing significant headwinds. While Manchin is adamant he will not be pressured, Democrats’ determination to get the bill passed with some of its basic energy and social spending initiatives intact could provide the momentum needed to find the necessary compromises.

Still, tough decisions may lie ahead if the bill’s energy provisions have to go through the Senate Energy and Natural Resources Committee, which Manchin chairs. The West Virginian’s oft-repeated view on the U.S. energy transition is that it should be driven by innovation, not elimination, specifically of fossil fuels; hence his strong support for carbon capture, sequestration and storage, advanced nuclear and green hydrogen. He has also opposed increased tax credits for electric vehicles assembled in U.S. factories that have union labor contracts.

A committee process might also give Manchin the opportunity to expand BBB with a bill he and Sen. John Barrasso (R-Wyo.) introduced a few days before his withdrawal of support for the reconciliation package. Under the Fission for the Future Act, the Department of Energy would provide funding to site advanced nuclear facilities and infrastructure in communities affected by the closure of fossil fuel plants.

The importance of BBB to President Biden’s political agenda cannot be overstated: The energy funding is critical if the U.S. is to achieve a 100% clean grid by 2035 and a net-zero economy by 2050. These targets, set by Biden in the first days of his term, are themselves essential to U.S. leadership in global efforts to limit climate change to 1.5 degrees Celsius, as reaffirmed at the 26th U.N. Climate Conference of the Parties in Glasgow in November.

The Transition on the Ground

At the same time, a narrow focus on BBB obscures a broader view of U.S. progress toward a decarbonized grid and economy. Beyond what Biden has been able to accomplish — from his executive orders to the signing of the bipartisan Infrastructure Investment and Jobs Act (IIJA) — the transition at the ground level continues to be driven by the ambitious commitments and innovative programs of cities, states, utilities and corporations.

For example, a staunchly Republican legislature in North Carolina this year passed a law committing the state to reducing carbon emissions by 70% by 2030 and setting equally aggressive targets for adding 2,660 MW of renewable energy to the state’s grid.

Google pushed beyond an initial goal of running its operations on 100% clean energy to a new 2030 target of 24/7 clean power, matching its demand hour for hour with carbon-free electricity. In September, it joined the U.N. and other organizations in launching a global initiative of local governments, utilities and corporations committed to the 24/7 goal.

The spread of clean energy will continue to accelerate in 2022, as long as prices drop and efficiency and innovation improve. The key questions now revolve around how fast the transition can be accomplished and who will benefit.

The U.S. has seen many technological transitions that, by their very nature, create winners and losers. What differentiates the current transition is the recognition of past and ongoing inequalities — jobs lost and communities affected — and the corresponding efforts to provide targeted support, retraining and opportunities for new economic development.

Like BBB, 2022 could be a pivotal point for gauging how fast and how equitable the transition will be. State and local efforts will bear close watching, as will corporate and regulatory actions. But federal leadership will continue to be a vital catalyst.

The DOE Factor

Outside of BBB, Biden’s top catalyst for advancing the U.S. transition to clean energy is DOE. The past year saw a stream of new program announcements and funding opportunities, which will undoubtedly continue in 2022.

For example, even as supply chain delays have raised solar hardware costs, DOE has been working on cutting the “soft costs” of local permitting through its release and promotion of SolarAPP+, a platform that standardizes and streamlines the permitting process.

After hitting 127 SolarAPP+ cities in September, Energy Secretary Jennifer Granholm announced a new goal of adding 60 communities to DOE’s SolSmart program, which provides technical assistance to cities to help them further streamline solar planning and permitting.

In the wake of Manchin’s no-go on BBB, Granholm on Dec. 21 launched a new Office of Energy Demonstrations, funded with $20 billion from the IIJA, to support pilots in hydrogen, small modular nuclear and grid-scale storage.

The office could be a springboard for DOE’s Earthshots initiative, which is focused on accelerating innovation and cutting costs for key low- and no-carbon technologies, including green hydrogen, long-duration storage and carbon capture. The Hydrogen Shot, for example, aims to cut the cost of green hydrogen 80%, from $5/kg to $1/kg, in one decade.

A year-end webinar for the DOE team also highlighted the revitalization of the department’s Loan Program Office (LPO) under former cleantech entrepreneur Jigar Shah. According to Sydney Bopp, LPO chief of staff, the office is now processing 66 applications seeking $53 billion in loans and loan guarantees and has another 50 applications in early development.

Prospects cover “critical minerals processing, manufacturing, advanced nuclear, energy storage, carbon capture, hydrogen, sustainable aviation fuels, EV charging infrastructure, advanced geothermal, hydropower, offshore wind transmission and virtual power plants,” Bopp said.

Granholm hinted at “some exciting news coming out of LPO early next year.”

The secretary has also been a tireless and strategic booster for BBB and the jobs it will create, while helping the U.S. regain its leadership role in global energy markets. One of Granholm’s constant themes is the $23 trillion global market the energy transition is going to create and the imperative for the U.S. to win back competitive leadership from China and Europe.

Energy and Transportation

As former governor of Michigan, Granholm is also aware of the need to bring older, traditional industries and their workers into the energy transition; hence her embrace of advanced nuclear, hydrogen and carbon capture. Under her leadership, DOE’s Office of Fossil Energy has been rebranded as the Office of Fossil Energy and Carbon Management.

For some progressives, these technologies — which even conservatives like Barrasso support — are still suspect, but in 2022, they might also provide an initial common ground and point of compromise.

With broad buy-in from automakers and unions, transportation electrification may present similar opportunities; it also heads the list of high-impact technologies getting a boost from federal support in 2022. Cars and trucks account for 29% of all U.S. greenhouse gas emissions, more than any other sector of the economy, according to EPA. The infrastructure package attacks a major obstacle to cutting those figures — making EV charging easy and convenient — with $7.5 billion for deploying 500,000 EV chargers nationwide.

Granholm and Transportation Secretary Pete Buttigieg on Dec. 14 launched the Joint Office of Energy and Transportation, which will develop guidelines and standards for deployment of EV chargers and provide technical assistance for state planning to make the most effective use of the federal funds. The photo op for the announcement had Granholm and Buttigieg charging up a Ford Mustang Mach E at RS Automotive in Takoma Park, Md., a local small business billed as the nation’s first former gas station to replace all its pumps with EV chargers.

The ambitious fuel efficiency standards announced by EPA on Dec. 20 — a fleetwide average of 40 mpg by 2026 — will be another catalyst for near-term growth of vehicle electrification. EPA predicts EVs will account for 17% of light-duty vehicles in the U.S. by 2026, and automakers have said that federal support will be critical for reaching those figures. (See EPA Rules Will Slash Vehicle Emissions, Rev up EV Market by 2026.)

So, even if Manchin nixes the $4,500 union-labor add-on, strong support from the auto industry and labor unions could keep the standard $7,500 federal rebate for EVs in BBB.

Tax Incentives and Supply Chains

The renewable energy industry is similarly tooling up for a major lobbying campaign in the new year to keep BBB’s 10-year extension of the solar investment tax credit and the addition of tax incentives for standalone storage, transmission and cleantech manufacturing.

The industry is also intensely focused on supply chain issues, which are raising prices and could slow market growth in 2022 by as much as 25%, according to the latest solar market report from Wood Mackenzie and the Solar Energy Industries Association.

Storage, and especially long-duration technologies, could be the winners here, providing potential solutions for both reliability and supply chain issues. Released in June, Biden’s executive order addressing the latter includes a list of provisions aimed at building up the country’s mining and processing of critical minerals, like lithium. The need is pressing and strategic as the U.S. is largely dependent on China for lithium processing.

The LPO is ready with $3 billion in loan guarantees “to support efficient end-use energy technologies, such as mining, extraction, processing, recovery or recycling technologies,” according to a White House fact sheet.

The executive order also calls for a cross-agency task force to tackle environmental and permitting issues, a pressing need regularly raised on both sides of the aisle. The infrastructure law gives FERC the authority to designate national transmission corridors and approve projects in these corridors, if necessary, over the objections of state regulators. Transmission advocates and opponents are watching closely to see if and how FERC uses this power.

Amid such supply chain and permitting challenges, long-duration storage could emerge as a core technology allowing U.S. innovation to capture global markets and build out a domestic supply chain less dependent on offshore mining and processing of critical minerals. For example, Eos Energy Enterprises offers zinc-based storage with up to 12 hours of duration. The company works from a retooled Westinghouse factory near Pittsburgh, with most components supplied by vendors located within a three-hour drive of the plant, according to CEO Joe Mastrangelo.

While lithium-ion batteries will remain critical for the automotive industry, long-duration storage technologies with local supply chains are coming into their own, and 2022 could see major advances for the sector. Further support will come from DOE’s Long Duration Storage Shot, which is targeting a 90% decrease in cost for technologies providing 10 or more hours of duration, again within one decade.

Federal Procurement

A final component of federal action worth following this year will be procurement. Biden’s last energy-focused executive order of the year sets up the federal government to lead by example on clean energy, targeting completely decarbonized electricity for government operations by 2030, with 50% of that power matching supply with demand on a 24/7 basis.

Similarly, the executive order calls for all new government light-duty vehicles to be zero-emission by 2027, with the federal fleet following suit in 2035. The federal portfolio includes 300,000 buildings and 600,000 vehicles, which, with or without tax incentives, means a huge bump in demand that will itself energize domestic markets and drive down costs.

Here as elsewhere, Biden has called for a whole-of-government approach, and the order also looks to the federal General Services Administration to start tracking the greenhouse gas emissions of government suppliers. A Buy Clean program will also tackle the “embodied carbon” in essential materials such as concrete and steel.

The ripple effect is potentially huge. Whatever happens in Congress, Biden’s commitment to climate action and clean energy will accelerate the U.S. transition in 2022 and beyond. The clean energy sector has also shown itself to be remarkably resilient to any economic or social obstacles it encounters, from the 2008-2009 recession to COVID to a divided Congress.

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Study Links Western Wildfires to Arctic Ice Melt

A new study has solidified the link between melting Arctic Ocean ice and the wildfires that regularly ravage the Western U.S.

The study was spearheaded by the Pacific Northwest National Laboratory (PNNL) and published in October in Nature Communications. The results were presented Dec. 16 at an American Geophysical Union meeting in New Orleans.

The link between melting Arctic sea ice and increasing Western wildfires has been a theory among climate scientists. Using sophisticated computer models at the Lawrence Berkeley National Laboratory, the new study nails down how the link occurs, Hailong Wang, an Earth scientist at PNNL and a co-author of the report, told NetZero Insider.

“There had been a lack of consensus in the community about potential mechanisms,” Wang said.

The PNNL team — with data scientist Yufei Zou as the lead author — has been studying how temperature changes in the Arctic affect other regions.

“It was hard to tease out the step-by-step observations,” Wang said. The study’s computer modeling pinned down the scenario.

Global warming melts the Arctic ice into the ocean. Consequently, sunlight directly hits the water, which absorbs the heat and later releases it back into the atmosphere, creating a counterclockwise vortex of warm air. The vortex pushes the polar jet stream out of its typical pathway, diverting moist air away from the Western U.S. That creates a second clockwise-spinning vortex beneath the polar jet stream as it crosses the West, dropping warm dry air on the region. That warm dry air makes conditions more conducive to wildfires.

“It’s not a perfect analogy, but teleconnections like this are a bit like the butterfly effect,” Wang said in a PNNL news release.

In the interview, Wang said understanding how this scenario works will help in predicting dry weather conditions in the West.

PNNL will tackle follow-up studies, creating computer models that will analyze how precipitation and other variables in nature factor into this domino effect and how to predict fire-prone conditions, Wang said.

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Here’s the Top Decarbonization Challenge for the Northeast in 2022

For climate action and energy policy in the Northeast, 2021 was a big year. Massachusetts and Rhode Island passed landmark climate bills, and climate councils in New York and Vermont adopted initial plans for decarbonizing their states. Those legislative and strategic imperatives, along with other efforts across the region, set up much more work for 2022, but one challenge stands out for Northeast states: They need a comprehensive, long-term way to pay for their plans to reduce emissions in the transportation sector.

No Plan B for TCI-P

The governors of Connecticut, Rhode Island and Massachusetts pulled their support for the Transportation and Climate Initiative Program (TCI-P) in the fall. And other states that were eyeing TCI-P participation are now backpedaling on the idea.

TCI-P’s vision is to allow participating states to decarbonize transportation, which is the biggest emitting sector across the Northeast, and raise money for decarbonization strategies through a cap-and-invest system. While the region’s states have ambitious plans for electric vehicle adoption, charging infrastructure and alternative transport solutions, they have no long-term alternative plans for raising the funds expected from TCI-P.

That funding gap is a real problem, but for now, states are looking to the American Rescue Plan Act (ARPA) and the Infrastructure Investment and Jobs Act, along with utility investments, to make near-term funding progress. And in 2022, they will continue to consider longer-term strategies that will reduce sector emissions and produce funds for reinvestment in climate solutions.

In 2022, watch for these clean transportation funding efforts for the region:

  • potential ARPA funding recommendation this month of $100 million to $150 million from the Vermont Climate Council for the state’s transportation sector;
  • transportation sector funding mechanism recommendations for the Vermont Climate Action Plan update in the spring;
  • transportation sector funding mechanism recommendations for the final New York Climate Action Council Scoping Plan due at the end of 2022;
  • a directive to legislators from the new Rhode Island Electric Vehicle Charging Station Plan — due for release this week — to identify funding support for EV incentives; and
  • a recommendation in Maine’s new Transportation Roadmap to develop EV infrastructure funding through new sources, such as a clean fuel standard, road user charge, gas tax or carbon mechanism.

Policy

In March, Gov. Charlie Baker signed the Next Generation Roadmap for Massachusetts Climate Policy, which set a mandate for the state to reach net-zero emissions by 2050.

Central to the state’s climate goals are two emission-reduction pathways that are now in jeopardy. In addition to losing the long-term emission reductions of the TCI-P, the state’s plan to supply 20% of its electricity from Canadian hydro resources via the New England Clean Energy Connect transmission line could fall apart.

Accessing Canada’s hydropower required siting part of the NECEC project in Maine, but residents there voted in November to halt the line’s construction activities. And Maine regulators have suspended an environmental permit for the project.

Climate advocates are hoping to see Massachusetts make up for the potential loss of hydropower with more offshore wind procurements. OSW supporters in the legislature want to pass new legislation “as soon as possible” to boost the state’s target for the resource, according to Kai Salem, policy coordinator at the Green Energy Consumers Alliance.

Before Massachusetts climate advocates hone their legislative priorities for 2022, they are waiting for the Baker administration to release the state’s Clean Energy and Climate Plan in July. They are also anxious to see the overdue Commission on Clean Heat kick into action. Stakeholders expect the commission to begin its work this month to meet a deadline for policy recommendations in November.

Rhode Island joined Massachusetts last year in the drive for net-zero emissions by 2050. Gov. Dan McKee signed the Act on Climate in April, making the target legally binding. By the end of the summer, climate advocates started criticizing the administration for being slow to address the act. McKee, however, directed the state’s Executive Climate Change Coordinating Council (EC4) at the end of September to step up the pace of its work to meet the act’s objectives.

With the upcoming release of the state’s EV charging station plan this month, the legislature will begin to consider follow-on policies in support of the plan. Up for immediate consideration will be a 100% Renewable Energy Standard; a mandatory public charging station minimum for the state; and code changes to make buildings ready for EV adoption.

Planning

Planning activities to address climate-related solutions have a wide footprint across the Northeast, and the work will have many deliverables in the New Year.

New York’s Climate Action Council spent last year developing its draft scoping plan, which it adopted right before Christmas. A key priority for the council this year will be to solidify its recommendation on how to value greenhouse gas emissions, which it refrained from doing in the draft plan. The council will now take public comments on the plan and release a final version in January 2023.

In addition, New York is gearing up to release its Great Lakes Wind Feasibility study this month. The New York State Energy Research and Development Authority will submit the study to the Public Service Commission. NYSERDA officials say the PSC likely will decide this year whether the state should develop OSW on the New York side of Lake Erie and Lake Ontario.

Vermont’s Climate Council also released a climate action plan in December after a year of work. While the council works to fill certain gaps in the initial plan, including how to pay for decarbonizing the transportation sector, advocates will begin to push legislation for some of the plan’s major initiatives.

Those initiatives include:

  • a Clean Heat Standard;
  • a 100% Renewable Energy Standard;
  • a scaled-up weatherization program;
  • a formal environmental justice policy for the state; and
  • a revamped transportation modernization bill.

In Rhode Island, the EC4 will spend most of this year updating the state’s 2016 Greenhouse Gas Emissions Reduction Plan, as required by the Act on Climate. The update will build a foundation for the EC4’s work to develop strategies by the end of 2025 for reaching net-zero emissions by 2050. The council will start the year with a series of public sessions to help shape what net-zero emissions means for the state.

In 2021, Maine officials oversaw the development of a handful of reports that stem from the state climate council’s December 2020 action plan. Five new reports will help drive climate and energy policy efforts in the state in the New Year. They include the:

  • Forest Carbon Taskforce report, which the group released in October with a recommendation to set an annual forest carbon sequestration target of 12 million metric tons of carbon dioxide equivalent through 2045;
  • Distributed Generation Stakeholder Group draft report, which is due this month and will inform a final report on potential programs and grid upgrades to expand DG in the state;
  • Agricultural Solar Stakeholder Group report, which the group released in December and includes a recommendation to create a dual-use pilot program;
  • Clean Transportation Roadmap, which lead state agencies released in late December and includes a recommendation to adopt California’s Advanced Clean Cars II and Advanced Clean Trucks programs; and
  • Maine Offshore Wind Roadmap, for which working groups made initial recommendations in December that will inform early industry action, such as port development, and a finalized roadmap by November.
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CAISO Takes on Transmission, EDAM in 2022

CAISO intends in 2022 to focus on long-term transmission planning, connecting storage to its grid and extending the real-time Western Energy Imbalance Market (WEIM) to a day-ahead market amid a push for greater Western regionalization.

“We’re going to turn the corner into ’22, and it is going to be a big year,” CEO Elliot Mainzer told the Board of Governors at its year-end meeting Dec. 17. “We are ready to go on the enhanced day-ahead market and all our other initiatives.”

CAISO must also keep competing with SPP, which is pushing West with its RTO and Western Energy Imbalance Service, and managing the Northwest Power Pool’s Western Resource Adequacy Program.

SPP’s recently unveiled Markets+ program could challenge CAISO’s proposed extended day-ahead market (EDAM).

“It’s a conceptual bundle of services proposed by SPP that would centralize day-ahead and real-time unit commitment and dispatch, provide hurdle-free transmission service across its footprint and pave the way for the reliable integration of a rapidly growing fleet of renewable generation,” the RTO says on its website.

“For utilities that see value in these services but who aren’t ready to pursue full membership in a regional transmission organization at this time, Markets+ provides a voluntary, incremental opportunity to realize significant benefits.”

SPP has scheduled a series of stakeholder meetings to discuss the new offering in Denver, Phoenix and Portland, Ore., during the first half of 2022.

WEIM and EDAM

CAISO is hoping the EDAM will give it an advantage and is wasting no time getting started this year.

Three newly established EDAM working groups will meet Monday and continue through Thursday to discuss resource sufficiency, transmission commitment, greenhouse gas accounting and other topics. CAISO’s goal is to complete EDAM market design by the end of 2022, implement and test it in 2023 and go live in early 2024.

“Amidst a dynamic and competitive environment for market services, we are fully committed to positioning EDAM as the next major step in West-wide market integration,” Mainzer said in his December report to the board.

CAISO revived the EDAM effort last year after putting it on hold following the energy emergencies of summer 2020. An online forum to relaunch EDAM in October drew 600 attendees. (See CAISO Promotes EDAM Effort in Forum.)

The level of interest was a sign of the growing demand for Western regionalization, Mainzer said at the time.

“I have never seen or felt a greater sense of interest and urgency on this topic,” he said.

Last year, FERC Chairman Richard Glick called for the establishment of one or more Western RTOs, and Nevada and Colorado passed laws ordering their transmission-owning utilities to join an RTO by 2030. (See Glick Says West Should ‘Finish the Job’ on RTO and FERC Commissioners Opine on Western RTO.)

A coalition of Western utilities formed the Western Markets Exploratory Group last summer to examine working together on transmission expansion, day-ahead energy sales and other market services, while leaving open the possibility of forming or joining a Western RTO. (See Western Utilities to Explore Market Options.)

EDAM seeks to build on the WEIM’s record of financial success and steady expansion. The WEIM has produced more than $1.7 billion in benefits for its participants since 2014. By 2023 it expects to have 22 members representing 84% of load in the Western Interconnection.

Establishing trust between California-run CAISO and the rest of the West remains a work in progress.

Toward that end, the CAISO board approved a power-sharing plan with the WEIM Governing Body in August. A joint meeting of the two bodies Dec. 16 was the first held under the new rules. (See CAISO Agrees to Share More Power with EIM.)

CAISO is also working on issues that have bothered some WEIM participants, including its resource sufficiency test and temporary wheel-through rules. (See CAISO Reevaluating WEIM Resource Sufficiency Test and FERC OKs CAISO Wheel-through Restrictions.)

“This past year raised difficult issues with respect to resource sufficiency and the prioritization of service to loads, exports and wheel-throughs,” Mainzer said in his report. “Both these issues are vitally important to our partners throughout the West and key to the trust that is the foundation of regional markets.”

The board and Governing Body are expected to vote on a revised resource sufficiency evaluation proposal in February. CAISO plans to address wheel-throughs in a separate stakeholder initiative.

Transmission Planning

Another major CAISO effort this year involves new, long-term transmission planning to meet the state’s goal of serving retail customers with 100% clean energy by 2045, as required by Senate Bill 100, signed by Gov. Jerry Brown in 2018.

The ISO intends to develop an extended 20-year transmission outlook working with the California Public Utilities Commission (CPUC), which prepares statewide integrated resource plans, and the California Energy Commission (CEC), which produces long-term energy demand forecasts.

The CPUC’s IRP envisions connecting 18 to 22 GW of new renewable generation and importing 1 to 3 GW of out-of-state wind power to meet the state’s interim 2031 energy goals.

“These procurement portfolios require significant in-state and out-of-state transmission investments,” the CPUC’s Public Advocate’s Office said in written comments responding to a July 27 stakeholder call.

CAISO plans to release the first findings of its new 20-year transmission outlook in early 2022, Mainzer told the board in December.

The 20-year effort is meant to run in parallel with CAISO’s normal 10-year transmission planning process. It will consider the CEC’s long-term demand forecasts, including the impacts of increased electrification in the transportation and building sectors. Connecting resources still in development — such as offshore wind, energy storage and utility-scale solar — also is part of the agenda. (See CAISO Launches 20-year Transmission Planning Process.)

One big difference is that CAISO’s 10-year process looks at in-state needs, but clean energy goals may require more interregional planning and collaboration, which the longer-term process will address, Jeff Billinton, director of transmission infrastructure planning, said at a kickoff meeting in May. He cited the TransWest Express Transmission Project, intended to bring Wyoming wind to California, as one example.

“This planning process is using SB 100 resource portfolios and other inputs to characterize the longer-term architecture of the ISO high-voltage transmission system. It will evaluate onshore, offshore and interregional transmission solutions,” Mainzer said in his report. “The 20-year outlook is designed to provide an overarching transmission planning roadmap to guide interconnection queuing, resource planning, network upgrades and resource procurement in the years ahead.

“At the same time, the ISO has been conducting a stakeholder process to explore foundational reforms to transmission queuing procedures given that we now have over 250 GW of requests for service in our transmission queue, which is an unsustainable situation for all concerned,” he said.

RA and Batteries

CAISO, the CPUC and CEC face another year of dealing with resource adequacy problems following the energy emergencies of summer 2020 and a close scrape on July 9 when major transmission pathways between the Pacific Northwest and California were derated because of a massive wildfire. (See CAISO Declares Emergency as Fire Derates Major Tx Lines.)

The addition to the grid of approximately 2,250 MW of batteries since summer 2020 should help meet summer evening peaks, the time when CAISO’s grid has been most strained. California’s dependence on solar power and imports made the state vulnerable to Western heat waves that drive air-conditioning demand after sunset.

CAISO previously estimated the state will need at least 12 GW of battery storage to meet its clean-energy goals.

In December, the CPUC adopted measures aimed at securing up to 3 GW of additional capacity through supply- and demand-side programs to prevent shortages in extreme heat waves in the summers of 2022 and 2023.

The measures included ordering the state’s three big investor-owned utilities — Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric — to accelerate procurement of battery storage. The commission projected shortfalls of 2 to 3 GW this summer but noted that PG&E, SCE and SDG&E have already procured 1 GW in response to earlier commission decisions.

Since late 2019, the CPUC has directed the state’s IOUs to collectively procure more than 17 GW of additional capacity, including a June order for 11.5 GW of new resources to come online between 2023 and 2026.

Acting on a July emergency proclamation by Gov. Gavin Newsom, the CEC approved a plan in September under which batteries capable of providing at least two hours of discharge by the end of October 2022 can be licensed and connected to the grid in far less time than it would normally take.

The proclamation ordered CAISO, the CPUC and CEC to “work with the state’s load-serving entities on accelerating plans for the construction, procurement and rapid deployment of new clean energy and storage projects to mitigate the risk of capacity shortages and increase the availability of carbon-free energy at all times of day.”

It cited severe drought as an exacerbating circumstance. Two extremely dry winters in the past two years in California dried up major reservoirs so that hydropower plants had to reduce or cease production. The power plant at Lake Oroville, one of the state’s largest reservoirs and hydroelectric generators, shut down in August because of falling lake levels.

Winter storms in December generated snowpack in the Sierra Nevada that was about 160% of average for the month, but more is needed during the rest of the winter to alleviate drought conditions. Sierra snowpack supplies water for residential and agricultural use throughout the state’s dry summer months.

WECC’s Western Assessment of Resource Adequacy warned of impending shortages through 2025, including as a result of drought. (See WECC Warns West Heading for Resource Shortfalls by 2025.)

Greater dependence on variable resources such as wind and solar could mean none of WECC’s five subregions will “be able to eliminate the hours at risk for loss of load even if they build all planned resource additions and import power,” the regional entity warned.

WECC examined RA under several scenarios including a “drought case” in which the Glen Canyon and Hoover dams on the Colorado River ceased hydroelectric production because of low water levels.

In August, the U.S. Bureau of Reclamation for the first time declared a water shortage for Lake Mead, behind Hoover Dam, in response to a historic drought impacting the entire Colorado River Basin. (See Feds Invoke First-ever Colorado River Water Restrictions.)

WECC said “entities may have many more options to address resource adequacy issues in the five- to 10-year time frame than in the near term” but urged quick action.

“If the current long-term issues are not addressed immediately, they may be insurmountable when they become near-term issues,” WECC said.

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FERC Reverses Itself on PJM Reserve Market Changes

PJM’s upcoming 2023/24 Base Residual Auction will be delayed again after FERC on Dec. 22 partially reversed its May 2020 decision on the RTO’s proposed energy price formation revisions, requiring tariff and Operating Agreement revisions within 60 days (EL19-58).

In a 3-1 vote, the commission reaffirmed its previous decision directing PJM to consolidate its tier 1 and tier 2 reserve products, but it said it erred in its approval of changes to the shape of the RTO’s operating reserve demand curve (ORDC). Commissioner James Danly was the lone vote against the decision, saying he would publish his full dissent in the future, while newly appointed Commissioner Willie Phillips did not participate in the order.

PJM filed its proposal unilaterally in March 2019 under Section 206 of the Federal Power Act because stakeholders could not come to a consensus on a single plan after more than a year of discussions and debate. (See PJM Files Energy Price Formation Plan.)

PJM-Reserve-Market-Alignment-(PJM)-Content.jpgPJM’s realignment of its reserve market under the proposal it filed with FERC in 2019 | PJM

The RTO uses an ORDC and transmission constraint penalty factors to establish LMPs. Under its current rules, the maximum price the energy component of an LMP can reach is $3,750/MWh.

But the “downward sloping” ORDC, approved by FERC in May 2020, allowed the RTO’s LMPs to reach or exceed $12,050/MWh in cases of extreme reserve shortages.

The commission approved the proposal in a 3-1 vote in 2020, with then-Commissioner Richard Glick issuing a strongly worded dissent that said he was “particularly troubled” that PJM’s revision to the ORDC was accepted and that annual increased costs to load could reach up to $2 billion. (See FERC Approves PJM Reserve Market Overhaul.)

Public interest and consumer organizations challenged FERC’s decision over the increased costs to ratepayers. In May, several petitioners, including state consumer advocacy agencies, asked the D.C. Circuit Court of Appeals to reverse the decision, and the court in August remanded it.

FERC said the 2020 order “relied on broad statements” concerning the amount of PJM’s “operational uncertainty,” the practice of “load forecast biasing” by its operators and the “prevalence of reserve market uplift” in determining that aspects of the RTO’s markets were unjust and unreasonable, including the “shape of its ORDCs beyond the minimum reserve requirements.”

“Upon reconsideration, we find that PJM failed to demonstrate that the operator bias it cited is caused by its currently effective ORDCs, and thus that the biasing data PJM provides does not demonstrate that its ORDCs are unjust and unreasonable,” FERC said.

FERC Directives

The commission ordered PJM to maintain its currently effective reserve penalty factors of $850/MWh for the synchronized reserve requirement and primary reserve requirement and $300/MWh for the extended requirements.

PJM argued that the $850/MWh factors were no longer just and reasonable because FERC Order 831 directed the RTO to increase its cost-based incremental energy market offer cap to $2,000/MWh, and thus “$2,000/MWh is the lowest reasonable level at which the penalty factor can be set and still be consistent with the actions that system operators are required to take to maintain reserves.” (See New FERC Rule Will Double RTO Offer Caps.)

The RTO proposed a replacement rate design that would establish reserve penalty factors of $2,000/MWh to align with the maximum price-setting energy offer cap of $2,000/MWh. But FERC said it disagreed with the RTO’s arguments as to the necessity for the change.

“The costs of a resource providing reserves are mainly based on that resource’s lost opportunity costs: the difference between the prevailing locational marginal price and its energy offer, i.e., its foregone net energy market revenues,” FERC said. “Thus, even when LMPs in the PJM region exceed $1,000/MWh, there is usually reserve capacity available at a cost much less than $1,000/MWh.”

The commission also reversed its decision on PJM’s forward-looking energy and ancillary services (E&AS) offset, a key variable in calculating the net cost of new entry (CONE) for resources in capacity auctions. The RTO must now revert to the previous, backward-looking offset.

FERC said PJM’s failure to demonstrate that its reserve penalty factors and ORDCs were unjust and unreasonable “undermined the fundamental basis” for the commission’s determination that the backward-looking offset is unjust and unreasonable.

“Without these fundamental changes to the reserve market, there is insufficient evidence in the record to find that E&AS revenues will increase to such an extent that the backward-looking offset does not reasonably reflect future E&AS revenues and is therefore unjust and unreasonable,” the commission said.

Auction Delay

The commission said it recognized PJM will need to delay the BRA for the 2023/24 delivery year currently scheduled for Jan. 25 to implement the revised E&AS offset. FERC previously approved PJM’s request in October to delay the BRA in response to the commission’s order in September revising the RTO’s market seller offer cap (MSOC). (See FERC Accepts PJM BRA Delays.)

PJM must submit a compliance filing with the commission within 30 days proposing a new schedule for the BRA and subsequent capacity auctions impacted by the delay.

The commission said it will not require PJM to rerun capacity auctions that utilized the forward-looking offset because doing so would “undermine the expectations of the parties who are making commitments for the 2022/23 delivery year.” Capacity prices fell sharply in the last BRA held in May, the first capacity auction held since a delay in 2018. (See Capacity Prices Drop Sharply in PJM Auction.)

PJM spokeswoman Susan Buehler said the RTO was still reviewing the FERC order and examining next steps.

Order Opinions

Mark-Christie-2021-07-27-(RTO-Insider-LLC)-FI.jpgFERC Commissioner Mark Christie | © RTO Insider LLC

FERC Commissioner Mark Christie said in a concurring opinion that certain changes in PJM’s reserve market construct proposal represented an “unacceptable risk that hundreds of millions of dollars of additional costs could be placed on consumers without a conclusive demonstration, in my view, of a commensurate increase in reliability.”

Christie said he agreed with the majority of commissioners that PJM “failed to meet its demanding burden” under FPA Section 206 to show that aspects of its currently effective reserve construct were unjust and unreasonable. He also agreed that because the replacement ORDC construct and reserve penalty factors “formed the bases” of challenging the E&AS offset from backward-looking to forward-looking, it too was unjust and unreasonable.

Christie said the order does not prevent PJM from seeking the approval of a forward-looking offset in the future if a proper case can be made, and he said it also doesn’t prevent the RTO from proposing other modifications to the reserve market construct.

Chandler-Kent-CleanPower-Webinar-FI.jpgKent Chandler, Kentucky PSC | AWEA

“Consumers deserve a reliable supply of power at the least cost (consistent with applicable laws),” Christie said in his concurrence. “The issues implicated by PJM’s proposal to make major changes to its reserve market construct involve both reliability and consumer costs. Achieving the right balance is always the challenge in utility regulation.”

In a Twitter thread published on Dec. 23, Kentucky Public Service Commission Chairman Kent Chandler gave praise to FERC for “rethinking a prior decision.” Chandler said the previously approved ORDC “would have raised electricity prices by hundreds of millions of dollars, with little increase in resource availability or reliability.”

“The real win for consumers from this order is the reduced risk of extended periods of high prices that don’t increase reserves during emergency events,” Chandler said. “Without a circuit breaker, the ORDC posed a risk of high prices that look to bring on new generation, even if no one can show up.”

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New York Set to Start Building Big in 2022

New York enters 2022 having greenlighted the state’s largest transmission projects in 50 years, with its first offshore wind project ready to put steel in the water and with officials having approved a plan for reaching emission limits set by the Climate Leadership and Community Protection Act (CLCPA).

The 2019 CLCPA and other statutes set high clean energy targets staggered every five years from 2025 to mid-century, with strict emissions limits that regulators cited in October when denying air quality permits to proposed gas-fired generators in the Hudson Valley and New York City. (See NY Regulators Deny Astoria, Danskammer Gas Projects’ Air Permits.)

Here’s a roundup of some of the biggest developments of 2021 and a look ahead to the new year.

Transmission to Deliver Renewable Power 

The New York State Energy Research and Development Authority (NYSERDA) in November signed a contract for the 174-mile Clean Path New York transmission line being developed by a joint venture of Invenergy, EnergyRe and the New York Power Authority to bring solar and wind energy from upstate to New York City (15-E-0302).

Champlain Hudson Power Express map (HQUS) Content.jpgMap shows the full length of the Champlain Hudson Power Express transmission line from Quebec to New York City. | HQUS

The agency also signed a contract with Hydro Quebec Energy Services for the 339-mile Champlain Hudson Power Express line being developed with Transmission Developers Inc. to bring Canadian hydropower and some upstate renewables to the city. (See Two Transmission Projects Selected to Bring Low-carbon Power to NYC.)

The contracts are subject to approval by the Public Service Commission, which will accept public comments through Feb. 7.

Some environmentalists oppose the developers’ plan to lay the Canadian line’s cable along 200 miles in Lake Champlain and the Hudson River. Environmental organization Riverkeeper said that process could churn up long-dormant contaminants such as polychlorinated biphenyl (PCBs), which were dumped into the Hudson by General Electric between 1947 and 1977.

The Clean Path line runs from Delaware County, in New York’s Southern Tier economic development region, through the Mid-Hudson region to New York City. A majority of the transmission line will be built on existing rights of ways already used by roads and transmission lines, developers said.

Construction could begin this year for the 1,250-MW Champlain Hudson, which is targeting a 2025 commercial operation date. The 3,800 MW Clean Path project is expected in service by 2027.

OSW Turbines for Downstate

The U.S. Bureau of Ocean Energy Management (BOEM) in November approved the construction and operations plan for the 132-MW South Fork Wind Project being built for the Long Island Power Authority, the second major offshore wind project in the country to move forward following the 800-MW Vineyard Wind I project. (See Interior Greenlights South Fork Wind Project COP.)

A joint venture between Ørsted and Eversource Energy (NYSE:ES), South Fork will be located approximately 19 miles southeast of Block Island, R.I., and 35 miles east of Montauk Point, N.Y. The developers say they hope to begin construction on the project’s underground transmission line this month. Commercial operation is expected by the end of 2023.

Meanwhile, BOEM plans to auction new wind energy areas in New York early this year. (See New York Writing Ending to Tale of Two Grids.)

Last year, New York said it had selected Equinor and its partner BP to build 2.5-GW of offshore wind: an additional 1,260 MW for their Empire Wind project in the New York Bight, and 1,230 MW for Beacon Wind, to be situated 60 miles east of Montauk. The state, which has targeted 9 GW of offshore wind for construction by 2035, previously selected the 816-MW initial phase for Empire Wind. Beacon Wind could add up to 1,170 MW in the future. (See NY Awards 2.5-GW Offshore Deal to Equinor.)

Equinor has begun constructing the port facilities needed to build and operate their projects, using the Port of Albany for tower manufacturing, the nearby Port of Coeymans for turbine foundation manufacturing, and turning the South Brooklyn Marine Terminal into an assembly and operations and maintenance hub. (See NY Builds OSW Ports in Brooklyn, Albany, Long Island.)

Without coordinated planning, NYISO says transmission congestion around New York City could increase after the first 6,000 MW of offshore wind is interconnected.

In a NYSERDA-commissioned study released in November, The Brattle Group concluded that high voltage alternating current (HVAC) would be better than high voltage direct current (HVDC) for a cost effective meshed offshore grid. Because most of the offshore wind lease areas are close to shore, distance constraints associated with HVAC will not be an issue, the study said.

“Most lease areas up for auction are within 20 miles from each other. At this distance HVAC is a much more suitable option,” the study said. “HVAC also allows for less expensive upfront costs and technology risks to developers, which will enable higher degrees of cooperation and acceptance of a meshed solution.”

Climate Scoping Plan

In March, the state’s Climate Action Council will begin holding at least six regional public hearings on the draft scoping plan it approved in December for meeting the state’s climate goals. (See NY Officials Approve Draft Climate Action Plan.)

The scoping plan incorporated recommendations from the Climate Justice Working Group, the Just Transition Working Group and seven advisory panels: Transportation; Agriculture and Forestry; Land Use and Local Government; Power Generation; Energy Efficiency and Housing; Energy Intensive and Trade Exposed Industries; and Waste.

NY Climate Projections (NYSERDA) Content.jpgClimate projections for New York state. | NYSERDA

 

The public will have at least 120 days to submit comments on the plan, and the Council will incorporate the feedback over the course of the new year before issuing a final plan by Jan. 1, 2023.

New York officials in December also announced the release of a roadmap outlining expanded programs to achieve 10 GW of distributed solar in the state by 2030 (Case No. 21-E-0629).

The state defines distributed solar as projects under 5 MW, including rooftop installations and community solar projects. The new framework builds on New York’s solar energy progress so far, with installed distributed solar and projects under development already totaling 95% of the state goal of 6 GW by 2025.

NYSERDA and the Department of Public Service (DPS) submitted the roadmap to the Public Service Commission for public comment, which is due March 7. (See New York Issues 10 GW Solar Roadmap for 2030.)

The expanded NY-Sun initiative aims to encourage the construction of at least 1,600 MW of new solar capacity to benefit disadvantaged communities and low-to-moderate income New Yorkers. It proposes that at least 450 MW be built in Con Edison’s service territory covering New York City and parts of Westchester, which would increase solar capacity in the ConEd region to more than 1 GW by the end of the decade.

NYSERDA also proposes that at least 560 MW of new solar generation be built on Long Island through the Long Island Power Authority.

NYISO Market Changes

NYISO last month updated stakeholders on several wholesale market changes it is making to accommodate the thousands of megawatts of state-solicited renewable resources coming online in New York over the next decade. (See NYISO Updates Grid in Transition Work and Plan for 2022.)

The measures range from carbon pricing — which has not been endorsed by the governor or the legislature — to buyer-side mitigation reforms and distributed energy resource participation models, including for storage, hybrid and co-located resources, all part of the ISO’s Grid in Transition initiative announced in 2019. The Grid in Transition initiative is focused on aligning New York’s competitive markets with the state’s clean energy objectives, valuing reserves for resource flexibility, and improving capacity market valuation.

In addition to working on buyer-side mitigation tests and capacity accreditation, the ISO expects to complete development and deployment of the remaining software for its distributed energy resources (DER) participation model in 2022.  

The ISO also posted the final version of its 2022 Master Plan for changes to the energy, ancillary services and capacity markets.

In addition to addressing climate change, state officials hope offshore wind and other clean energy policies will have an economic payoff: A study commissioned by New York officials predicts that clean energy employment in the state will increase by at least 211,000 jobs this decade and by nearly 350,000 by mid-century. (See NY Predicts 200K+ New Clean Energy Jobs by 2030.)

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ERCOT Reports Optimistic About Coming Winter

ERCOT broke a three-month silence on social media Wednesday when it tweeted the release of its semiannual report that provides a 10-year forecast of its planning reserve margins.

It was the Texas grid operator’s first tweet since Sept. 13, when it said it was preparing for Tropical Storm Nicholas. The storm eventually made landfall in Texas the following day as a Category 1 hurricane, bringing heavy rainfall and storm surge before quickly falling apart quickly and dissipating on Sept. 18.

On Thursday, ERCOT also issued its first press release since Sept. 13, a sunny report that most of the generation and transmission facilities it had inspected in December were “ready” for the winter.

The burst of activity doesn’t necessarily mark ERCOT’s return to social media or sending out press releases. The Capacity, Demand and Reserves (CDR) report was dropped without the accompanying media briefing staff used to hold for both the CDR and the seasonal assessments of resource adequacy.

With the exception of the Sept. 13 notices, ERCOT’s external communications have all but dried up ever since a pair of ordinary conservation alerts in April and June spooked Texans scarred from the devastating February winter storm. A Dec. 8 press conference with Public Utility Commission Chair Peter Lake and interim ERCOT CEO Brad Jones ended abruptly before trade media calling in could ask questions, but not before Lake promised “the lights will stay on” this winter. (See Texas PUC Chair Lake: ‘The Lights Will Stay On’.)

ERCOT officials have said they are focused on “making the necessary changes to protect Texans against the next winter storm” in explaining the lengthy radio silence. Jones has put a public face on the grid operator with his Listening Tour of Texas. (See Jones Working to Restore Confidence in ERCOT.)

According to The Texas Tribune, Gov. Greg Abbott, who is up for re-election next year and is fighting off Republican primary challengers and dismal favorability numbers (with only 18% of Texas voters approving of how state leaders have handled the winter storm and its aftermath), has taken control of ERCOT’s public messaging since the storm. The Tribune said the grid operator needs approval from the governor’s office for most of its public communications, a report confirmed by people familiar with the directives coming from Abbott’s office.

Indeed, Abbott wasted no time in retweeting a Bloomberg story that picked up the winterization readiness press release. “Texas power plants have made the upgrades needed to protect against cold weather. … They are good to go,” he said.

Doug Lewin (New West Communications) Content.jpgDoug Lewin, Stoic Energy | New West Communications

“As has been a pattern lately, the communications with the public about issues of widespread concern is sorely lacking,” tweeted Doug Lewin, president of Stoic Energy and close observer of ERCOT and the PUC.

Lewin poked holes in both announcements. He complimented the inspection program for getting power plants ready for the winter, but he has frequently noted the weatherization standards won’t apply to natural gas facilities until 2023. Industry reports have been unanimous in blaming the gas industry’s failure to supply gas plants before and during the storm as being primarily responsible for the storm’s outages.

“If you can’t get fuel to it, that gas plant isn’t very useful during a cold snap,” Lewin said.

He said the latest CDR, which shows ample capacity for the grid well into the future, bases its projections on normal weather and not the freezing conditions of 2011 or 2021. He pointed out the report’s highest winter peak demand for the next five years is about 10% lower than it was under the storm’s conditions.

“To say we have enough power in normal weather is not helpful,” he said in another Twitter thread. “We should at least plan for a winter as bad as the last one. And why do we assume that we could never have a winter worse than 2021? If these reports don’t take into account extremes, they’re mostly useless.”

John Raymond Hanger, who once sat on the Pennsylvania Public Utility Commission, said he was shocked by ERCOT’s assumptions that demand won’t again reach what it did last February.

“February 2021 is now the historic winter peak within ERCOT,” he tweeted. “But in reliability planning, instead of meeting historic peak demand, ERCOT assumes such demand won’t happen during next five years. Wow!”

Inspections Find Generation Fleet ‘Ready’

ERCOT said that its system’s generation fleet and transmission companies are ready for winter weather following its on-site inspections of mandatory winterization efforts at 302 generating units and 22 transmission facilities.

In a status report filed with the PUC (52786), the grid operator said some generators had exceeded the commission’s new winterization requirements following the storm. (See “Weatherization Rule Published,” PUC Workshop Takes First Stab at Market Changes.)

ERCOT said only 10 generators, accounting for 2.1 GW (1.7% of the total fleet), had items requiring corrective measures on the day of their inspection. It said many of those items had since been completed and noted that all 10 units are still operational.

“Texans can be confident the electric generation fleet and the grid are winterized and ready to provide power,” Woody Rickerson, ERCOT vice president of grid planning and weatherization, said in a statement.

The inspections of transmission facilities found only six minor “deficiencies,” most of which have since been corrected. They focused on resources that accounted for 85% of the megawatt-hours lost during the storm. Staff plan to file a final report with the PUC on Jan. 18 for review and any potential enforcement action. Violators of the new weatherization rules face penalties of up to $1 million per day per violation. (See ERCOT Generators Near 100% Winter Readiness Compliance.)

ERCOT will conduct follow-up inspections on those generation and transmission facilities with potential identified issues. Staff and contractors have already spent more than 3,600 hours on inspection-related activities.

Final 2 Board Members Appointed

Peggy Heeg (UT School of Law) Content.jpgPeggy Heeg | University of Texas School of Law

The PUC said Wednesday it has filled the last two vacancies on ERCOT’s Board of Directors, completing a total makeover in the wake of the February storm.

The commission said a three-man board selected by the state’s political leadership had appointed Julie England and Peggy Heeg as ERCOT’s final two independent directors. They are also the only women on the board. A previous appointee, Elaine Mendoza, resigned in November over an apparent conflict of interest. (See Twitter Blows up over ERCOT Communications.)

England, a former senior executive with Texas Instruments, currently serves on the boards of TTM Technologies, a global technology solutions and printed circuit board fabrication company, and engineering and construction firm McMillen Jacobs Associates. She previously served as a director of the Federal Reserve Bank of Dallas from 1997 to 2003.

Julie England (Crunchbase) Content.jpgJulie England | Crunchbase

Heeg advised companies on energy, regulatory and corporate governance matters as an attorney before retiring. She also served on the Texas Lottery Commission and has been a director on numerous boards in the energy sector.

“This completely independent board marks a new era of reliability and accountability in ERCOT governance and leadership,” PUC Chair Lake said in a statement.

Legislation passed during the summer replaced the previous board’s five unaffiliated directors and eight market segment representatives with eight independent directors chosen by the selection committee. The ERCOT CEO, the PUC chair and the Texas Office of Public Utility Counsel’s CEO sit on the body as non-voting members.

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MISO in 2022: Seasonal Capacity, Fleet Turnover and Tx Planning

As it heads into 2022, MISO‘s to-do list is dominated by getting major transmission built and crafting a seasonal capacity auction, direct responses to an increasingly renewable fleet and intensifying weather events.

“Don’t rest — or maybe you should rest — because we have a lot to do in the new year,” MISO CEO John Bear told stakeholders at the December board meeting, referencing the RTO’s work on its long-range transmission plan, seasonal capacity market, ongoing market platform replacement and dynamic transmission line ratings.

“I think we put MISO in a much, much better place than we were 12 months ago,” Bear said.

Seasonal Capacity on the Way

Though climate change is rarely mentioned in meetings by politically adverse MISO staff, the footprint was roiled by extreme weather in 2021, leading the RTO to conclude that a suite of resource adequacy solutions is needed for a fleet that’s either aging or has its output dictated by weather.

MISO Senior Director of Operations Planning J.T. Smith said it’s no longer surprising for the RTO to issue seasonal warnings and that it will find itself relying on non-firm imports from neighbors if outages are high when devastating cold snaps or heat domes strike.

“It’s not a new situation; it’s something we’ve reported out over the last couple of years,” Smith said in mid-December.

In February, an unprecedented winter storm forced load shed in MISO South. The RTO said the widespread artic blast gave it further justification to revise its capacity market. (See MISO: Wintry Weather Vindicates RA Changes.)

But the cold snap seemed tame in comparison to the havoc Hurricane Ida doled out to MISO South in late August. After the storm struck, MISO South stayed in conservative operations from Aug. 29 to Sept. 10 to allow for restoration. The hurricane cut through a significant transmission corridor, slashing ties from MISO into most of the Amite South and all of the Downstream of Gypsy — or metropolitan New Orleans — load pockets. MISO reported 233 transmission lines lost and 6.4 GW of generation knocked offline during the storm. (See Entergy Touts Restoration; NOLA Leaders Question Lack of Blackstart Service.)

Hurricane-Ida-damage-in-New-Orleans-(Entergy)-FI.jpgHurricane Ida damage in New Orleans on Aug. 30 | Entergy

 

“We’re still suffering down there. A lot of recovery has to happen,” Louisiana Public Service Commissioner Lambert Boissiere said at an Entergy Regional State Committee meeting Nov. 9.

In all, MISO declared conservative operations instructions for 29 days in 2021, 13 of them from Ida. The remaining days were devoted to managing intense heat or cold.

MISO recently requested FERC approval of a four-season capacity auction and corresponding reserve margin targets. That design will accompany a new capacity accreditation based upon generators’ recent availability, especially during tight conditions. The RTO has also filed separately to create a minimum capacity obligation, in which a load-serving entity must demonstrate that at least 50% of the capacity required to meet their peak load is secured ahead of the voluntary capacity auction. (See FERC Grants Comment Extension for MISO Capacity Filing.) The pair of filings pending at FERC is all but certain to attract protests from generation owners that stand to have lower capacity credits.

The RTO said it will dedicate 2022 to furthering decisions on how its markets must change to accommodate more actively managed load and a more intermittent and varied resource fleet.

Reconstruction of Tx tower after Hurricane Ida (Entergy) Alt FI.jpgReconstruction of an Entergy tower after Hurricane Ida | Entergy

 

In early December, MISO’s Jordan Bakke said the current market construct will gradually become less adept at serving load. He said local power imbalances will multiply, and MISO must be able to transport power for longer distances as more wind and solar generation is built in pockets around the footprint.

MISO has said that it expects wind and solar generation to reach 30% of its total load as early as 2026, straining the system and threatening reliability. It set a new, all-time wind output record of 22 GW on Nov. 12, with wind serving 29% of total load.

Winter Apprehension

MISO is steeling itself for a reserve shortage over the winter.

RTO staff over 2021 repeated that they must make more long-lead commitments and issue maximum generation warnings more frequently as surpluses disappear under even normal weather conditions throughout the year and the bulk electric system gets more complex to manage.

Days under a maximum generation alert (MISO) Content.jpgDays under a maximum generation alert, warning or event in the last eight years | MISO

 

The grid operator has said it will likely move up instructions for members to make public appeals for energy conservation earlier in its emergency process. It’s also collecting weekly winter fuel surveys through the end of February from about 400 generators to gauge natural gas and coal fuel security. (See MISO Sounds Alarm on Potential Winter Fuel Scarcity.)

Some generation owners have criticized the weekly survey fill-in as onerous. MISO staff say they need the information to assess reliability risks this winter.

“Given the potential upside of protecting the reliability of MISO and the downside of the administrative burden, I think the upside really outweighs [the downside]. … I really appreciate MISO as a proactive manager of this situation,” Minnesota Public Utilities Commission staff member Hwikwon Ham said at the Reliability Subcommittee’s meeting Dec. 10.

MISO has estimated through an internal survey that about 11 GW of coal generation is at risk of outage this winter because of fuel supply issues.

Addressing the winter worry, Michelle Bloodworth, CEO of coal trade group America’s Power, said MISO should “reconsider how far [the coal] fleet should be allowed to shrink.” She said some coal generation can temper the “inherent risks of an overreliance on natural gas and intermittent generation for electric generation.”

“Each coal plant that retires increases MISO’s exposure to fuel assurance risk,” Bloodworth said during MISO’s Board Week in mid-December.

But the coal exodus continues unabated.

Ameren Missouri (NYSE:AEE) announced Dec. 14 that it would accelerate the retirement of its coal-fired, 1.2-GW Rush Island Energy Center to 2024. The new retirement date coincides with a deadline to install new emissions controls imposed by the U.S. District Court for Eastern Missouri. Ameren’s 2020 integrated resource plan envisioned the plant running through the end of 2039.

“Potential grid stability and reliability impacts and other downstream effects must be evaluated, and those issues that are identified must be addressed,” Ameren noted in a Dec. 14 filing. Rush Island supports voltages in the St. Louis area.

NERC estimated that MISO faces a loss of more than 13 GW in capacity by 2024, comprising 10.5 GW of coal-fired generation and 2.4 GW of gas generation. If MISO doesn’t get replacements online soon, the footprint could suffer from a combined 560-MW shortfall, NERC concluded.

New generation is clamoring in MISO’s interconnection queue. In September, generation developers’ requests to join the system pushed the queue to a 153-GW high, shattering all previous records. (See MISO Warns Queue Won’t Stay at 150-GW High.)

Historically, MISO interconnects about a fifth of the generation projects that enter the queue. MISO executives have warned that much of the new generation won’t be able to connect to the system without substantial transmission expansion.

Long-range Planning in 2022 and Beyond

Despite that, some MISO players in 2021 staged a standoff over the necessity of a long-range transmission portfolio and how to divvy its costs. (See Tensions Boil over MISO South Attitudes on Long-range Transmission Planning.)

RTO leadership has said it could advance several billions in transmission expansion for Board of Directors approval over the next few years. So far, the RTO is only prepared to propose select projects located in MISO Midwest in late spring.

MISO plans to finish an initial cost allocation design in early 2022. The allocation prescribes a separate but equal postage stamp allocation to MISO Midwest and South. The design is based on MISO’s hypothesis that benefits from long-range projects built in either Midwest or South won’t cross its subregional transmission constraint. (See MISO to Test Long-range Tx Allocation Benefits.)

Some MISO members — especially environmental proponents — have suggested that Entergy (NYSE:ETR) is opposing major transmission expansion, hoping to stave off democratization of access to its system.

MISO also faces outside pressure to get transmission towers erected.

Former FERC Commissioner John Norris — who voted in 2013 to approve Entergy’s integration into MISO to mollify a Department of Justice investigation into the company’s anticompetitive behavior — has expressed regret at his vote and admonished Entergy and its regulators’ efforts to stall the RTO’s long-range transmission planning. He asked the MISO board to intervene in what he said was the RTO’s tendency to “yield to parochial interests.”

“I did not, nor did I suspect any of my colleagues at FERC, would have thought that by late 2021, no advancement in regional transmission planning and building would have taken place. At a minimum it would’ve seemed reasonable to assume that the north-to-south interconnection issue would’ve been addressed and resolved. Without the ability to transfer substantial amounts of electricity from north to south begs the question: What’s the point?” Norris told the board in September.

Norris said MISO’s lack of regional planning means it’s “already behind in its abilities to meet the needs for 2030 and beyond.”

“Given the increase in [maximum generation] events, one could argue that MISO is not even meeting the needs of today,” he added.

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SPP Again Delays In-person Stakeholder Meetings

SPP said last week it was once again delaying in-person meetings and staff’s return to the office because of rising COVID-19 infections and flu cases.

In a Dec. 28 message to stakeholders, CEO Barbara Sugg said SPP is cancelling the in-person option for the Jan. 10-11 Markets and Operations Policy Committee and Jan. 12 Strategic Planning Committee meetings in Oklahoma City. Those meetings will revert to the virtual format of the last two years.

The Jan. 24 Regional State Committee and Jan. 25 Board of Directors/Members Committee meetings are still planned to be held at SPP’s headquarters in Little Rock, Ark., although attendance will be limited for social distancing.

“I know this means that I will not get to see many of you in-person as soon as I hoped, but I’m confident our team will continue to facilitate virtual meetings with their usual standard of excellence,” Sugg wrote. “Be well and stay safe.”

Sugg cited a “dramatic trend” in COVID-19 infections and flu cases. She said daily new COVID cases have nearly doubled in Oklahoma since Dec. 18 and recent hospitalizations in Arkansas increased 7% in a day.

“Although early data seems to show the Omicron variant is unlikely to severely affect healthy, boosted people, we still do not know what its impact will be on older, at-risk colleagues, friends and family,” Sugg said.

The grid operator is also delaying the fourth phase of staff’s return to the Little Rock offices until at least Jan. 18 while it continues to monitor community COVID cases. It warned its plans may undergo additional modifications “to appropriately respond to changing conditions.”