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October 5, 2024

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CAISO Reevaluating WEIM Resource Sufficiency Test

The Western Energy Imbalance Market Governing Body met twice last week, once by itself and once in a joint session with the CAISO Board of Governors, receiving briefings in both meetings on potential changes to the interstate market’s resource sufficiency test, which is being re-examined in a stakeholder initiative.

The test is meant to ensure that each WEIM participant enters a trading hour with enough capacity and ramping capability to supply its own needs and to prevent participants from “leaning” on the market to meet internal demand.

Participants raised objections to the test, including the recent addition of components that account for the unpredictability of weather-dependent resources such as solar and wind generation, transmission outages and other variables. Some contended the “uncertainty” components skewed results and led to periodic test failures, including by CAISO during intervals last summer.

A revised final draft proposal in the resource sufficiency evaluation (RSE) enhancements stakeholder initiative was released Thursday, when the board and governing body met in joint session. CAISO Vice President of Market Policy and Performance Anna McKenna provided a briefing on the proposed changes, as she had done in the governing body’s regular meeting Wednesday.

Stakeholders had four areas of concern over test accuracy, McKenna said.

“The first category is with regards to the measurement of uncertainty used in the capacity test,” she said. “After hearing more concerns about the current measurements that we use to capture uncertainty and the adders that we’ve put into the test, we are now considering suspending … uncertainty in the tests.”

Participants also raised concerns around demand response resources, capacity counting rules and consideration of load conformance.

CAISO planners had proposed increasing penalties for including demand response resources in the sufficiency test that do not materialize, but they now recommend shelving that plan because the penalties could have a “detrimental impact on how (participants) use demand response,” McKenna said.

A third category of stakeholder concerns involved CAISO’s proposed rules for counting resources toward the sufficiency test. CAISO still intends to enhance the counting criteria “so that the resources that are used to count to meet the test … can better reflect their actual reliability,” McKenna said.

The fourth category of concerns involves “how conformance of load forecast, which is done by our operators, can trigger EIM transfers to meet the [resource sufficiency] test,” McKenna said. CAISO continues to believe that understanding and adjusting for the impact of load forecast is important, but additional analyses showed complexities that deserve further testing and evaluation, she said.

“So, we’re proposing to take that additional time with regard to this one item,” McKenna said.

CAISO already had extended its timeline for the RSE initiative to take stakeholder comments into consideration and now plans to submit a final proposal to the board and governing body in a joint meeting Feb. 9.

Thursday’s joint meeting was the first to be held under new governance rules adopted by the CAISO and WEIM in August. The vote on the sufficiency test will among the first joint decisions under the new rules.  (See CAISO Agrees to Share More Power with EIM.)

A meeting on the latest draft RSE draft proposal is scheduled for Dec. 21, with stakeholder comments due Jan. 10.

The WEIM now has 15 participants with seven more scheduled to join in the next two years, eventually accounting for more than 80% of load in the Western interconnection. Participants have amassed more than $1.7 billion in benefits since the market started in 2014 by buying and selling excess power across state lines.

CAISO is undertaking a major effort this to year to expand the real-time market to a day-ahead market (EDAM), further increasing cooperation among the West’s 37 balancing authorities.

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Jones Working to Restore Confidence in ERCOT

Brad Jones 2021-12-17 (RTO Insider LLC) FI.jpgInterim ERCOT CEO Brad Jones | © RTO Insider LLC

DALLAS — Brad Jones, ERCOT’s interim CEO, opened his conversation Friday with the Dallas Friday Club as he always does on what he calls his Listening Tour: stepping away from the podium and eschewing the use of a mic. The better to wander the stage and connect with his audience.

“This will take about two and a half hours,” Jones said, drawing a few laughs.

His story began on Feb. 15 during a winter storm, “one you’ve never seen and one your grandparents never saw.” Jones, retired from the electric industry at the time, says he was on his couch and watching television coverage of the winter storm disaster that left millions without power and caused human and financial suffering.

“Things have changed for me, haven’t they?” Jones said in a quick aside.

“Were you in Texas?” asked a voice from the back of the room.

“Yes.”

“Did you have power?”

“Electricity, but no water.”

It’s that mixture of charm, humor and candor that serves Jones well as he explains to Texans what happened to the grid during the storm and why it won’t happen again. Several members of the public affairs organization exchanged smirks as Jones began his comments. An hour later, most everyone in the room was listening in rapt attention.

Jones admitted to ERCOT’s poor communication during the storm, when “each piece of the market was telling different stories.” He said the subfreezing temperatures shut down almost 50 GW of the grid operator’s capacity — more than the 48-GW demand peaks CAISO sees on its hottest days, he said — and left the grid within about 10 minutes or so of a black start situation when generators automatically shut down.

“Things would have been much more difficult to manage,” Jones said.

He explained the lack of interconnections with neighboring RTOs wouldn’t have helped much, as they were experiencing the same emergency conditions. That led into an explanation of why ERCOT, “an island to itself,” is exempt from FERC jurisdiction.

When Jones began taking questions from the audience, he was asked how Texas can again say it has the best grid in the nation. He said his flippant answer is that New York has had three blackouts and California two while the Lone Star State has not had one.

“The real answer is simple,” he said. “We have to show the country we’ve changed the way we operate.”

Jones mentioned the RACE acronym he uses to denote “reliable, affordable, clean electricity.” Until the February storm, he said, RACE had been turned into CARE.

“For 20 years, we let the market dictate what we need for reliability,” Jones said. “We need to move reliability back to the front. That will be how we change.”

Jones handled every following question with similar ease. When the luncheon concluded, he took time to visit with the diners that stayed behind before doing on-camera interviews with the local media.

Asked if he is the perfect spokesman for this role as the communicator in chief, Jones laughed loudly.

“It’s an extremely important role,” he said. “The reason I came back to ERCOT after the winter storm was so ERCOT can begin to restore confidence among Texans in what it does.”

Jones served as ERCOT’s COO before leaving to take the top job at NYISO. He has watched the industry from afar since abruptly leaving New York for personal reasons in 2018. (See Brad Jones out at NYISO.)

The Brad Jones Listening Tour continues. Dallas was the 13th stop, with four more on the schedule. That is expected to change, however. Jones has yet to come across a city council or town hall that he won’t attend.

Contrast that with Texas Gov. Greg Abbott, who has guaranteed the grid will not fail this winter. While Jones has been crisscrossing the state, Abbott held a closed-door meeting Thursday with “Texas energy providers” to discuss the grid’s reliability and “preparedness ahead of the winter season.”

The governor’s office said in a statement that Abbott and “energy leaders” discussed actions already taken and improvements made by both the providers and the state, including updated winter preparedness plans, meetings with plant managers and “winterization of all components of the power grid.”

The office also said several providers “discussed their efforts to ensure that natural gas supply is available this winter to fuel power plants, including on-site storage of natural gas and designation of natural gas facilities as critical to ensure they maintain power during energy emergencies.”

NRG Energy (NYSE:NRG), Vistra (NYSE:VST), Calpine and several pipeline companies were among those involved in the meeting.

434 MW Back for Late Winter

ERCOT will have an additional 434 MW of gas-fired capacity to play with before this winter is over, thanks to a pair of decisions related to retired power plants.

Vistra told the grid operator on Friday it is bringing its 69-MW Wharton County Generation facility out of retirement and making it operational as of Feb. 4. The plant, located southwest of Houston, was decommissioned and retired last December after a forced outage. (See “Luminant, 1 Other File NSOs with ERCOT,” Vistra to Shut down Another Texas Coal Plant.)

ERCOT and CenterPoint Energy, the interconnecting transmission service provider, may delay the proposed return date if any studies, testing, metering or facility upgrades are necessary.

NRG notified ERCOT on Dec. 14 that Gregory Power Partners — a three-unit, 365-MW facility near Corpus Christi currently under seasonal mothball status — will change the start date of the operating period from May 1 to Jan. 1.

The plant was shut down in late 2016 when its cogeneration partner, Sherwin Alumina, filed for bankruptcy and ceased operations. NRG returned it to seasonal operations in 2019. (See ERCOT Approves Seasonal Plan for NRG Cogen Units.)

The announcements will help make up for the loss of almost 500 MW of capacity following recent suspension-of-operations notifications filed by the cities of Austin and Garland for aging gas-fired generators. ERCOT approved the notices earlier this month. (See “500 MW to Depart Market,” ERCOT Briefs: Week of Nov. 1, 2021.)

The 405-MW Austin unit will be available through the winter before being retired.

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CAISO Board Elects New Leaders

In its last meeting of 2021 on Friday, the CAISO Board of Governors elected a new chair and vice chair and voted to fund new technology to settle billions of dollars in yearly market transactions.

The five board members continued their policy of rotating leaders annually, electing Vice Chair Ashutosh Bhagwat as chair and naming Governor Mary Leslie to take his place as vice chair.

Bhagwat, a law professor at the University of California, Davis, who has served on the board since 2011, took over the top spot from Angelina Galiteva, whom colleagues praised for her leadership in difficult times. The first woman to chair the CAISO board, her term included the pandemic, the state’s struggle to prevent summer blackouts and a changeover in CEOs.

“You are the perfect chair to have led this effort because I think you brought a really nice warmth and understanding and vision to being chair, and I think it’s served us really well,” Leslie told her.

Galiteva responded, “Well, thank you. It was a pleasure to be the first woman chair. It was about time we had a woman chair at the ISO, and now we’ll have many more. It’s wonderful to see that now women are the majority on the board, which is also a first, so it has been it has been a very good period.”

Bhagwat lauded Galiteva for her work as an ambassador between the CAISO board and the Western energy community and asked her to continue with those efforts.

Accepting his new role, Bhagwat said, “I appreciate the confidence you’re showing in me, and I hope to live up to it.”

Settlement Upgrades

CAISO management requested a $15.6 million upgrade to CAISO’s settlement system, which handles billions of dollars in transactions annually and will likely handle more in the coming years as CAISO expands its Western Energy Imbalance Market.

“Every week, the ISO settles between $60 [million] and $219 million dollars of market transactions, and in 2020 that totaled $11.4 billion dollars,” Vice President for System Operations Dede Subakti and CFO Ryan Seghesio said in a memo to the board. “In order to achieve this, the ISO settlement team must process between 18 and 51 trade dates each week, as mandated by our tariff. This results in roughly 31,000 system files being published to 585 market participants weekly.”

The current system is aging, they said.

“It [now] takes between three and seven hours of work to process each trade date, leaving very little room for error,” they wrote. “As a result, the ISO is sometimes challenged to meet the tariff-defined statement publishing deadlines.”

“As we look toward a future with more market participants, new customer types, new market products and an expanded ISO footprint, it is time to address the shortcomings in the current settlement system,” they said. “Failing to do so would be too risky to the ISO and our stakeholders.”

The board unanimously approved the request.

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Manchin Says ‘No’ on Build Back Better

Work on the Democrats’ $2 trillion Build Back Better Act came to a screeching halt Sunday morning as Sen. Joe Manchin (D-W.Va.) stated unequivocally that he could not vote for the bill in its current form.

“I have always said if I can’t go home and explain it to the people of West Virginia, I can’t vote for it,” Manchin said on “Fox News Sunday.” “And I cannot vote to continue with this piece of legislation. I just can’t. … This is a no.”

President Joe Biden “has worked diligently; he’s been wonderful to work with,” Manchin said of his negotiations with the White House. But he said the government should focus on inflation and the new surge in COVID-19 cases, driven by the fast-spreading Omicron variant.

White House Press Secretary Jen Psaki said the administration was blindsided, labeling Manchin’s statements “a sudden and inexplicable reversal in his position and a breach of his commitments to the president and the senator’s colleagues in the House and Senate.”

Manchin had repeatedly told Biden he was committed to working on the bill, Psaki said. “On Tuesday of this week, Sen. Manchin came to the White House and submitted — to the president, in person, directly — a written outline for a Build Back Better bill that was the same size and scope as the president’s framework and covered many of the same priorities. While that framework was missing key priorities, we believed it could lead to a compromise acceptable to all. Sen. Manchin promised to continue conversations in the days ahead and to work with us to reach that common ground.”

In his own statement, released following his appearance on Fox, Manchin said that the bill represented efforts by Democrats to “dramatically reshape our society in a way that leaves our country even more vulnerable to the threats we face.”

He also reiterated his longstanding argument that U.S. energy policy should be driven by innovation and markets, rather than regulation.

“If enacted, the bill will also risk the reliability of our electric grid and increase our dependence of foreign supply chains. The energy transition my colleagues seek is already well under way in the United States of America,” he said. “We have invested billions of dollars into clean energy technologies so we can continue to lead the world in reducing emissions through innovation. But to do so at a rate that is faster than technology or the markets allow will have catastrophic consequences for the American people like we have seen in both Texas and California in the last two years.”

‘This is not Over’

Clean energy advocates have lobbied hard for the bill, which contains $555 billion in funding for renewable energy tax credits and other programs aimed at achieving Biden’s goals of decarbonizing the U.S. electric grid by 2035 and cutting the nation’s carbon emissions to net zero by 2050. Supporters pledged to continue their efforts despite Manchin’s announcement.

Speaking on CNN’s “State of the Nation,” Sen. Bernie Sanders (I-Vt.) said Manchin is “going to have to tell the people in West Virginia why he’s rejecting what the scientists of the world are telling us, that we have to act boldly and transform our energy system to protect future generations from the devastation of climate change.”

Sanders also called for Democrats to “bring a strong bill to the Senate as soon as we can and let Mr. Manchin explain to the people of West Virginia why he doesn’t have the guts to stand up to powerful special interests.”

“This is not over,” said Gregory Wetstone, CEO of the American Council on Renewable Energy. “The clean energy tax platform and grid infrastructure provisions in the Build Back Better Act are our last, best chance to tackle climate change. We will be working with Congress to find a way forward and deliver the clean energy future Americans want and deserve. Failure is not an option.”

Erin Duncan, vice president of congressional affairs for the Solar Energy Industries Association, also signaled the organization’s determination to keep fighting for the bill.

“There have been many twists and turns in this legislation, but the need for jobs, particularly domestic manufacturing jobs, that help address the climate crisis is unrelenting,” she said. “This is not the end of the road. We will continue to advocate aggressively for policies that deliver jobs and clean energy to every state across America.”

The debate also exploded on Twitter, where Robert Reich, who served as secretary of Labor for former President Bill Clinton, said Congress’s adjournment at 4 a.m. Saturday ended any hope for passing Build Back Better this year. “Biden’s agenda is now at the mercy of the midterm election year,” Reich said.

Calling Manchin “the new Mitch McConnell,” Rep. Jamaal Bowman (D-N.Y.) questioned whether Manchin’s opposition to the bill was influenced by special interests. “When you say you’re a no on Build Back Better — is it you? Or is it the special interest that powers you?” Bowman tweeted. “I’m inviting you to my district to see just how badly we need this bill. Will you tell my community ‘No’ to our face?”

On the other side of the aisle, Rep. Dan Crenshaw (R-Texas) was jubilant, tweeting that Manchin’s no means that “America has dodged a serious bullet. BBB is dead. Merry Christmas!”

ClearView Partners, a D.C.-based research firm, anticipates the new year could bring a revised Build Back Better Act (BBBA) with trimmed down energy spending.

“Democrats could face a Hobson’s Choice on a next bill (i.e., a significantly smaller bill or nothing at all),” ClearView said in a note to clients. “A future draft therefore would seem unlikely to retain the breadth and depth of clean energy spending in the House-passed BBBA. … We would not yet bet against long-term green power tax credit extensions in some form, albeit for shorter durations and/or with less generous provisions.”

Keeping Coal in the Picture

As chair of the Senate Energy and Natural Resource Committee and one of two critical swing votes in the evenly divided Senate, Manchin, along with Sen. Kyrsten Sinema (D-Ariz.), has had an outsized ability to shape key legislation, especially anything related to energy policy.

His opposition had already cut key provisions from the bill, most prominently Biden’s Clean Electricity Performance Program, which would have provided incentives for utilities to accelerate their switch to carbon-free power.

Manchin describes himself as a “conservative Democrat,” but his opposition to aggressive clean energy programs reflects his strong ties to the coal industry in his home state of West Virginia. He earns hundreds of thousands of dollars annually from Enersystems, the coal company he started, which is now run by his son, Joseph Manchin IV.

Manchin has long maintained the family business does not constitute a conflict of interest because he put his investments in a blind trust.

But The Washington Post reported last week that his most recent financial disclosure showed the company paid him $492,000 in interest, dividends and other income in 2020 and was worth between $1 million and $5 million. The blind trust Manchin created with $350,000 in cash in 2012 generated no more than $15,000 last year, the Post reported.

Manchin regularly speaks in favor of bipartisan legislation, especially when it contains dollars for his home state of West Virginia and the coal industry. For example, the $1.2 trillion bipartisan infrastructure bill, which he helped shepherd through the Senate, includes billions for the development and deployment of carbon capture, storage and sequestration projects.

Similarly, on Thursday, Manchin and Sen. John Barrasso (R-Wyo.), ranking member on the Energy and Natural Resources Committee, introduced a bill that would establish a program to provide federal dollars for building advanced nuclear reactors and related supply chain facilities on or near retired coal plants.

“Advanced nuclear technologies provide an opportunity to repurpose shuttered coal and fossil generating plants,” Manchin said in the press announcement of the bill. Such projects “could bring new high-paying jobs and economic opportunities to communities throughout West Virginia and the nation while expanding our domestic nuclear supply chain.”

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Arizona Regulators Approve Transportation Electrification Plan

The Arizona Corporation Commission has approved a statewide transportation electrification plan developed by utilities and intended to accelerate electric vehicle adoption.

The commission voted 3-1 Wednesday to approve the plan. Commissioner Justin Olson voted “no” and Commissioner Jim O’Connor abstained.

The commission also voted 4-1 in favor of directing investor-owned utilities Tucson Electric Power Co. (TEP), Arizona Public Service Co. (APS) and UNS Electric Inc. to file transportation electrification implementation plans at least every three years, starting next year. Olson was opposed.

In addition, TEP and APS must file semi-annual reports detailing their progress in implementing the transportation electrification plan.

The commission was split on a proposal from Commissioner Sandra Kennedy that would have directed the three utilities to base their EV programs and investments on a “high adoption scenario” analyzed in the transportation electrification (TE) plan.

The high-adoption scenario envisions 1.5 million light-duty electric vehicles on the road in Arizona in 2030, or about 20% of all light-duty vehicles.

That compares to a medium-adoption scenario, with 1 million light-duty EVs in the state by that year, and a low-adoption scenario, with about 250,000 EVs.

Kennedy’s proposal said that the high-adoption scenario would bring a projected $11 billion more in net benefits to the state compared to the medium-adoption scenario. But the proposal failed 2-2, with Olson and commission Chairwoman Lea Marquez Peterson opposed. O’Connor abstained.

According to the TE plan, TEP and APS support establishing an EV goal for their respective service territories based on the statewide medium-adoption scenario. For TEP, the goal is 95,000 EVs on the road by 2030. For APS, the goal is 450,000 EVs.

Aiming High

Several groups had urged the commission to aim for the high-adoption target. Doing so would allow utilities to better plan for peak loads and help certain regions of the state bring their air quality into compliance with federal ozone standards, they said.

But Marquez Peterson raised questions about the high-adoption scenario in a Dec. 13 letter to her fellow commissioners.

Marquez Peterson said the commission must base its decisions on facts and data. She said she found no evidence that the high-adoption scenario would prevent a reclassification of the Phoenix-Mesa area from “marginal” to “serious” ozone nonattainment, which is expected to occur in 2024.

The Arizona Department of Environmental Quality (ADEQ) told Marquez Peterson that the state would need to replace more than 1.3 million internal-combustion-engine vehicles with EVs within the next two years to avoid the reclassification. That assumes EV adoption is the only measure the state pursued to improve air quality.

In addition, the Maricopa Association of Governments (MAG) said that the large drops in traffic related to the COVID-19 pandemic “have not resulted in a comparable reduction in ozone air pollution,” Marquez Peterson said in her letter.

“Until MAG, ADEQ and other stakeholders determine the appropriate number of EVs necessary, there is no adoption scenario modeled in the Phase ll report [transportation electrification plan] that bears any relation to preventing or reversing ozone nonattainment in Arizona,” she wrote.

Marquez Peterson also said the commission does not have authority to require a specific number of EVs or adopt air quality mandates.

Overcoming Barriers

The transportation electrification plan is the result of a 2019 commission decision that ordered the state’s utilities to develop a long-term, comprehensive TE plan.

APS and TEP worked with consultants Energy and Environmental Economics (E3) and Illume Advising to develop the plan, which was released in March. A public workshop on transportation electrification followed in August. (See EV Growth Prompts Need for Managed Charging.)

The plan outlines barriers to transportation electrification and steps that TEP and APS are taking to overcome those obstacles. For example, to address a shortage of EV charging infrastructure, the utilities offer programs such as APS’ Take Charge AZ, which covers costs for installing EV chargers at businesses and multi-family housing.

The plan lists a wide range of recommendations from a stakeholder panel. The stakeholders advised electric utilities to devise EV rates and electrify their own fleets. The state is encouraged to enact zero-emission vehicle legislation and offer incentive programs for EVs and charging infrastructure.

As part of the plan, APS and TEP plan to track progress of transportation electrification through metrics that may include the number of public EV charging stations and plug counts, the number of customers enrolled in EV or time-of-use rates, or a summary of EV programs in each service territory.

Environmental groups were enthusiastic about approval of the transportation electrification plan.

“With more electric cars on our roads, we can lower utility rates, improve air quality, and boost public health outcomes,” Ellen Zuckerman, utility program co-director for the Southwest Energy Efficiency Project (SWEEP), said in a release. “This decision sends a strong signal that Arizona is serious about transportation electrification and all of its great benefits.”

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Mass. Adds 1,600 MW to OSW Portfolio in Latest Procurement

Massachusetts selected two projects on Friday with a total of 1,600 MW in generating capacity to move forward in its latest offshore wind energy procurement.

Mayflower Wind, awarded 400 MW and Vineyard Wind awarded 1,200 MW for its Commonwealth Wind project, will begin contract negotiations under the state’s 83C III request for proposals issued in May. If regulators approve the project contracts next year, they will bring the state’s OSW total to 3,200 MW.

“The bipartisan energy legislation our administration worked with the legislature to pass in 2016 has unlocked record low pricing and significant economic investment through three separate procurements, and the projects selected today further illustrate the potential offshore wind presents for our climate goals, our local workforce and our port communities,” Gov. Charlie Baker said in a statement.

In March, Baker signed climate legislation that authorized a new total of 5,600 MW of OSW procurements for the state by 2035. The 800-MW Vineyard Wind 1 project and the 804-MW first phase of the Mayflower Wind project won contracts under the 83C and 83C II RFPs, respectively. Vineyard Wind and Mayflower Wind were the only bidders for the latest RFP, with both entities providing multiple bid sizes. (See Mass. Governor Signs NextGen Climate Bill.)

Bidders had to address new provisions in the 83C III RFP relating to diversity, equity and inclusion. Their submissions included strategies to promote job access for disadvantaged community members and identified how projects would affect environmental justice populations in the state.

Commonwealth Wind

Avangrid (NYSE:AGR) subsidiary Avangrid Renewables and Denmark-based Copenhagen Infrastructure Partners (CIP) submitted the Commonwealth bids as a joint venture, but the companies announced a restructuring in September. Under the agreement, Avangrid will buy the Commonwealth project and the lease area for the proposed 804-MW Park City Wind project. CIP will take control of a nearby lease area for development. (See Partners Behind Vineyard Wind Divvy up Leases.)

If the restructuring is approved, the Commonwealth project will bring Avangrid’s OSW portfolio to 2,400 MW, the company said.

Contract approval for Commonwealth will move several major infrastructure initiatives forward for the region.

The developer will site an OSW control center in New Bedford, Mass., that will provide remote project monitoring. New Bedford also will be the home of a service and maintenance hub through Avangrid’s partnership with Semco Maritime.

In addition, Prysmian Group plans to build a transmission cable manufacturing facility in a former coal plant in Somerset, Mass. And Crowley Marine will develop a wind turbine assembly and staging port at Salem Harbor Station. (See Vineyard Wind to Build Salem OSW Port if Mass. Approves Newest Bid.)

Mayflower Wind

The 400 MW Mayflower Wind bid is the second award for a lease that is co-owned by Royal Dutch Shell (NYSE:RDS.A), EDP Renewables and Engie.

Development of the Mayflower project will support the buildout of an operations center in the city of Fall River. (See Mayflower Wind Pledges $81M for Economic Development in OSW Bid.) In addition, Mayflower said in October that it will work with Gladding-Hearn to build a crew transfer vessel.

“From their office on South Main to their O&M port at Borden & Remington and the tens of millions of dollars in support of education and training and supply chain growth, Fall River is poised to benefit city-wide and our residents — all of our residents — can celebrate in the new jobs and opportunities that the offshore wind industry promises to bring,” Fall River Mayor Paul Coogan said in statement.

Mayflower signed an agreement in May to use transmission assets developed by Anbaric Development Partners in Somerset to connect OSW to the New England grid.  The developers plan to interconnect both phases of Mayflower at Falmouth, Mass.

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Maryland Green Buildings Bill To Be Based on Commission Report

Commercial and multifamily residential buildings in Maryland would be required to eliminate their carbon emissions and new buildings would be all-electric under a bill being drafted in the state’s House of Delegates. And ideas in the recently released Maryland Climate Change Commission’s 2021 annual report are playing a key role, says the bill’s lead sponsor.

“I’ll be working in the House of Delegates on the buildings bill, and it’s likely we’ll be including a number of recommendations from the report, such as the electric code for new buildings and the emissions standard for existing buildings,” Del. Dana Stein (D), said in an interview with NetZero Insider. “The report has been very helpful for that.”

Stein’s proposal would seek to implement at least two of the 16 recommendations for the buildings sector, which the Commission’s Greenhouse Gas Mitigation Working Group (MWG) developed in a series of meetings earlier this year. (See Maryland Looks at Pathways to Net Zero Buildings by 2045.)

“I can’t say which of the recommendations beyond the electric code for new buildings and an emissions standard for existing buildings will be in the bill,” Stein said in an email. He said he is working on the bill with Del. Kumar Barve (D), chair of the Environment and Transportation Committee, and that he hopes they will finish drafting the bill before or shortly after the legislature’s next session begins Jan. 13.

Electric Code for New Buildings

The Mitigation Working Group recommended the Maryland Building Code Administration adopt a code that requires new buildings meet all water and space heating demand without fossil fuels (e.g., through electric heat pumps, solar thermal, etc.) and can accommodate solar panels, electric vehicle charging, and building-grid interaction. It would apply to all new residential, commercial and state-funded buildings beginning no later than 2024.

Exemptions would be allowed for building types for which compliance is not feasible. The Building Code Administration also would be required to develop a cost-effectiveness test, including the federal social cost of carbon, to allow building projects to seek variances to code requirements. A new commercial building that receives a variance and produces greenhouse gas emissions on-site would be required to participate in the proposed Building Emissions Standard and follow a “tailored plan” for reaching net-zero emissions. Residential building projects would also be permitted to seek variances using the cost-effectiveness test.

Annualized-lifecycle-consumer-costs-(E3)-Content.jpgAnnualized lifecycle consumer costs, including costs for equipment, operations and maintenance, and utility bills, for several types of buildings. | Energy + Environmental Economics (E3)

The Building Code Administration also would be charged with developing training courses on the benefits and challenges of all-electric and electric-ready buildings for developers, real estate agents, appraisers and lenders.

The MWG cited studies that it said found new all-electric homes have lower construction and energy costs than mixed-fuel homes, which would improve housing affordability and local air quality while also reducing greenhouse gas emissions. The group said heat pumps work well in Maryland’s climate and are the second most common heating system for buildings in the state.

But the MWG called for cost-effectiveness tests in recognition that all-electric design can increase construction and energy costs for commercial construction.

The MWG said the state could adopt the New Building Institute’s Building Decarbonization Code, which includes an all-electric pathway. It also pointed to recently adopted building energy efficiency codes in California and Washington.

Emissions Standard for Existing Buildings

The MWG also recommended the Maryland Department of the Environment develop a Building Emissions Standard to bring commercial and multifamily residential buildings to net-zero emissions by 2040, with state-owned buildings facing a 2035 deadline. Historic buildings would be exempt.

The state would require measurement and reporting of on-site emissions beginning in 2025 and provide financial support for implementing emissions reduction measures. Such measures would include building shell and other energy efficiency improvements and replacing fuel-burning equipment with heat pumps and induction cooktops.

It would provide an “alternative compliance pathway” allowing commercial building owners to pay a fee for emissions above target levels. The fee would be “reasonable,” perhaps corresponding with the cost of carbon sequestration or negative emissions technologies, “but not less than the federal social cost of carbon.” The MWG set the target date for 2040 to allow the state time to invest revenue from non-compliance payments into measures such as carbon sequestration or negative emissions technologies to address remaining emissions.

The proposal also would offer commercial tax credits and direct subsidy payments to reduce the simple payback period for decarbonization improvements to between three and seven years.

The MWG cited New York City and Boston as among the cities that have implemented building performance standards for commercial buildings to eliminate emissions.

The Climate Change Commission’s recommendations for single-family homes have to do with funding mechanisms to encourage conversion to electricity rather than the mandates proposed for commercial and multi-family homes.

Controversial Interim Goal Dropped

Stein said the building recommendations were “very strong.

“In buildings, there [previously] wasn’t a game plan for getting that sector to net zero. So, the focus and recommendations are very good,” he said.

But he added, “One area I wish they would have been stronger in was the building emissions sector — though the final goal is net zero, there is no interim goal.”

At its Oct. 13 session, the MWG set aside a proposed interim goal of a 50% reduction in direct emissions from covered, non-state-owned buildings by 2030. It will instead consider it for review in its 2022 work plan.

“There was a 50% interim goal, but some thought that was too aggressive, so it was tabled till next year,” Stein said.

Also supportive of the commission’s 2021 report was David Smedick, acting deputy regional campaign director for the Sierra Club’s Beyond Coal Campaign. “For two years in a row now, the Maryland Commission on Climate Change has delivered a clear message to the governor and General Assembly: The state must rapidly ramp down and eliminate fossil fuel use, grow clean energy, and electrify our buildings and vehicles,” he said in an email to NetZero Insider. “This isn’t a complicated formula, but Maryland has been stuck in debate and incremental climate progress for years.

“Now is the time for the bold action from Annapolis leaders to retrofit and electrify our building stock, plan the transition off coal and fracked gas power plants, commit big to offshore wind and solar, and transform the state’s transportation systems to grow public transit and electrify vehicles,” he said. “We’re in a code red climate emergency. Anything less than transformative action is failure.”

Capitol Strategies lobbyist Erin A. Appel, who represents the International Association of Shopping Centers, said the group had no immediate comment on Stein’s proposal.

Tom Ballentine, vice president of policy and government relations for the Maryland chapter of the Commercial Real Estate Development Association, who serves on the MWG; Kristin Hogle, director of external communications for the Maryland Building Industry Association, and lobbyist Ashlie Bagwell, who represents Federal Realty Investment Trust, did not respond to requests for comment.

16 Recommendations

The climate change commission’s appendix on its Building Energy Transition Plan, released last month along with the annual report, made 16 recommendations. In addition to the two provisions Stein has embraced, they include a clean-heat retrofit program in which all low-income households would be retrofitted by 2030. Fuel-switching and beneficial electrification would be encouraged beginning in 2024 through EmPOWER, the state’s energy efficiency program. The retrofitting program would include a target of having heat pumps account for 50% of residential heating, ventilation, and air conditioning and water heater sales by 2025, and 95% by 2030.

The commission also called for developing utility transition plans, ending EmPOWER subsidies for fossil fuel appliances, and having the state lead by example through the electrification and decarbonization of buildings it owns. It also proposes allowing local jurisdictions to set higher fines for non-compliance on building performance, and identifying locations that need grid upgrades to accommodate all-electric buildings.

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NERC Identifies 10-Year Challenges from Weather, Resource Mix

The growing frequency of severe weather events and a rapidly diversifying resource mix will present closely intertwined challenges to electric reliability in the coming decade, NERC said in its annual Long-Term Reliability Assessment (LTRA), released Friday.

“Our traditional baseload generation plants like coal and nuclear are retiring, and lots of new natural gas and variable generation, mostly solar and wind, have been deployed,” John Moura, NERC’s director of reliability assessment and performance analysis, said at a media event accompanying the release of the report.

Moura called the transition to renewable resources “a really great thing for our decarbonization efforts,” but added that “it’s vitally important that we [build and operate] a bulk power system that can be resilient to the extreme weather we’re seeing.”

NERC produces the LTRA every year to assess North American resource adequacy in the next decade and to identify trends that could affect grid reliability and security. This year’s assessment identified resource adequacy as a serious concern in MISO, Ontario and the south-central U.S., while extreme weather poses the biggest concern in New England and Texas. The Western Interconnection — including California, the Northwest and the Southwest — faces both risks.

Transition to Renewables Continues

Tier 1 and 2 planned resources (NERC) Content.jpgTier 1 and 2 planned resources projected through 2031. Tier 1 resources are planned capacity that have completed or are under construction, or have a signed/approved interconnection service, power purchase, or wholesale market participant agreement. Tier 2 resources are capacity that have signed/approved completion of a feasibility, system impact, or facilities study; have requested an interconnection service agreement; or are included in an integrated resource plan. | NERC

The resource adequacy challenge is partially caused by the decommissioning of traditional generators. MISO, for example, is projected to retire more than 13 GW of resource capacity between 2021 and 2024, while the report warned that the planned retirement of California’s Diablo Canyon nuclear power plant could contribute to more than 3 GW of capacity shortfalls beginning in 2026. Across the bulk power system, total capacity retirements are expected to top 60 GW by 2031, with coal making up the majority of plants decommissioned.

NERC’s projections show a steady decline in coal and petroleum generation through 2031, with the greatest growth expected in solar. Natural gas, meanwhile, is set to expand into the gap left by the retiring coal plants.

The more than 100 GW of additions to the BPS over the next 10 years — considering only Tier 1 resources, which comprise completed and under construction projects, as well as those with signed and approved interconnection service or power purchase agreements — are almost entirely solar and natural gas facilities. Other forms of generation, such as wind, petroleum, hydropower and nuclear, account for around 20% of capacity additions, with wind comprising nearly half of these.

With Tier 2 resources added in — those with signed or approved feasibility, system impact, or facilities studies, or that have requested an interconnection service agreement — solar plants are expected to grow from the current level of 41 GW to around 331 GW during the next 10 years. By the same measure, wind resources are set to expand from 132 GW to more than 244 GW over the same period.

The simultaneous growth of gas and solar is no accident, said Mark Olson, NERC’s manager of reliability assessments. Solar panels are naturally dependent on the availability of sunlight, and while the resources planned for addition are sufficient to meet demand at peak hours — typically in the middle of the day — they actually pose a problem later in the afternoon. At these times demand is lower, but the output of solar panels falls off sharply because less light is present, requiring another resource to pick up the load.

“Even though the reserve margins are adequate, energy risks are reduced by having sufficient flexible resources, which are resources that can be dispatched by the operators to follow demand, balance the system and make up for drop-off in variable resources,” Olson said. “And natural gas-fired generation is an important resource, as are effective demand response programs, in helping to reduce risk associated with [that] drop-off.”

Climate Change Makes Demand Forecasting Harder

While the weather restrictions of solar and wind imply that balancing resources should be expanding with them, Olson noted that the opposite seems to be happening in some regions, with “flexible generation resources … falling in Texas, California and the U.S. Northwest.” He warned that without local flexible generation, such areas will be dependent on weather-dependent facilities and external transfers. However, “extreme weather conditions raise the likelihood for one or more of these resources to fall short … leaving other resources to make up for this gap or … load will need to be shed.”

The LTRA noted that this combination of new types of generating resources and growing climate challenges means that existing methods of measuring resource adequacy may not be adequate. In particular, the report noted that the reserve margin — NERC’s traditional metric for reliability, defined as the difference between projected on-peak capacity and forecasted peak demand, divided by peak demand — may be too limited to capture the nuances of new generating resources.

“It’s kind of a simplistic way of looking at one hour and coming to a conclusion for all other hours,” Moura said. “And that’s served us well, and [still] serves us well in certain parts of the [continent] … where you have a lot of dispatchable resources. But in areas where we’re seeing these energy constraints, like in California, the Northwest, and ERCOT, we need to look with a different lens.”

Moura said that NERC has “a close partnership on a project right now with [the] Electric Power Research Institute” to study new metrics for use in planning and decision making. He suggested that industry stakeholders may also draw on work from their counterparts in other countries, without elaborating on what these might be.

“That is only part of the solution because then you … actually have to” create and enforce new standards based on these metrics, he added. “But right now, we’ve got to define this measuring stick to really help and guide what that path looks like going forward.”

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FERC Rules in Three SPP Disputes

FERC last week issued rulings in three SPP dockets, including Tenaska’s complaint over a network upgrade cost assignment; a dispute between Nebraska Public Power District and Tri-State Generation and Transmission; and NorthWestern Energy’s challenge of a qualifying facility.

Split Decision for Tenaska in SPP Complaint

FERC last week ordered SPP to restudy a Missouri wind project by Tenaska, which complained that the RTO erroneously assigned it about $66 million in network upgrade costs (EL21-77).

The commission’s Dec. 16 order found that SPP appropriately applied its authority under its tariff to restudy the project after one or more higher-queued projects withdrew; corrected the omission of 4.5 GW of higher-queued generation; and used the network resource interconnection service (NRIS) standard to evaluate the project’s effects on its system.

At the same time, FERC said SPP’s use of 2019 transmission-planning models in the restudy was unduly discriminatory or preferential. It directed SPP to restudy the project within 60 days using the 2017 planning models and incorporate the 4.5 GW of missing generation. It directed SPP to make a compliance filing within 10 days of the restudy’s completion.

Tenaska alleged that SPP mistakenly assigned the upgrade costs during a restudy of the Clear Creek Wind Project, a 242-MW facility that is interconnected to the Associated Electric Cooperative, Inc. (AECI) transmission system. It said the costs were assigned as part of SPP’s affected system study (AFS) process and asked that they be rolled into regional transmission rates or that FERC set a hearing to determine their equitable allocation. (See Tenaska Challenges SPP Tx Upgrade Costs.)

Clear Creek became operational in May 2020.

The developer requested an NRIS study in 2017. AECI identified SPP and MISO as potential affected systems; MISO’s AFS found no network upgrades were necessary to its system.

In August 2018, Tenaska requested that SPP conduct an AFS of the Clear Creek project. The RTO told Tenaska the project would be queued between the 2016-002 and 2017-001 definitive interconnection system impact studies (DISIS) and that it would use the 2016 cluster’s transfer case, reflecting capacity additions and associated network upgrades, as the base case. That transfer case used SPP’s 2017 Integrated Transmission Planning (ITP) study models, as the basis for its regional transmission planning studies.

SPP’s first AFS study identified $31.2 million in network upgrades it said were necessary to connect the project to the AECI system. The grid operator twice revised the study, in November 2018 and March 2019; the latter found approximately $33.5 million in network upgrades. FERC noted SPP only identified network upgrades to resolve constraints when modeling for energy resource interconnection service (ERIS).

After Tenaska began construction in 2019, it said it was told by SPP that the RTO intended to restudy the project because a higher-queued project had withdrawn from the interconnection queue. The RTO then told Tenaska in May 2020 that, because the initial studies’ models were more than a year old, staff intended to conduct the affected system restudy using the 2019 ITP models.

The study identified $763 million in network upgrades to the AECI system and the need for NRIS network upgrades. SPP said it had inadvertently omitted 4.5 GW of higher-queued generation on the MISO transmission system in the project’s first AFS and the DISIS 2016-002 cluster. The RTO deemed the initial AFS invalid and decided to use the 2019 ITP models for the restudy that lowered Tenaska’s cost responsibility to $106.8 million. In February 2021, that amount was lowered again to $91 million.

Clear Creek Project (Tenaska) Content.jpgTenaska’s Clear Creek Wind Project in Missouri | Tenaska

In March 2021, SPP posted the most recent affected system restudy results, assigning about $99 million in network upgrades to Clear Creek, comprised of $34 million in ERIS network upgrade costs and $66 million in additional network upgrade costs necessary to provide NRIS identified in the affected system restudies.

Commissioner Alison Clements concurred with the order “only because it conforms to the standards and requirements currently applicable to SPP’s affected system study process” and filed a separate statement.

She said the order demonstrates that reasonable efforts and good utility practice standards are “currently so lenient that neither SPP’s delay of over a year in completing the restudy process … nor SPP’s serious omission of 4.5 GW from its initial studies rises to the level of a violation.”

“I am sympathetic to the formidable challenges that overwhelmed regional interconnection queues cause for transmission owners, operators and interconnection customers,” she wrote. “Our regulatory standards do not mean much, however, if they are lenient to the point of impotence. As the commission turns to addressing transmission and interconnection reforms in the coming months, the standards applicable to interconnection studies must be among the topics to receive the commission’s attention and careful scrutiny.”

NPPD Complaint Rejected

The commission also rejected a Nebraska Public Power District (NPDD) request that FERC find Tri-State Generation and Transmission’s inclusion of certain costs in its 2021 annual transmission revenue requirement (ATRR) unjust and unreasonable (EL21-100).

FERC said NPPD did not demonstrate that Tri-State’s inclusion of amounts related an agreement between the two SPP members seriously harmed the public interest.

NPPD in 2018 asked the commission to direct Tri-State to remove from its ATRR costs related to an earlier Western Nebraska Joint Transmission Agreement (NETS Agreement) between the two that governed the use of transmission facilities. Under the agreement, the party making greater use of the facilities was required to make an annual cost equalization payment to the other party.

The agreement originally had a 2020 termination date, which Tri-State agreed to extend to March 1, 2021, to allow for negotiations between the two and SPP. The cooperative made its final payment under the agreement to NPPD in February 2021.

In July, SPP posted Tri-State’s update of its 2021 ATRR for the rate year beginning Sept. 1 and included an annual cost-equalization payment of more than $1.84 million. NPPD said the payment’s inclusion led to unjust and unreasonable rates because the NETS agreement was terminated and Tri-State had made its last payment. It also alleged the cooperative was no longer incurring any costs under the agreement and that Tri-State refused to remove the payment from the annual update process.

FERC said it found the disputed cost component was included in 2017 settlement agreement between NPPD and Tri-State over SPP’s placement of the Tri-State in NPPD’s transmission zone. (See FERC Rejects NPPD Objection to Tri-State Zonal Placement.)

The commission said that under the agreement, NPDD had to demonstrate that the proposed modifications to the ATRR and underlying rates satisfy the “public interest” application of the just and reasonable standard. It said the utility had failed to do so.

FERC also found that NPPD agreed in the settlement to Tri-State’s use of a formula rate based on the prior calendar year’s financial data. It said that by arguing that the cooperative should not be permitted to include the annual cost equalization payment Tri-State made in 2020 in its 2021 ATRR, “NPPD is seeking to modify the nature of the formula rate and, thus, modify the settlement agreement.”

“We find that NPPD, as a settling party, must make a showing sufficient to demonstrate that, without the proposed changes, the settlement agreement ‘seriously harms the public interest,’” the commission wrote.

NorthWestern Protest Denied

FERC denied NorthWestern Energy’s (NASDAQ:NWE) protest of a solar developer’s self-certification as a small power production qualifying facility (QF) under the Public Utility Regulatory Policies Act (PURPA) of 1978 (QF21-1213).

Gallatin Power Partners in September filed a form self-certifying its Shields Valley Solar Facility, to be interconnected with the NorthWestern system in Montana, as a QF. It said the development would have a 160-MW nameplate capacity but would also incorporate a battery-storage system with an expected 80 MW capacity on the solar array’s DC side, resulting in a maximum net AC power production capacity of 80 MW.

NorthWestern protested, arguing that the solar array and the storage systems were separate power-production facilities and that their capacities should be analyzed separately and then aggregated, resulting in a production capacity substantially larger than 80 MW. It based its argument on FERC’s March rehearing order for Broadview Solar that restored longstanding commission precedent for determining QF eligibility and extending it to integrated battery energy storage. (See FERC Reverses Ruling on Montana QF.)

The commission determined that because the Shields Valley facility could only deliver a maximum of 80 MW of AC electricity to NorthWestern’s system at any time, its production capacity “cannot and will not” exceed 80 MW. It said NorthWestern’s protest relitigated the Broadview rehearing orders’ capacity analysis and “effectively” requested that FERC overturn its findings and amounted to a “collateral attack” on those orders.

Commissioner James Danly concurred in part and dissented in part, saying as he did in the Broadview orders that “there is no net-output exception” to PURPA’s production capacity threshold.

However, Danly also disagreed with NorthWestern’s protest, noting batteries and other storage systems cannot be included when determining a facility’s “power production capacity” because they “do not ‘produce’ power — they simply store it for later delivery.”

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Court Overturns FERC on CAISO CPM Rates

The D.C. Circuit Court of Appeals on Friday overturned a 2020 FERC ruling that approved CAISO’s decision to award a 20% adder to above-cap bids for resources needed for grid reliability, saying FERC’s decision “was not the product of reasoned decision-making.” (20-1388).

The case involved CAISO’s capacity procurement mechanism (CPM), which lets the ISO purchase electricity needed to maintain grid reliability in extraordinary circumstances. It was based on a challenge by the California Public Utilities Commission, which claimed that CAISO and FERC had erred by awarding the adder to CPM resources that exceeded CAISO’s soft-offer cap reference bid of $6.31/kW-month.

CAISO and FERC had previously approved a 20% adder for resources that bid under the ISO’s soft-offer cap, saying the adder would cover going-forward costs such as maintenance and upgrades. FERC relied on its prior decision to also approve the 20% adder for resources that sought compensation above the soft-offer cap by applying for a higher rate from FERC.

The D.C. Circuit said FERC had relied on its own precedent regarding the soft-offer cap without considering the differences in the two cases.

“The commission relied chiefly on its 2015 CPM Order approving the soft-offer cap, which includes a 20% adder,” the court said. “The commission inferred from its 2015 order that applying the same adder to above-cap CPM bids would be just and reasonable.”

That was a mistake, the court said.

FERC “may attach precedential, and even controlling weight to principles developed in one proceeding and then apply them under appropriate circumstances in a [precedential] manner,” the court said. “But application of precedent is warranted only if the factual composition of the case to which the principle is being applied bears something more than a modicum of similarity to the case from which the principle derives.”

“Here … the commission failed to grapple with the distinction between bids submitted below or above the soft-offer cap, resulting in the commission’s reliance on precedent without recognition of the substantial differences between the two cases,” it said.

With the below soft-offer cap bids, “CAISO reasoned that the 20% adder would allow resources with costs higher than the reference resource to recover their going-forward costs and additional fixed costs, as well as providing investment incentives,” the court said. “In the event that the soft-offer cap does not allow a resource to recover its going-forward costs, that resource can submit a cost-justified filing to the commission for a higher rate.”

Providing the adder to above-cap bidders, however, “effectively renders the compensation formula uncapped; the greater a facility’s going-forward costs, the more it stands to recover through its cost-justified bid. This uncapped recovery stands in stark contrast to the soft-offer cap, which is meant to cap maximum bids evenly in order to facilitate competition among resources.”

Without reference to its precedent regarding soft-offer cap bids, “the commission’s order has little else, if anything, to support it,” the court said.

The court vacated FERC’s order and remanded the case for further proceedings consistent with its order.