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October 30, 2024

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National Grid Plans $35B Investment in NY, Mass.

National Grid plans to invest $75 billion in its infrastructure over the next five years, nearly half of it in New York and Massachusetts. 

The UK energy company announced the plan May 23 with its year-end financial results and said the $35 billion investment in the two states would be over 60% higher than in the past five years. 

National Grid also announced it would sell National Grid Renewables, its U.S. onshore renewables business, and Grain LNG, its UK LNG asset, as it focuses more closely on its energy networks. 

In a news release, National Grid said the New York and Massachusetts projects would harden the electric grid, reduce emissions and provide benefits to both customers and local economies. 

The company noted the Department of Energy in its 2023 National Transmission Needs Study forecast a need for a 255% increase in transmission development to support the two states’ anticipated clean energy growth. 

The news release emphasized the investments in electric networks and the resulting benefits for states’ decarbonization goals. But the financial report indicates a little more than 40% of the $35 billion would be spent on natural gas infrastructure, including a proposed three-year, $5 billion modernization of National Grid’s downstate New York gas businesses. 

Continued investment in gas infrastructure has been a friction point between utilities and decarbonization advocates. National Grid notes that the work planned would be for safety and reliability purposes and would provide environmental benefits by reducing leaks. 

In total, National Grid said it plans to invest about $21 billion in New York through March 2029. More than $4 billion of this would go to the Upstate Upgrade, a portfolio of more than 70 transmission enhancements designed to increase reliability, resilience and capacity.  

As it announced the upgrade in March 2024, the company called it the largest investment in the grid in its century-plus existence — building, rebuilding or modernizing more than 1,000 miles of transmission line. As a result, 45 substations would be built, rebuilt or modernized. 

The New England investment would total about $14 billion and include smart meters, modernized infrastructure, hardening against extreme weather and quality upgrades to electric and gas assets. Part of this would be National Grid’s Electric Sector Modernization Plan, a $2 billion proposal submitted to Massachusetts regulators as part of the state’s drive to upgrade the grid and accelerate connection of renewables. 

The dollar figures are approximate and are based on present UK-U.S. currency exchange rates. 

The plan involves an equity raise of 7 billion British pounds, or nearly $9 billion. 

The company’s share price, which recently traded near 52-week highs, took a dive after the plan was announced, closing 10.9% lower May 23 on the London Stock Exchange and 14.3% lower on the New York Stock Exchange. 

For the fiscal year ended March 31, National Grid’s operating profit was down 8% from the previous fiscal year, its pre-tax profit was down 15% and its earnings per share were down 19%. 

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NJ Wrestles with Clean Energy Priorities

A New Jersey campaign to solicit public opinion on a new Energy Master Plan has sparked intense and diverging opinions, with state officials claiming achievements triggered by the previous plan and environmentalists charging the next plan should be tougher, bolder and more aggressive.

Speakers at the first of four public hearings organized by the New Jersey Board of Public Utilities urged the agency to emphasize cutting emissions from heavy- and medium-duty trucks and aggressively tackle methane emissions. Several speakers at the May 20 hearing asked the BPU to do more to reduce vehicle miles traveled in the state and push public transit, while business groups demanded closer attention to the cost of the plan.

The discussions follow the 2019 Energy Master Plan, which environmentalists depicted in the hearings as too timid and ineffective.

“The 2019 plan wasn’t strong enough, wasn’t really implemented,” said David Pringle of Empower NJ, a climate coalition. And he expressed concern that the next version would have the same impact because it won’t be completed until the final months of Gov. Phil Murphy’s tenure, which ends in January 2026.

BPU officials said they expect to complete a draft of the new plan by the third quarter, and the final report by the end of the year. That will form the cornerstone of the state’s “comprehensive climate action plan,” with a release target date of the third quarter of 2025, said Eric Miller, executive director of Murphy’s Office of Climate Action in the Green Economy.

Miller said the goal of the master plan initiative is to “identify the best pathways for New Jersey to achieve its ambitious climate targets.” It will build upon the 2019 plan and adapt to the changes that have taken place since, such as new clean energy goals and money available through the federal Inflation Reduction Act, he said.

“We’ll be conducting a deeper and more robust study of the cost of climate mitigation for our residents,” Miller said. That will include “detailed gas and electric rate modeling, in addition to the upfront capital costs associated with decarbonization” and will enable the state to “more deeply explore how a diverse range of demand reduction strategies may help alleviate peak electric load.”

Clean Energy Advances

Whatever its impact, the 2019 New Jersey plan came as the state embarked on a series of clean energy initiatives considered among the more aggressive in the nation.

The state, which already had a strong portfolio of solar projects when the previous master plan was created, has continued to add solar capacity, launching a highly popular — and oversubscribed — community solar program.

State incentive programs had by the end of 2023 helped put 154,153 electric vehicles on the road, about halfway to the goal of 330,000 by 2025. The state also has heavily backed offshore wind energy, approving five projects and building a $600 million wind port. The state suffered a setback in October when developer Ørsted abandoned two projects, but three OSW projects with a capacity of 5.25 GW are ongoing, and the state launched a fourth solicitation on April 30. (See New Jersey Opens 4th Offshore Wind Solicitation.)

In September 2021, Murphy increased the state’s OSW capacity target from 7.5 GW to 11 GW by 2040. That followed the governor’s moving forward the goal of reaching 100% clean energy electricity generation from 2050 to 2035.

In advance of the public hearings, the BPU issued a request for information seeking stakeholder input at the first meeting on a range of topics, among them how to shape the state’s EV incentives as uptake progresses, and how to support and accelerate the development of the OSW and solar projects without placing too much burden on ratepayers.

Cost is Key

The cost of implementing the final plan emerged as a consistent theme at the more than three-hour meeting, at which about 50 people spoke.

The New Jersey Chamber of Commerce said it supports the state’s OSW initiatives and the goals of the Energy Master Plan but urged the BPU to hire an “independent, outside organization” to study the costs and ratepayer impact.

“Transparency in costs is essential to ensuring the success of the implementation,” said Laura Gunn, a lobbyist for the chamber.

Doug O’Malley, state director of Environment NJ, said the state needs to be ready to provide financial support for whatever proposals end up in the plan.

“We can solve our climate crisis by investing in clean energy, including energy storage,” he said. “The missing ingredient of past Energy Master Plans and the future ones is that it needs funding, and it needs funding from the Murphy administration that will meet the moment and meet the challenge, to ensure that we’re not underfunding the solutions.”

Any assessment of the cost of the plan should take into account the cost of “inactivity,” the expenses arising from the extreme impacts of climate change if the state does not combat climate change, he said.

Peggy Middaugh, of Unitarian Universalist FaithAction NJ, also said the BPU should go beyond calculating the costs of implementing initiatives to include the broader costs that would result if the state failed to cut emissions, such as health costs, property damage from wildfires and flooding, and “the reduction in value of real estate in flood-prone areas.”

Reducing Miles Traveled

Middaugh added that cutting emissions from transportation should be a key element of the master plan, including efforts to reduce emissions by using EVs or bolstering the state mass transit agency so more people will use it.

But the plan should go much further and seek to cut the distance that people travel to get to work, she said.

“In almost all New Jersey municipalities, a large majority of the residents leave town to go elsewhere to work while a large majority of the jobs in the municipality are filled by non-residents,” Middaugh said. “This requires a deep examination of development and our transportation infrastructure.”

Chris Sturm, policy director of land use for New Jersey Future, a nonprofit organization that promotes sustainable growth, said vehicle miles traveled statewide have increased annually for most of the past 50 years, and the organization has crafted a plan to reduce the number by 8.5% by 2050. Implementation would include measures such as investing in bike and pedestrian infrastructure and mass transit, and creating municipal developments that put homes closer to grocery stores, schools and bus stops.

John Reichman of Empower NJ said the most effective step toward reducing vehicle miles traveled would be to “stop expanding highways and instead invest that money in public transit” and pedestrian walkways. He urged the state to stop the expansion of the New Jersey Turnpike just outside New York City, which he said would cost $10.7 billion.

“Prioritizing expanding highways is a policy of the 1950s that totally ignores the climate crisis,” he said.

Speakers also offered diverging opinions as to what should be considered clean energy.

Gunn urged the BPU to take a broad view of acceptable energies, including natural gas, nuclear, renewable natural gas and hydrogen, and to “recognize the vital importance of the state’s gas distribution system going forward.”

“The more options our residents and businesses have as it relates to energy production in New Jersey, the more affordable it will be,” she said.

But environmental groups encouraged a much harder line, with some calling for a moratorium on the development of any fossil fuel generating plants and urging the BPU not to accept alternative fuels that are not 100% clean energy.

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NERC Says IBR Work Proceeding as Planned

A year on from FERC’s approval of NERC’s work plan for registering inverter-based resources (IBRs) such as solar and wind facilities, representatives from the ERO and its regional entities say the task is on track to conclude on schedule. 

Speaking at a webinar hosted by the Texas Reliability Entity, Howard Gugel, NERC’s vice president of regulatory oversight, said the ERO is in the second phase of the road map it laid out in its work plan, which the commission accepted May 18, 2023. (See FERC Approves NERC’s IBR Work Plan.) 

The plan follows a framework FERC described in a November 2022 order directing NERC to register IBRs that are not currently required to register with it but that are connected to the grid and, “in the aggregate, have a material impact” on reliable operation. According to FERC’s order, the ERO must complete any necessary modifications to its registration processes by 12 months after the commission approves its work plan, identify owners and operators of relevant IBRs within 24 months of approval and register them no later than 36 months after approval. 

In a progress update, Gugel said NERC’s Board of Trustees approved the appropriate changes to its Rules of Procedure (ROP) at a special meeting in February and filed them with the commission the following month, requesting an expedited review period of 60 days (RD22-4). FERC accepted comments on the proposal from industry stakeholders through April 18. 

“They are in the process right now [of] reviewing those comments, and we are hoping that they will provide some more guidance — either accepting our registration criteria or proposing … some further modifications — sometime in the very near future,” Gugel said. 

The proposed ROP changes would create a new category for entities that own or operate IBRs that either have or contribute to an aggregate nameplate capacity of at least 20 MVA and are connected to a common point of connection with a voltage of at least 60 kV. 

Currently, the ERO is using data from the U.S. Energy Information Administration and other sources to identify those resources ahead of FERC’s expected approval of the ROP updates. It is also drafting a request for information to be sent to registered entities, starting with balancing authorities and transmission owners, as soon as FERC has given its assent. 

Gugel also updated attendees on the ERO’s IBR-related standard development projects, which are also the subject of a FERC order issued last October. The commission directed NERC to submit standards aimed at improving the reliability of IBRs in three tranches beginning in 2024. 

At the moment, Gugel said, NERC has prioritized the first set of standards, which concern performance requirements and post-event performance validation for registered IBRs. These standards must be sent to FERC for approval by Nov. 4. 

The next set of standards will address data sharing and model validation for IBRs, to be completed by November 2025. The final tranche to be finished by November 2026 will concern planning and operational studies. 

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Massachusetts DPU Approves Everett LNG Contracts

The Massachusetts Department of Public Utilities has approved agreements between Constellation Energy and the state’s investor-owned gas utilities to keep the Everett LNG import facility operating through May 2030. 

The Everett Marine Terminal (EMT) is the only facility in the state that can import and directly inject LNG into the gas network, but it has faced an uncertain future, with Constellation’s cost-of-service agreement with ISO-NE expiring at the end of this month. Constellation owns both Everett and the Mystic Generating Station, Everett’s anchor customer, which is set to retire at the same time. 

Following extended negotiations with the state’s gas utilities dating back to 2021, National Grid, Eversource Energy and Unitil filed agreements with Constellation in February to help cover the facility’s fixed costs and provide the utilities the option to purchase LNG as needed. 

The utilities argued that the agreements were necessary for the reliability of the gas network, but they were met with pushback by environmental organizations and state agencies about the cost and climate implications of the agreements. The Conservation Law Foundation (CLF) opposed the agreements, while groups including Enbridge, Tennessee Gas Pipeline and Constellation supported the utilities’ filings. 

Neither the Massachusetts Attorney General’s Office nor the state Department of Energy Resources took an explicit stance on the contracts, but both called for additional transparency and reporting requirements. (See Mass. AGO, DOER Call for Climate Guardrails on Everett LNG Contracts.) 

In its ruling, the DPU found that “without the agreements, each company will not have sufficient natural gas supplies to reliably serve its customers in design-winter scenarios during the term of the agreements, which could jeopardize the health and safety of its customers during the cold winter months.” 

Responding to CLF’s argument that utilities did not adequately consider alternatives, the DPU ruled that “the alternatives to the agreements currently available to each company, including electrification, are insufficient to fully replace supplies from EMT or provide the reliability benefits that EMT offers.” 

The DPU also disagreed with CLF’s contention that the agreements are not compatible with the state’s climate laws. The department noted that Eversource’s and Unitil’s contracts are intended to replace existing gas supply contracts and are therefore in line with the precedent set by previous rulings. 

Meanwhile, National Grid indicated that its contract is needed in part to help meet increasing gas demand from oil-to-gas heating conversions. The department found that this justification is aligned with previous rulings “that the acquisition of incremental natural gas supply to serve new customers that convert from oil heating to natural gas heating is consistent with the” Global Warming Solutions Act. 

However, the DPU wrote that it may need to revisit this precedent following its December 2023 order (20-80-B) creating “a new regulatory framework” to discourage new investments in gas infrastructure. (See Massachusetts Moves to Limit New Gas Infrastructure.) The department also said it intends to consider whether equity and affordability impacts should be included in the evaluation of similar contracts going forward. 

Instead of changing the standard of review within the Everett proceedings, “the department finds it appropriate to engage in a more thoughtful, comprehensive process involving the participation of all interested stakeholders,” the DPU wrote. 

The department agreed to include annual transparency and reporting requirements around the cost and climate effects of the agreements, as well as on the utilities’ efforts to reduce their need for Everett. 

“We agree with the attorney general and DOER that open and transparent insight into the companies’ efforts to reduce or eliminate their reliance on EMT is critical to ensuring that the commonwealth remains on a path to achieve its decarbonization goals,” the DPU wrote. 

Throughout the process, climate and environmental advocates in the state have expressed concern that the contracts could function as a stop-gap measure to a more permanent pipeline capacity expansion into the Northeast. Enbridge has said it could complete a major capacity expansion of the Algonquin pipeline by the end of the decade. (See Enbridge Announces Project to Increase Northeast Pipeline Capacity.) 

Joe LaRusso, senior advocate at the Acadia Center, said the DPU’s approval of the contracts is “potentially in conflict with Order 20-80,” particularly if the contract timelines are intended to align with Enbridge’s pipeline expansion effort. 

He said the reporting requirements should give the DPU ample information on the utilities’ gas demand trajectories, with the “open question” being whether the DPU allows the companies to reduce their reliance on Everett by securing additional pipeline capacity. 

Meanwhile, Constellation applauded the DPU’s ruling, writing in a statement that the contracts will help “ensure adequate gas availability during extreme weather conditions as the region transitions to clean energy.” 

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Iberdrola to Take Full Ownership of Avangrid

Iberdrola is moving to acquire the 18.4% stake in Avangrid that it does not already own.

The Spanish-based multinational utility operator said May 17 that this is a growth strategy: It wants to expand its presence in markets with strong credit ratings and its exposure to regulated businesses such as networks.

The $2.55 billion deal is subject to approval by shareholders, FERC and utility regulators in Maine and New York. Upon completion, which is anticipated in the fourth quarter, Iberdrola will seek to delist Avangrid shares from the New York Stock Exchange.

Avangrid is headquartered in Orange, Conn. It has approximately $45 billion in assets and 8,000 employees, mainly in renewables and networks. Its operations include eight electric and natural gas utilities in New York and New England serving more than 3.3 million customers.

Iberdrola is based in Bilbao, Spain, and is the largest European electrical utility by market capitalization. Its assets on five continents are valued at more than 150 billion euros; its 2023 installed capacity was 62,883 MW; its power lines stretch 1.28 million km; and it employs more than 42,000 people.

Both companies claim leadership roles in the clean energy transition.

Avangrid has 8.7 GW of renewable capacity installed in 24 states and is a 50/50 partner in the first large-scale U.S. offshore wind farm, Vineyard Wind 1, now under construction. Iberdrola is pursuing a renewable portfolio totaling 100 GW.

The acquisition works out to $35.75/share, an increase from the original offer of $34.25. That represents an 11.4% premium over the closing price of Avangrid stock on March 6, the last unaffected trading day before Avangrid announced it had received Iberdrola’s unsolicited offer.

Avangrid said its board of directors unanimously approved the agreement.

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EEI Sues EPA over Power Plant Rules’ Carbon-capture Requirement

The Edison Electric Institute has joined the litigation against EPA’s power plant rules under Clean Air Act Section 111, filing its own petition to review the rules and intervening in existing suits. 

The agency had already been sued over the rules by a group of states and the National Rural Electric Cooperative Association, the latter of which has asked the court to stay implementation of the rule. (See Republican-led States Sue EPA over Power Plant Emissions Rule.) 

The rules imposed stricter emissions limits on existing coal plants and new natural gas plants. They identified carbon capture and storage as the best system of emission reduction (BSER) under the CAA. Coal plants intending to operate past 2039 will have until Jan. 1, 2032, to cut their emissions to a level based on a presumption that they will install a CCS system capable of capturing 90% of their emissions. (See EPA Power Plant Rules Squeeze Coal Plants; Existing Gas Plants Exempt.) 

EEI CEO Dan Brouillette said in a statement that the investor-owned utility trade group still supports EPA’s ability to regulate greenhouse gases under the CAA but opposes the use of CCS as the BSER. 

“We are intervening today to preserve our ability to defend, if needed, elements of the final 111 rules that are consistent with the ongoing clean energy transition and that do not create reliability impacts for customers,” Brouillette said. “At the same time, we are seeking judicial review of the agency’s determination that carbon capture and storage should be the basis for compliance with other portions of the 111 rules. EPA’s record and the docket do not support the agency’s finding that CCS is adequately demonstrated for broad deployment across our industry.” 

CCS is an emerging technology, and the rule’s implementation timelines do not align with its commercial reality, Brouillette said. No power plants are operating today that would meet the agency’s requirements for CCS. 

“Throughout the rulemaking process, we repeatedly raised concerns that CCS is not yet ready for full-scale, industrywide deployment, nor is there sufficient time to permit, finance and build the infrastructure needed for compliance by 2032,” he added. 

EEI said its members are investing in CCS and other technologies that can deliver power around the clock and without emissions, but it cannot bet the future on a technology that is not ready for industrywide deployment. 

The utility group’s concerns about CCS are not unique, with SPP and PJM both recently saying the technology was not ready. (See related story, SPP Shares Concerns over EPA’s GHG Rule.) 

In a statement this month, PJM noted that EPA had responded to concerns it brought up in joint comments filed with SPP, ERCOT and MISO before the rules came out, making some helpful improvements. However, the final rules’ reliance on CCS was still a concern. 

“The availability of CCS is highly dependent on local topology, such as salt caverns available to sequester carbon and the availability of a pipeline infrastructure to transport carbon emissions from individual generating plants to CCS sites potentially hundreds of miles away,” PJM said. “There is very little evidence, other than some limited CSS projects, that this technology and associated transportation infrastructure would be widely available throughout the country in time to meet the compliance deadlines under the [rules].” 

Advanced Energy United put out a statement urging the broader electricity industry against litigation in response to EEI’s petition for review. 

“With the Inflation Reduction Act at our backs, and clean energy the most affordable and reliable choice, it’s time for all of us to lean into the energy transition,” said CEO Heather O’Neill. “Dragging our feet and betting against America’s technological innovation will only drive up utility bills for consumers. The most cost-effective way to power our electric grid is by scaling up the use of the proven, clean and reliable technologies we already have.” 

Technologies like wind, solar, energy storage, geothermal, demand flexibility and efficiency are proven, clean alternatives to fossil-fueled power plants, United said. 

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FERC Denies PacifiCorp Formula Rate Change

FERC on May 21 rejected PacifiCorp’s request to include in its Open Access Transmission Tariff the interest it pays when refunding advance payments such as interconnection study deposits (ER24-1595). 

In a March 22 filing, PacifiCorp described the interest payments as “prudently incurred costs.” 

The company noted that FERC Order 2023 requires interest to be paid on refunds of interconnection study deposits, commercial readiness deposits and payments in lieu of site control. PacifiCorp said its Large Generator Interconnection Procedures also include that requirement. 

The deposits are refunded when an interconnection customer reaches commercial operation or withdraws from the interconnection queue, the company said. Interconnection study deposits are refunded after deducting study costs PacifiCorp paid for, while commercial readiness deposits are refunded less any withdrawal penalties owed. Site control deposits are fully refunded. 

PacifiCorp asked to include the interest payments for those refunds in its Annual Transmission Revenue Requirement that is part of the OATT. And in response to comments during a previous proceeding, the company said it would deduct from the interest expense the interest it earned while holding the deposits. 

“The interest expense is a legitimate and required cost for PacifiCorp to provide interconnection service,” the company said. 

The filing drew protests from Bonneville Power Administration and a group of customers comprising Utah Associated Municipal Power Systems, Utah Municipal Power Agency, and Deseret Generation and Transmission Cooperative. 

The Utah customers said PacifiCorp’s proposal would inappropriately shift costs from generators seeking interconnections to transmission customers. 

BPA said PacifiCorp hadn’t been clear on how it would determine the interest expense, or explained why it should have discretion in calculating its interest income on the deposits. 

BPA also argued that under a 2013 settlement that implemented a formula rate for PacifiCorp’s transmission service, single-issue rate filings related to the formula rate are prohibited. 

FERC rejected PacifiCorp’s proposed formula rate revision, saying the company had not shown that its plan to recover interest expense on the deposits was just and reasonable. 

“PacifiCorp has not demonstrated that its proposal would restrict the use of the deposit funds,” the commission wrote. “Although PacifiCorp represents that it currently puts the deposit funds in short-term, daily rate interest-bearing accounts, the record in this proceeding does not indicate that PacifiCorp is required to do so.” 

While not addressing all of the protesters’ objections, the commission said PacifiCorp hadn’t fully explained how it would calculate interest expense. 

According to its filing, PacifiCorp’s interest expense in 2023 amounted to $15.1 million, which was offset by $9.4 million in interest earned on the deposits, for a net interest expense of $5.7 million. The rate impact of that expense would be about 1%, according to the company, which noted that the interest expense would vary each year. 

PacifiCorp said it had tried to work with BPA and other customers on its interest-expense proposal. The company sent its proposed methodology to them in February and followed up with a conference call in March. 

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Strategy Offered for Success of Future West Coast OSW Sector

A new report outlines steps that could pave the way for a robust offshore wind industry on the West Coast, where there’s limited infrastructure to support it. 

Key actions suggested in Oceantic Network’s “Suppliers’ Guide to Success” include making investments in port and transmission infrastructure, structuring offtake awards to emphasize deliverability and following a steady, long-term procurement schedule. 

Oregon and particularly California have ambitious goals for this emissions-free source of power generation, but they will not be in the forefront of U.S. offshore wind construction because their projects will rely on floating wind turbine technology that still is being developed and tested. 

The report provides a chance for the West Coast to analyze the mixed record of first-wave offshore wind development on the East Coast and work to avoid pitfalls when development begins in earnest off the California and Oregon coasts, Oceantic said. 

The trade organization’s West Coast Supplier Council assisted with production of the report. 

It leads off by laying out some of the challenges — floating wind turbines have been installed only at smaller scale, and never at the depths present along parts of the U.S. West Coast.  

So, while early East Coast projects can turn to foreign suppliers and foreign expertise for their bottom-fixed turbines, that option is less promising for floating wind. 

Further, the report states, the near-to-midterm market potential for offshore wind on the West Coast is less than on the East Coast, where statutory goals are higher. 

Building a West Coast offshore wind industry requires a financially sustainable and scalable supply chain that can produce results at the right time and cost. A predictable and steady pipeline is essential to attracting the investment needed to make this happen. 

“We cannot repeat the experience of the East Coast, where a focus on least-cost offshore wind procurement yielded projects with business cases that were not resilient to macroeconomic change, [were] often delayed and, ultimately, proved to be undeliverable,” the authors write. 

They proceed to lay out problems and suggest solutions: 

Infrastructure Investment

The West Coast has a severe shortage of ports and transmission, the biggest hurdle to creating a viable floating wind industry.

A massive buildout of both is required, and it needs to start as soon as possible due to the long timelines to completion.  

The California Energy Commission’s analysis in its strategic plan of port functions to support offshore wind is a great first step, and the state needs to create a funding strategy for the Port of Humboldt and Port of Long Beach. The effort should be state-led and federally supported, with guidance from the offshore wind industry. 

CAISO’s draft 2023/24 Transmission Plan, which included a proposal to bring at least 1.6 GW of offshore wind power onto the grid in the North Coast, was a tremendous first step, but substantial further investment will be needed in that region. Reserving existing capacity for offshore wind in the Central Coast could reduce the major transmission investment that otherwise would be needed there. 

Offtake Award Criteria

Offshore wind offtake contracts should prioritize quality, timeliness and capacity rather than unrealistic price targets. 

Inflexible prices and a confluence of other factors resulted in the recent cancellation of 13.2 GW of offshore wind contracts on the East Coast, causing damaging ripple effects that still are manifesting across the nascent supply chain.  

The West Coast can learn from this, but it may encounter new hurdles because of the differences between new floating technology and relatively mature bottom-fixed technology. 

It should be recognized that initial projects will reflect the higher cost of establishing an ecosystem, and that their success will reduce the cost of subsequent projects. 

Bids submitted to state solicitations should be evaluated not just for price tags, but also for supply chain and infrastructure readiness, experience and credibility, and technology maturity. 

Procurement and Production

West Coast states should set up markets to encourage development of a local supply chain rather than simply specifying local content requirements. 

This is accomplished by the firm promise of a long and steady pipeline of work, which improves return on investment, provides a clear line of sight for workforce development needs and allows for more stable pricing. 

(The desire for clear market signals was aired this month at the Pacific Offshore Wind Summit in Sacramento, during which developers called on California to set an interim goal of 10 GW installed by 2035 on the way to its existing goal of 25 GW by 2045. See Developers Urge New Target for Pacific Offshore Wind.) 

Policymakers should focus supply chain development in sectors where the West Coast could have a competitive advantage in attracting new investment, rather than on components that are readily available on the world market. 

Global supply chains already exist for blades, nacelles, towers and cables, for example. The West Coast could do better by targeting components and processes specific to floating wind for which there is not yet a robust supply chain, such as floating platform assembly and turbine integration, vessel construction or retrofitting, and manufacture of mooring systems. 

Finally, Pacific states should coordinate and collaborate regionally to use their existing industrial strengths. 

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MISO Braces for Hot Summer, Potential 130-GW Peak

MISO said it’s expecting a hot summer footprintwide and while it should be able to survive load peaks into the 120-GW level, the system could be at the brink if a scorching day produces demand near 130 GW.  

Per usual, MISO said the bulk of the danger lies in July. MISO said it likely will encounter a 122.6-GW peak sometime that month but doesn’t rule out a high-demand forecast of 129.3 GW. That level of demand would break all load records, outstrip its 123.8 GW of cleared, accredited capacity and force it to declare an emergency to access its approximately 15-GW store of operating reserves and load-modifying resources.  

In June, MISO said load could crest at an expected 115 GW or climb near 122 GW in a high-demand scenario. By August, MISO expects an almost-120-GW peak load under normal conditions, or as much as 126 GW.  

MISO’s all-time summer peak of 127 GW occurred July 20, 2011. Last year, MISO expected to eclipse that record twice during late August and early September heat waves that produced temperatures exceeding 95 degrees in northern portions of the footprint. MISO rounded out summer with a 125-GW peak Aug. 23. (See MISO: Could Have Employed Wait-and-see Approach for August Emergency.)  

During a May 21 summer readiness workshop with stakeholders, MISO resource adequacy engineer John DiBasilio said while MISO should have sufficient capacity under normal operating conditions, it’s likely to enact emergency procedures if demand intensifies this summer.  

The RTO estimates it has a 4.6-GW capacity surplus beyond its 136-GW planning reserve margin requirement heading into summer from excess capacity offered into the auction and from members’ fixed resource adequacy plans.  

MISO’s primary weather forecast vendor, data analytics and technology company, DTN, has predicted “above-normal to well-above-normal” average temperatures May through September.  

The RTO noted that the National Oceanic and Atmospheric Administration is projecting above-normal temperatures across the country June through August. MISO also said it expects precipitation this summer between near normal and slightly above normal.  

MISO in-house meteorologists Brett Edwards and Adam Simkowski said it doesn’t seem that the RTO can use last summer, which held nearly normal average temperatures in MISO Midwest, as a reference for the upcoming summer. They said more appropriate reference points include summers where load topped 120 GW systemwide and more than 30 GW in MISO South.

Edwards said all data points to a very warm summer, and MISO expects “pervasive heat across pretty much the entire continental U.S.”  

The RTO anticipates a developing La Niña weather pattern contributing to hotter conditions in July and August.  

MISO also said there’s a good chance heat could emanate from the eastern U.S. this summer, affecting PJM’s ability to export to MISO during heat waves.  

“That’s something we’re going to be watching closely as the entire Eastern Interconnect heats up,” Simkowski said. 

“Our teams are constantly working to identify and manage the areas of growing risk within our region and throughout our industry,” Executive Director of Market Operations JT Smith said in a press release.  

Finally, MISO said while it’s expecting solar penetration to increase to 6 GW of in-service capacity this summer, it’s also keeping an eye on the potential for wildfire smoke drifting from Canada to stifle a percentage of output. MISO has been routinely breaking its own solar records monthly as developers complete solar farms. Currently, MISO’s solar arrays are briefly capable of about 5-GW peaks. 

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MISO Says Risk Driving It to LMR Reorganization, Stronger Requirements

CARMEL, Ind. — MISO said with resource adequacy risks at its doorstep, it may need to place tougher requirements on its load-modifying resources and devise new, nonemergency means of using the load offsets that cannot meet new performance standards. 

During a May 22 Resource Adequacy Subcommittee, MISO’s Neil Shah said he expects the grid operator will use LMRs differently from how they’ve been used in the past to aid reliable grid operations. He said the RTO plans to “redefine the LMR product” and “remap” its load management that can’t meet qualifications into potentially new resource modes that can be used during nonemergency conditions. The LMR category going forward might contain only those resources that can be ready within 30 minutes, staff suggested.  

Shah said MISO still plans to draw on “all types of resources both on the demand side and the supply side.” He said reserves that cannot meet new LMR standards will still be used to aid reliability in its markets, albeit differently.

“We see the grid is transforming at a rapid pace. We see the risk patten changing,” Shah said, adding that the LMR construct must change with it. 

Shah said that since 2007, LMRs have been used strictly during emergency conditions. LMRs are out-of-market voluntary response resources, Shah said, which are “guaranteed capacity market payment regardless of actual performance.” He said when MISO begins issuing capacity advisories and emergency alerts, LMRs sometimes will self-schedule reductions, and because MISO isn’t aware of the load offsets until after they occur, it complicates the ability to estimate needs before peak hours.  

Shah said MISO plans to present its new approach to LMRs at its Resource Adequacy Subcommittee’s July meeting. 

Sustainable FERC Project’s Natalie McIntire asked that MISO find ways to “maximize” the resources that might not be able to make the LMR cut. 

Michigan Public Power Agency’s Tom Weeks said it might be simpler for MISO to remove the requirement that it be in an emergency before LMRs can be accessed. He also said he wished MISO would “weed out bad actor” LMRs that don’t provide load reductions as promised.  

“Instead of using a scalpel to correct the issue, MISO is pulling out a bone saw and doing Civil War-like medicine to cut off a limb,” Weeks said.  

Shah acknowledged MISO needs better-defined auditing and monitoring standards for its LMRs. He repeated that MISO is open to creating a new market product to make sure participants can make use of longer-lead demand response offerings. However, MISO’s Zak Joundi later said MISO prefers to route nonemergency LMRs into one of its existing participation categories. 

Shah said MISO can examine its current Demand Response Resource Type I participation model to make sure it’s still useful to participants. If not, the RTO can make tweaks, he said.  

“It’s MISO’s job to make sure that it can make use of the resources available to it,” WPPI Energy’s Steve Leovy said. He argued that MISO shouldn’t need strictly 30-minute LMRs and that it should activate emergencies a few hours beforehand when it requires demand response. MISO should expect some level of inefficiencies during emergencies, he said.  

“We’re talking a few times a year during severe conditions … to keep the system intact,” Leovy said.  

“Managing a 15-state footprint is incredibly complicated. When you get into real-time emergency conditions, more simplicity is needed in the design,” Executive Director of Market Operations JT Smith said.  

Smith said the problem of when LMRs could deliver wasn’t present 10 years ago because MISO had ample resources. Now, he said MISO’s “entire reserve fleet is sitting behind an emergency call.”  

MISO initially was slated to use summer to design a new capacity accreditation for its LMRs; however, it said it was persuaded by stakeholders to pause on remodeling accreditation in favor of redrafting the LMR rulebook.  

LMRs were not included in MISO’s recent filing to implement a new capacity accreditation that would accredit resources based on their projected availability and historical performance during periods of high system risk. (See Stakeholders Deliver Negative Reactions to Proposed MISO Capacity Accreditation at FERC.)  

Before it announced the pivot, MISO said it considered splitting LMRs into emergency and nonemergency resources, giving 100% capacity credit to more nimble, emergency LMRs and apply a sliding scale to nonemergency LMRs that would reduce capacity credits as response times rise.