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November 14, 2024

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SPP, SEEM Woo Entergy Regulators at NARUC

LOUISVILLE, Ky. — Amid clashes with MISO on regional transmission planning and cost allocation, this week’s Entergy Regional State Committee meeting featured introductions to SPP’s and the Southeastern Energy Exchange Market’s (SEEM) workings.

SPP leadership and a SEEM delegate were on-hand to share the members’ experiences during the committee’s Tuesday meeting, held during the National Association of Regulatory Utility Commissioners’ annual meeting.

Louisiana regulator Eric Skrmetta, who in a fiery speech last month suggested forcing Entergy Louisiana to exit MISO for either SPP or SEEM, stood at the back of the room during the meeting. He didn’t comment. (See La. Regulators Threaten MISO Departure over Tx Costs.)

Former Kentucky Public Service Commissioner Talina Mathews, freshly hired as SPP’s director of state regulatory policy, described the RTOs planning process and cost allocation. She said the footprint’s regulators have control over cost allocation decisions, a “unique” setup among RTOs.

“Decisions are not made quickly or lightly,” Mathews said.

“I know that SPP takes their relationships with regulators very seriously,” Mississippi Public Service Commissioner Brandon Presley said.

Presley said SPP ensures their regulators have a “central” role, given they take the heat for system outages and missed forecasts. He likened MISO’s relationships with state commissioners to a spouse that’s only remembered at tax time. He also mentioned regulators being put through MISO’s “hellacious” stakeholder process.

“It just seems a big cultural difference,” Presley said.

Noel Black with Southern Co., one of SEEM’s founding members, told regulators that the market’s aim is to “get out of the way of the bilateral market.” He lauded his exchange’s simple market structure and minimal “disruption” to regulators.

FERC on Monday approved requests for the zero-cost transmission service that will used to deliver SEEM’s energy transactions. The market became effective “by operation of law” in October. (See SEEM to Move Ahead, Minus FERC Approval.)

Both the Mississippi and Louisiana commissions have hinted they would pull their utilities out of MISO if the RTO shares the bill from major Midwest transmission expansion with their South region. (See Mississippi PSC Audit Questions MISO Membership.)

Aubrey Johnson, MISO’s executive director of system planning, said regional transmission planning is “needed to accommodate the current and future resource fleet shift.”

MISO is currently studying about 10 Midwestern projects for possible approval in March. Johnson said after the first tranche of those projects is approved, the grid operator will turn its attention to studying the South’s regional needs. He said the first projects would likely be ready for approval in 2023.

Johnson said a proposed footprint-wide postage stamp rate isn’t realistic based on MISO’s current hourglass configuration, where the Midwest and South are constricted by the subregional transfer limit. He also said MISO South’s resistance to cost sharing played a role in the RTO’s current decision against a footprint-wide allocation. (See MISO Hopes Bifurcated MVP Cost Allocation Will be Temporary.)

Texas Public Utility Commission economist Werner Roth said the state supports a bifurcated cost allocation between the Midwest and South.

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California Needs Its Last Nuclear Plant, Study Finds

A study published this week by researchers at Stanford University and the Massachusetts Institute of Technology found that California would reap significant financial and environmental benefits by keeping its last nuclear power plant operating for at least another decade.

The authors of the paper, published on Stanford’s website, cited grid reliability during the state’s statutorily mandated switch to 100% clean power by 2045 as a prime argument for operating Pacific Gas and Electric’s (NYSE:PCG) Diablo Canyon Power Plant beyond its scheduled retirement date in 2025. The state has struggled with capacity shortfalls in the past two summers, including rolling blackouts in August 2020, and anticipates up to a 3,000-MW shortfall next summer.

“It’s important to remember that this power plant produces 15% of California’s carbon-free electricity today and is responsible for 8% of the state’s total electrical production,” co-author and MIT professor John Lienhard said in a question-and-answer session with MIT News. “In other words, Diablo Canyon is a very large factor in California’s decarbonization. When or if this plant goes offline, the near-term outcome is likely to be increased reliance on natural gas to produce electricity, meaning a rise in California’s carbon emissions.”

Postponing the plant’s retirement to 2035 would reduce the state’s reliance on natural gas, cut carbon-emissions from electricity generation by 10% compared with 2017 levels, and save ratepayers $2.6 billion in electric costs, the researchers found. Operating the plant until 2045 could save up to $21 billion and “spare 90,000 acres of land use from energy production,” by eliminating the need for 18 GW of solar arrays, they wrote.

Using energy from the nuclear plant on the Central California coast to desalinate ocean water or produce hydrogen would be added benefits, the study found.

PG&E said it would continue working toward the plant’s retirement unless ordered to do otherwise.

“We are aware of the independent study performed by Stanford and MIT. PG&E is committed to California’s clean energy future, and as a regulated utility, we are required to follow the energy policies of the state,” it said in a statement to RTO Insider. “The state has made clear its position on nuclear energy, and the plan to retire Diablo Canyon Power Plant has been approved by the California Public Utilities Commission and the state legislature. Our focus therefore remains on safely and reliably operating the plant until the end of its NRC licenses, which expire in 2024 and 2025.”

The California Public Utilities Commission, which approved the plant’s retirement, said continuing to operate it would require costly upgrades and federal approval.

“The CPUC has not been briefed on the report, and no proposal has been made directly to the CPUC to revisit the 2018 decision to allow the plant to close down after its federal licenses expire in 2024 and 2025,” CPUC Spokesperson Terrie Prosper said in an email.

“To continue operating Diablo Canyon beyond 2025 would have required a license renewal from the federal Nuclear Regulatory Commission,” Prosper said. “As part of the renewal PG&E would need to make seismic upgrades. Those upgrades combined with required changes to the cooling systems to comply with state and federal water quality laws would likely cost more than $1 billion.”

The authors of the study said their research had concluded the plant, which sits near fault lines, could withstand severe earthquakes, tsunamis and other natural disasters without upgrades.

“We reviewed the latest NRC documentation on Diablo Canyon’s seismic risk,” the paper said. “This is summarized in a very recent NRC letter, which concludes that PG&E has demonstrated the plant’s capacity to withstand the types of seismic hazards re-evaluated after Fukushima. No further actions have been required by the NRC.”

The authors also cited 2014 estimates by Bechtel Power Corp. that the cooling system fixes could be done for as little as $456 million.

The study appeared to bolster the case of a group called Californians for Green Nuclear Power (CGNP), which has argued in recent years that extending Diablo Canyon’s operation is the most cost-effective option for supplying the state’s power needs and that nuclear power is more dependable than wind and solar, making it an essential provider of baseload capacity.

FERC dismissed a CGNP complaint in March after NERC, PG&E and others argued against the group’s challenge. CGNP’s complaint claimed, in part, that the closure of Diablo Canyon violated NERC and WECC reliability standards and contended the Electric Reliability Organization had failed to exercise appropriate oversight in the matter. (See FERC Dismisses Calif. Nuclear Complaint and NERC Blasts Calif. Nuclear Group’s Complaint.)

Diablo Canyon, which went online in 1985, consists of two nuclear reactors with a nameplate capacity of 2.3 GW. In 2019, it produced nearly 16.2 TWh of electricity accounting for about 10% of in-state generation, according to the U.S. Energy Information Administration.

Its closure has been in the works since 2016, when PG&E asked the CPUC to approve a plan, created in partnership with environmental, labor and anti-nuclear advocacy groups, to begin shutting down the plant in phases between 2024 and 2025. The utility intends to replace the aging nuclear plant with wind, solar and other carbon-free resources as a means of meeting renewable energy goals set by California’s legislature in 2018 under Senate Bill 100.

Lienhard told the university news service that he hoped the new study would cause PG&E and others to revisit and reverse the decision to retire Diablo Canyon.

“We believe that this report gives the relevant stakeholders and policymakers a lot of information about options and value associated with keeping the plant running, and about how California could benefit from clean water and clean power generated at Diablo Canyon,” he said.

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NARUC Panelists Push for Software Documentation

Panelists at the National Association of Regulated Utility Commissioners’ annual meeting on Tuesday said the concept of a software bill of materials (SBOM) is attractive for the utility industry, but they warned that challenges remain for its implementation.

The SBOM idea has been getting more attention from the industry since its inclusion in President Biden’s Executive Order 14028, issued in May in response to the ransomware attack against Colonial Pipeline. (See Biden Directs Federal Cybersecurity Overhaul.) Biden’s order included a number of mandates, mostly aimed at federal agencies and their contractors, that were intended to improve cybersecurity preparedness in both the public and private sectors.

Participants in a panel on cyber supply chain security admitted to some surprise at the speed with which the SBOM concept has entered the popular lexicon.

“This has been a known idea for quite a while, but it’s really received a lot of traction lately. I don’t think two years ago I would have predicted we’d be in a conference talking about SBOMs and HBOMs [hardware bill of materials],” said Brian Barrios, vice president of cybersecurity and information technology compliance at Southern California Edison.

Tom-Deitrich-Judy-Jagdmann-(NARUC)-Content.jpgTom Deitrich, Itron (left) and Judith Jagdmann, Virginia State Corporation Commission | NARUC

The impetus behind the SBOM is similar to that of the HBOM, which came earlier. With HBOMs, the manufacturer provides a list of all the physical materials that went into a hardware product and where they came from; SBOMs are not physical products, but they are similarly composed of various subprograms and other components that, unlike in the 1980s and 1990s, are almost always not created by a single programmer or even a single company.

“If you’re a coder these days, a lot of times you’re spending energy taking code from other places and pulling it all together. You’re not really writing a ton of custom code yourself,” Barrios said. “If I’m dealing with millions of lines of code in a software product, [understanding] where did it all come from [and] who ultimately wrote that is an extremely complex question.”

But implementing SBOMs in the utility sector could be a challenge. Tom Deitrich, CEO of Itron, a developer of technology for the energy and water industries, pointed out that while physical components can be traced back to their origin or at least the previous step in the supply chain, determining the provenance of software code is much more difficult.

In the case of last year’s attack on the SolarWinds Orion network management platform, an attacker managed to infiltrate the update channel for the widely used software and insert its own code into patches that went out to thousands of users. How could the company produce a useful SBOM when it didn’t even know that the malicious code was in the product?

“A situation like SolarWinds is a place where some bad software got integrated with some good software,” Deitrich said. “If you were looking at a bill of materials only, you may not have found it. If you were scanning the binaries to truly understand what’s inside of it, you could have detected it.”

Matt-Wakefield-(NARUC)-FI.jpgMatt Wakefield, EPRI | NARUC

Matt Wakefield, director of information, communication and cybersecurity research at the Electric Power Research Institute, pointed out that Biden’s order focused on the IT space, but the greatest concern for many utilities is with operational technology, where software is more specialized and documentation may be scarce compared to more widely used products like SolarWinds.

“There’s much less maturity in [SBOMs] and [HBOMs] in the OT space and the technologies that we use to operate the grid, so we’re kind of a step behind,” Wakefield said.

To speed the process along, some observers have proposed using software to analyze code and determine its origins. However, like many software projects, putting this idea into practice has proven more difficult than anticipated.

“I read an article earlier this year that 2021 was going to be the year of the automated [SBOM],” Wakefield said. “I haven’t seen that occur yet.”

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NYISO Shares Order 2222 Response with Stakeholders

NYISO on Monday presented stakeholders a subset of draft responses to FERC’s data request regarding its Order 2222 compliance.

NYISO’s response must explain how its distributed energy resource (DER) participation model complies with Order 2222 and propose additional tariff revisions, as necessary. The ISO has not identified tariff revisions required in order to respond to the commission thus far, said Harris Eisenhardt, market design specialist.

The commission on Oct. 1 gave CAISO and NYISO 30 days to explain details of the treatment of distributed energy resources and aggregations described in their Order 2222 compliance filings. It later granted NYISO’s request for an extension until Nov. 19 (ER21-2460). (See FERC Asks Details from CAISO, NYISO on Order 2222 Compliance.)

Market Rules

Most of the presentation focused on coordination between the ISO, aggregator and distribution utility, particularly the role of the utility.

One question concerned rules to prevent aggregators from receiving compensation twice for the same services (e.g., in an ISO market and a state program).

The commission asked, “What role, if any, will the distribution utility play in helping NYISO verify that an aggregator is not providing the same or substantially similar service in the NYISO-administered markets?”

As previously stated in its filing, Eisenhardt said, NYISO plans to rely on aggregators’ self-attestations that their DERs are not double dipping.

One stakeholder said that some answers for the attestations may require a level of operational detail that might not necessarily be known or could still be in flux at the time of enrollment and asked whether it would be necessary to amend the attestation if circumstances changed.

Eisenhardt said there will be a document to provide guidance on which programs are compatible with specific NYISO services.

“It is the expectation of NYISO that the aggregator would be able to use that during enrollment to make an informed decision on what the planned operation of the aggregation and individual DER would be and that it would not conflict or that they do not believe it would conflict with the services as laid out in that guidance document,” Eisenhardt said. “If there were modifications following the attestation, NYISO would expect there would be an amendment and would be informed of those changes as needed.”

Another market participant said that while Order 2222 directs that the utility should have up to 60 days to complete evaluation of whether there would be any safety or reliability impacts to its distribution system, it did not specify what happens at the end of the 60-day window if there are issues that take longer to evaluate.

NYISO has dispute resolution procedures in its tariff already that could be reset for Order 2222 compliance, if necessary, NYISO senior attorney Greg Campbell said.

“We’ll see if the commission would like us to enhance those. I think that they are sufficient as is, but more specifically, NYISO will be the one making the final decision on whether a DER can participate in its markets,” Campbell said. “That decision will be informed by information provided by the utilities as well as by the aggregator and by others, so if the aggregator feels as though it needs to, it can invoke those dispute resolution procedures in section 11 of the NYISO services tariff.”

Implementation Details

One stakeholder asked how transmission node mapping will be made available to market participants.

The ISO plans to put out a list of all the transmission nodes for the New York Control Area, said Michael Ferrari, market design specialist. Developers will have to work with the transmission owner to find out how nodes map up.

“From the NYISO’s perspective, we were identifying the points on the transmission system, but the mapping from distribution to transmission will have to go through the transmission owner, so presumably the question of whether or not there will be some tool available will be one that needs to be put to the individual distribution utilities,” Ferrari said.

If the commission authorizes the ISO and the distribution utilities to take 90 days to evaluate changes to a DER aggregation, — which is the 30 days the commission has already authorized the ISO to take to evaluate changes and then a 60-day evaluation by the distribution utility — NYISO is going to have to change its timing for updating the transmission node list, Campbell said.

“We previously said we would provide at least 90 days’ notice of transmission node changes prior to the beginning of the capability year. Clearly, if an aggregator needs to notify the ISO 90 days before they can take effect, we need to bump up the timing of publishing transmission node changes,” Campbell said. “One hundred fifty days prior would provide sufficient lead time.”

The ISO expects to release the number of nodes for deployment by the end of this year or the first quarter of next year, and DER deployment is still anticipated for the fourth quarter of next year, Ferrari said.

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P3 Seeks 3rd Circuit Review of PJM MOPR

The PJM Power Providers Group (P3) on Friday petitioned the 3rd U.S. Circuit Court of Appeals to review PJM’s narrowed minimum offer price rule (MOPR) after FERC deadlocked on issuing a decision on the RTO’s proposal.

PJM’s narrowed MOPR automatically took effect Sept. 29 because the commission’s four members were evenly divided over it. The rule now only applies to resources connected to the exercise of buyer-side market power or those receiving state subsidies conditioned on clearing the RTO’s capacity auction. (See FERC Deadlock Allows Revised PJM MOPR.)

The America’s Water Infrastructure Act, signed into law by President Donald Trump in October 2018, added a provision to Section 205 of the Federal Power Act to allow for judicial review if FERC fails to act on the merits of a rehearing request within 30 days because the commissioners are divided 2-2. P3 and other stakeholders had filed rehearing requests last month (ER21-2582).

P3 said the 3rd Circuit, based in Philadelphia, is the “most appropriate venue for judicial review” because of its proximity to PJM, based in Valley Forge, Pa. P3 also said the court has the “most direct experience” regarding FERC’s prior orders on the MOPR and its “interaction with state subsidies designed to promote preferred resources.”

The water act also required each commissioner to issue a statement explaining how they would have voted and why if the commission fails to act.

FERC Chair Glick and Commissioner Allison Clements, both Democrats, said the commission’s past decision on PJM’s expanded MOPR “created a Byzantine system of administrative pricing — unprecedented in both scope and complexity — that would have imposed on consumers billions of dollars in unjustified costs.” (See ‘Good Riddance’ to Old PJM MOPR, Glick Says.)

Republican Commissioners James Danly and Mark Christie opposed the proposal, with Danly calling it “irredeemably inconsistent” with the FPA.

The commission would be unable to order a rehearing if the 2-2 deadlock continues. D.C. Public Service Commission Chairman Willie Phillips’ nomination for FERC’s vacant fifth seat is pending before the full Senate for a final vote. (See Senate Energy Committee Advances Phillips.) Phillips may decide to recuse himself from the MOPR proceeding, however, because the D.C. PSC filed comments supporting PJM’s proposal.

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NARUC Calls for Regulators to Work with Military on Resilience

With the U.S. Department of Defense increasingly reliant on civilian electric infrastructure, state utility regulators must be prepared to work with utilities and the military to safeguard national security, according to a new report from the National Association of Regulatory Utility Commissioners (NARUC).

The Regulatory Considerations for Utility Investments in Defense Energy Resilience report, published last week, was prompted by the transformations over the past few decades in both the mission of the U.S. military and in its relationship to the national power grid. Whereas the military previously did its job largely outside the continental United States, the power of digital communications has allowed more and more missions to be conducted from within the nation’s borders — most visibly through the use of remotely controlled drones for intelligence and combat, but also with cybersecurity and signals intelligence.

Shifting these tasks to the continental U.S. meant the electricity needs of domestic military bases kept increasing, and the pre-World War II model of facilities managing their own power needs could not keep up with demand. Fortunately for DOD, by this point the civilian power grid had grown capable enough that bases could tap into commercial utilities.

Similar trends were underway regarding other utilities. According to figures from the Government Accountability Office (GAO), today more than 98% of military facilities rely on the civilian power grid, 98% depend on commercial telecom providers, 87% on the commercial natural gas system and 76% on community water. More than 300 major military and national security installations are served by investor-owned electric utilities, according to Edison Electric Institute, with additional bases served by rural coops and municipal utilities.

Bases No Longer Isolated from Outages

But the integration with the national grid and the end of electric self-sufficiency comes at a price of increased vulnerability to outages. NARUC observed that in fiscal year 2019, DOD “experienced 2,572 unplanned utility outages, of which 542 lasted eight hours or longer, including at installations with missions that cannot tolerate interruptions.”

Percentage-of-Defense-Department-installation-reliance-(NARUC)-Content.jpgPercentage of Defense Department installation reliance on community infrastructure, as calculated by the U.S. Government Accountability Office. | NARUC

Concerning electric outages specifically, the report singled out major events such as hurricanes Irma and Maria in 2017 and Hurricane Michael in 2018, all of which “severely impacted nearby DOD installations and operations” in Florida and the Caribbean. In addition, Superstorm Sandy in 2012 demonstrated a different kind of vulnerability, when response efforts by the National Guard and other military units were crippled by power outages at their bases.

Military installations are also vulnerable to outages from cyberattacks against commercial utilities; such attacks may not be specifically aimed at disrupting defense operations, or in the case of nation-state actors like Russia and China, may be intended as an indirect threat against a rival’s military. Additional dangers come from infrastructure interdependencies; disruptions in the natural gas system can cause failures in the electric grid, as occurred during February’s winter storms in Texas and the Midwest.

The military’s reliance on power from commercial utilities puts pressure on those utilities’ regulators. Not only do they need to work on behalf of ratepayers in their states, but they also must be mindful that their decisions do not jeopardize the security of the U.S.

Within DOD, the Office of the Secretary of Defense handles overall energy policy regarding military installations, but the department has “multiple levels of energy governance and responsibility,” according to NARUC. These include personnel within each branch of the military and staff at the installations themselves that may work with regulators. The report advises regulators to “be mindful of the level of DOD bureaucracy with which they are interacting” and the type of influence that each level holds.

Role of Regulators Still Undefined

Overall, the report acknowledged that the role of state utility commissions in supporting the resilience of military installations “remains nascent,” and predicted that regulators will need to “proactively engage with issues related to defense energy resilience, or … increasingly see issues related to defense energy resilience integrated into their normal course of business.”

Questions that regulators may have to address include who pays for investments related to defense energy resilience: Should it come exclusively from the DOD or other federal programs, or should ratepayers foot part of the bill, since uninterrupted national security operations is an obvious public good? How might regulators calculate the benefits of the needed investments in order to sell them to a skeptical public? Should ratepayers support investments in cybersecurity intended to benefit the military, if such investments benefit the greater public as well?

These questions may be overwhelming for regulators who are still grappling with the idea that their decisions impact the nation’s military readiness, and the report noted that some commissions may wish to wait and see how existing government programs develop before stepping into the debate. But regulators may also want to “proactively define the practices and processes” for utilities’ collaborations with the military.

NARUC provided some steps that regulators could take to engage with the topic of defense energy resilience. First, commissions may identify military installations in their state that might rely on regulated utilities, and work with DOD representatives to identify energy resilience projects with which the commission might need to engage.

Regulators can also work with the military on joint energy resilience metrics, value of resilience investigations, and investigate defense energy-related cybersecurity investments. Finally, secure communications frameworks should be established so that sensitive materials can be discussed without fear of malicious eavesdroppers.

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US Governors: States More Ambitious, Faster on Climate Action

To the U.N., they are “subnationals” — states and provinces that have committed to climate action more dramatic than the nations of which they are parts.

But speaking at the U.N. Climate Change Conference (COP26) on Monday, Washington Gov. Jay Inslee said the leaders of the 68 states and provinces who met Sunday in Glasgow, Scotland, are calling themselves “supernationals.”

“It’s states and provinces around the world that are advancing this cause that is more ambitious than our nation states, faster than our nation states, more comprehensive than our nation states and more flexible than our nation states,” Inslee said. “So, whatever comes out of the COP, we will beat.”

Inslee was one of four U.S. governors speaking at a press conference to highlight the work of the U.S. Climate Alliance, a bipartisan group of governors from 24 states and Puerto Rico, many of whom have committed to net-zero carbon emissions or similar deep cuts by 2050. He was joined by Oregon Gov. Kate Brown, Hawaii Gov. David Ige of and Illinois Gov. JB Pritzker, all Democrats.

Climate Alliance Accomplishments

On Sunday, the Climate Alliance released a summary of the actions its members have taken since the group was formed in 2017 to counter President Donald Trump’s decision to withdraw from the Paris Agreement. The alliance represents 62% of U.S. GDP, 56% of the U.S. population and 43% of U.S. emissions.

The alliance has identified eight priority policy areas: power; buildings; industry; transportation; just transition and equity; resilience; natural and working lands; and the social cost of greenhouse gases.

Of its 25 members, all but a handful have adopted, or are in the process of adopting, renewable portfolio standards, electric utility energy efficiency standards, resilience or adaptation plans, and 100% clean electricity goals.

In contrast, fewer than 10 have taken action on addressing methane from oil and gas, landfill, and agricultural sources or clean-truck standards. Only two, Washington and Colorado, have acted on building performance standards, and only five (California, Colorado, Massachusetts, Washington and Oregon) have moved on addressing emissions from industrial sources.

California has adopted all but one of 22 major actions highlighted by the alliance, followed closely by Colorado, Maryland, Virginia, New York, Rhode Island and Washington.

The group noted that several states have committed to 100% net-zero operating emissions for new construction beginning in 2030; 100% zero-emission new light-duty vehicle sales by 2035; implementation of a low-carbon fuel standard and conserving at least 30% of land and coastal waters by 2030.

“The climate threat knows no borders, and when we share solutions and expertise — not just with one another in the alliance, but also with other like-minded subnational leaders around the world — we can truly turn the tide,” said Taryn Finnessey, the alliance’s acting executive director and policy director.

Washington: Cap and Invest

At Monday’s press conference, Inslee highlighted Washington’s cap-and-invest program, which he signed into law in May. (See Wash. Cap-and-trade, LCFS Tied to Transportation Package.) The program, to be launched by 2023, will cap emissions in the state and then auction or allocate allowances to major emitters, such as fuel suppliers, industrial sources and electricity generators.

The law’s environmental justice provisions will ensure that 40% of the money from the program will be invested in “inordinately impacted communities, BIPOC communities,” Inslee said, using the term for Black, indigenous and people of color. “It is very much targeted to the people who have been swallowing and breathing this pollution for so long.”

The Climate Alliance includes Republican governors, such as Larry Hogan of Maryland. Still, when challenged by a reporter on why only Democratic governors were speaking at the event, Inslee said that, in general, Republicans “see [climate action] as negative for economic development. It is absolutely the opposite. The best possible economic development strategy for any state or nation right now is to seize the moment to steal the markets from China for clean energy. That’s our destiny; we ought to fulfill it.”

Oregon: Environmental Justice at the Forefront

Gov. Brown echoed Inslee. After reeling off a list of extreme weather events and wildfires that have hammered Oregon since she took office in 2015, she insisted that “we can tackle climate change and grow our economy at the same time. These goals are not mutually exclusive.”

Oregon has set 2040 as the target date for decarbonizing its electricity system. In 2020, Brown ordered state agencies to set caps on climate pollution for sectors like manufacturing, increase energy-efficiency standards for buildings and appliances, and create a statewide plan for electric vehicle charging infrastructure.

Brown also stressed that the programs being developed have environmental justice “at the forefront. … We all know our communities of color, our low-income communities and our rural communities are disproportionately impacted by these climate change events, so we are working very hard to disrupt that.”

For example, the state offers rebates for both new and used EVs so that the “most vulnerable Oregonians have access to these technologies,” Brown said.

Hawaii: ‘Net-zero is not Good Enough’

Battered by hurricanes and “rain bombs,” like the one in 2018 that deluged Kauai with close to 50 inches of rain in 24 hours, Hawaii is the proverbial “canary in the coal mine,” Gov. Ige said.

“We know 2 degrees is not sufficient; we are driving for 1.5 degrees Celsius,” Ige said, referring to the limit the U.N. has set for global warming.

Hawaii was the first state to commit to 100% clean energy in 2015, he said. “We didn’t know exactly how the technologies would play in and specifically how they would be utilized, but we were clear about where we needed to go, and that was the transition from fossil fuels to clean, renewable energy,” he said. “We know it’s the same as we race to eliminate emissions. We know that net-zero is not good enough. In 2018, the state of Hawaii committed to a net-negative goal by 2045 or as soon as practical.”

The state is tackling emissions not only from cars, but from aviation and marine transportation, he said. “We are preparing for electric planes for inter-island flights and sustainable aviation fuels for longer flights. We’re looking at switching our inter-island shipping to locally sustainable biofuels and hydrogen to power our medium- and heavy-duty vehicles and equipment for longer distance transportation.”

Illinois: A Focus on Jobs

Gov. Pritzker signed the state’s Climate and Equitable Jobs Act in September, making Illinois the first Midwestern state to commit to 100% clean energy by 2050. The law phases out private coal- and oil-fired generation by 2030 and all coal and natural gas by 2045. It also doubles state funding for renewables, making it clear that the state is serious about creating green jobs and building a green economy, Pritzker said. (See Illinois Senate Passes Landmark Energy Transition Act.)

And, he said, the law passed with at least some bipartisan support. “I think what they shared in common, the [Republicans] who voted with us, was a real focus on jobs. … This is about economic development as much as it is about saving our planet.”

Pritzker was the only one of the four governors in Glasgow who talked up the importance of nuclear as a source of low-cost clean power and a “bridge to a zero-carbon future.”

Illinois has the most nuclear reactors (11) and the most nuclear generating capacity (11.6 GW) of any state, according to the Energy Information Administration. Nuclear was responsible for 54% of its in-state generation in 2019, EIA says.

But Illinois is also working hard to become a hub for EV manufacturing, drawing electric truck and bus manufacturers like Rivian and Lion Electric, along with the parts and component manufacturers that supply them, Pritzker said. “We’re fostering an energy sector that reflects the population that it serves, with investments in workforce hubs, a path to prosperity for minority contractors and Illinoisans living in the environmental justice communities,” he said.

While describing the law as “the most significant step that Illinois has taken in a generation toward a reliable, renewable, affordable, clean energy future,” Pritzker also said, “There is so much more to. Everything that can be done, must be done.”

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Edison Electric Institute and Biden Admin Work Together at COP26

The U.N. Climate Change Conference (COP26) in Glasgow, Scotland, continues this week with an impetus that U.S. National Climate Advisor Gina McCarthy, executives from several U.S. utilities and the Edison Electric Institute agreed was not always clear at previous global climate conferences: a cohesive U.S. mission.

“We were so impressed not only at EEI, but … all of our companies were impressed by how quickly this administration started leading from Day 1,” Pedro Pizarro, CEO of Edison International (NYSE:EIX) and vice chairman of EEI, said during a discussion session Friday sponsored by EEI and held at the State Department’s U.S. Center at COP26.

“In some ways we are a small player relative to the global community that is here, but all of us have our part to play in this,” Pizarro said.

He compared the challenge of dealing with climate change to the successful effort by medical scientists and policymakers around the world to develop a COVID-19 vaccine and make it available. “COVID was an existential crisis. This is another existential crisis.”

McCarthy explained the administration’s objective this way: “I want the world to know that the United States is back. I want the world to know that clean energy is not just the rest of the world’s future, but it is our future, and we intend to lead that future together.

“This is not about technologies. And it’s not about just one country. It’s about our world. It’s about recognizing that climate change demands actions that have to be taken right away and at scale, if we hope to deliver our children a future that we can be proud of,” she said.

Emphasizing that the administration’s goal is to foster domestic public-private partnerships, McCarthy also stressed that “President Biden knows that this isn’t just about clean energy. It’s about two-plus years of people stuck in their homes, wondering what the future is going to look like.

“And that future has to be hopeful,” she said emphatically. “That future has to be filled with new jobs, new growth opportunities. That’s what this is really all about.”

John Pettigrew, CEO of National Grid (NYSE:NGG), seemed to agree with McCarthy’s assessment of Week 1 of the conference and the administration’s goals for the U.S. energy markets.

“I’m finishing the first week with a sense of optimism because of the progress that’s been made,” he said. “Some of the announcements that we’ve seen and the commitments that have been made over the last week — whether it’s methane, whether it’s the phasing out of coal — some of the individual country commitments are much bigger than perhaps we could have anticipated. … We’ve got a real momentum that’s going to build as we come off COP26. The reality is that over the last 10 years, it feels like we’ve been jogging towards a goal line. We now need to start to sprint.

Ralph Izzo, CEO of Public Service Enterprise Group , headquartered in Newark, N.J., said the Biden administration’s efforts to facilitate offshore wind has created “a tremendous amount of investment in the region so that prices of projects “are actually coming down.”

“We’re investing over a billion dollars in offshore wind,” Izzo said. “We have approval to invest $150 million in the next year [for] electric vehicle charging stations. We’re asking for another $250 million to do more of that in New Jersey. All of that pales in comparison to the 13 million tons of carbon per year that we avoid by producing 30 TWh of nuclear power.”

On the West Coast, the challenge facing Edison International subsidiary Southern California Edison is a good example of what it will take to achieve the Biden administration’s goals, Pizarro said. California has set an overall target to have net-zero emissions by 2045 by electrifying transportation and heating and cooling in buildings.

“It’s a transition that’s doable, but it relies on clean electricity to repower a lot of the economy. Clean electricity will require the addition of something like 80 GW of renewables to the bulk power [grid] statewide, along with 30 GW of storage.

“Distributed [generation] is important too. We see the need for 30 GW of distributed renewables with 10 GW of distributed storage. That level of deployment will require a significant investment across the California economy. We estimate $250 billion statewide for those resources along with the grid investments needed to connect,” he said.

New Mexico is another sun-drenched state moving in a similar direction, and Pat Vincent-Collawn, CEO of PNM Resources (NYSE:PNM), recalled her company’s decision to shut down two coal plants when McCarthy was head of EPA, during the Obama administration. This year the company will shut down two more coal boilers and replace them with solar and batteries. New Mexico’s target is to be carbon free by 2040, she said.

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Overheard at NECBC Energy Conference: NECEC Line ‘Will be Built’

BOSTON — Ideas to build out the energy infrastructure in New England are plentiful. Still, concerns remain about the execution of potential projects to address the region’s ambitious climate change goals in addition to reliability.

American and Canadian business and government officials addressed the ideas-to-execution paradox during the New England-Canada Business Council’s 29th Annual Executive Energy Conference on Nov. 4-5.

The recent referendum rejection by Maine voters of the New England Clean Energy Connect transmission line was top on attendees’ minds.

The following is some of what we heard during the two-day event.

NECEC Project Vote

Voters in Maine went to the polls on Nov. 2, and a majority of them cast ballots to block construction of NECEC’S 145-mile transmission line through western Maine to deliver 1,200 MW of hydropower from Quebec to Massachusetts. However, on Nov. 3, Avangrid, the parent company of project developer Central Maine Power, filed a lawsuit in Maine Superior Court challenging the constitutionality of the referendum. (See Maine, NY Voters Prioritize Conservation on Election Day.)

Dennis-Arriola-2021-11-05-(RTO-Insider-LLC)-FI.jpgAvangrid CEO Dennis Arriola | © RTO Insider LLC

Speaking on a panel Friday, Avangrid CEO Dennis Arriola did not pull any punches about the future of the $1 billion project, which he said will be built on existing rights-of-way and commercial logging lands. NECEC, Arriola said, is good for the economy and environment and is “respectful of the local lands where the transmission lines are going to go.”

“The arguments that this project is doing really bad things to the forest, and everything, is totally false,” Arriola said. “I think that the narrative has been manipulated by, candidly, some characters that will be on the losing end of the energy transition.”

Arriola did not mention any specific “characters” by name.

More baseload fuels are needed to complement the intermittent electricity from offshore wind and solar, according to Arriola. It is essential to understand, he added, that “especially here in the Northeast,” projects specific to transmission have been blocked by companies that only care about “the bottom line.”

“When you look at what we need in this country, we don’t just need the renewables, we don’t just need more battery storage, we don’t just need more green hydrogen, we need a lot of transmission to be able to transport that clean energy to where it’s needed,” Arriola said.

If the U.S. and New England are serious about hitting “bold, audacious goals for carbon reduction” and getting to net-zero emissions in the next 15-30 years, he said, it will not happen without transmission.

“We’ve got to stop just talking about things,” Arriola said. “We got to put things into action.”

Government policymakers must “stand up and help push these projects along when they’re done right by the rules” established by them, he said.

Hydro-Québec can be “part of the solution in the Northeast,” Dave Rhéaume, senior director of development, strategy and commercial relations outside Québec, said during the panel discussion. He recognizes that whenever Hydro-Québec develops new deals, “obviously they come with very expensive transmission projects” like NECEC. As a renewable energy supplier, Hydro-Québec finds a market that requires renewables and sees the value proposition in building transmission lines that take energy in one direction … for now, Rhéaume said.

“We believe that in the long run, these lines won’t be unidirectional anymore,” he said. “They will be used to reduce the amount of curtailment periods in neighboring markets.”

Speaking of Tx

The referendum in Maine should be “sobering,” according to NERC CEO Jim Robb. He believes it put a “stick in the spokes of progress.”

There is a “robust transmission system” in New England, according to ISO-NE CEO Gordon van Welie. Still, there is more work to be done ahead of the integration of more renewable energy.

NECBC-Panel-2-2021-11-05-(RTO-Insider-LLC)-Alt-FI.jpgFrom left on stage: Gordon van Welie, ISO-NE; John Gulliver, Pierce Atwood Bill Quinlan, Eversource. On video: Richard Dewey, NYISO; Francis Bradley, Canada Electricity Association; Doreen Harris, NYSERDA. | © RTO Insider LLC

Eversource Energy operates about 50% of the transmission assets in the region, and Bill Quinlan, president of transmission and OSW projects for the utility, said that despite some of the headwinds for extensive energy infrastructure, “there are some paths forward.”

Quinlan cited Eversource’s $49 million project with National Grid in Boston, the first competitive transmission solicitation under FERC Order 1000. ISO-NE issued the RFP to address transmission violations expected after the retirement of Exelon Mystic Units 8 and 9, whose closing was extended to May 2024, under a two-year, $400 million cost-of-service contract. The Eversource-National Grid project has a projected in-service date of Oct. 1, 2023, eight months before the end of the contract. (See ISO-NE Chooses Incumbent as Boston RFP Winner.)

Quinlan said the retirement of a significant fossil-fuel asset like Mystic would help with decarbonization efforts.

“I know there are challenges, but I think if you’re creative and you deal effectively with stakeholders, you can build infrastructure, and that is going to be the challenge of the future,” Quinlan said.

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Inslee Order Electrifies State-owned Fleet by 2040

Washington will convert its entire state-owned vehicle fleet to electric by 2040, according to an executive order issued by Gov. Jay Inslee on Sunday.

Inslee discussed the order at a virtual press conference Monday morning with the Washington media. He is attending the 26th U.N. Climate Change Conference of the Parties in Glasgow, Scotland.

The executive order calls for the electrification of all the state’s light-duty vehicles by 2035 and medium- and heavy-duty fleets by 2040. The order covers roughly 5,000 vehicles.

The plan will be implemented by replacing gas-powered vehicles as they wear out. Inslee will work with the state legislature to obtain state funding, which will then be leveraged to obtain additional federal money.

“The capital costs will not be an insignificant figure,” Inslee said at the press conference. However, the state will save money because of smaller operating and maintenance costs, he said.

Last spring, Washington lawmakers passed a bill that ordered carbon emissions from gasoline and diesel fuel sold in Washington be cut by 10% below 2017 levels by 2028 and 20% by 2035. (See LCFS Bill Passes Washington Legislature.) A 2008 law sets overall carbon-reduction targets of 45% below 1990 levels by 2030, 70% by 2040 and 95% by 2050.

A 2021 Washington Department of Ecology report put the state’s carbon dioxide emissions at 99.57 million metric tons in 2018. The report shows that from 2016 to 2018, the transportation sector was the largest contributor at nearly 45% of emissions.

“This is the kind of nuts-and-bolts thing that enables us to reach our target,” Inslee said.

Inslee’s announcement comes roughly a week after Seattle Mayor Jenny Durkan announced a similarly sweeping climate-based executive order at the Glasgow summit.

Durkan’s order creates new carbon-based building performance standards, bans fossil fuels in city-owned buildings by 2035, and expands access to public transportation, according to KING-TV.

The order calls for Seattle’s Office of Sustainability and Environment to create legislation for carbon-based building performance standards for commercial and multifamily buildings that are 20,000 square feet or larger by July 2022, KING-TV reported. The executive order also bans the use of fossil fuels in city-owned buildings by 2035.