Municipal utility Seattle City Light wants the same legislative green light to manufacture hydrogen for fuel that Washington’s rural public utility districts (PUDs) have received.
In 2019, Washington’s legislature passed a law that allows the state’s PUDs to produce and distribute hydrogen. The state’s municipal utilities do not have that legal authorization.
“We would like municipal hydrogen authorization,” Mendy Droke, government and legislative affairs advisor for Seattle City Light, said Thursday at a briefing of the Washington House Environment and Energy Committee.
While committee members did not say whether they would tackle such a bill in their 2022 session, Droke’s statement addressed a question from Rep. Alex Ramel (D) about whether municipal utilities should have that authorization. Ramel is active in climate change legislation in Olympia.
Washington has no infrastructure to support fuel cell vehicles (FCEVs) powered by hydrogen.
But the Douglas County PUD plans to start operating a hydrogen manufacturing plant in the first quarter of 2022 along the eastern shore of the Columbia River in central Washington. The $25 million facility is expected to produce two tons of hydrogen per day with plans to expand when more output is needed. (See Wash. PUD Breaks Ground on Hydrogen Plant.)
“We want to make Douglas County a hotbed of hydrogen production,” PUD General Manager Gary Ivory said.
Two hydrogen refueling stations are on the drawing board in Douglas County and in Chehalis, which is south of Olympia. Both are slated to begin operating sometime in 2022. The first hydrogen-fueled vehicles in Washington will be a handful of buses to be operated by Twin Transit in Lewis County — which contains Chehalis — plus a few Douglas County PUD trucks.
By contrast, California has roughly 11,000 hydrogen-fueled vehicles and about 50 refueling stations, Jason Sekhon a senior consultant with Toyota North America, told the committee.
Sekhon said that Washington faces several challenges in bringing hydrogen-fueled vehicles to the state, including the current lack of local hydrogen production.
Sekhon said the state needs to build a hydrogen-refueling network prior to boosting the sales of the vehicles. Government agencies need to coordinate their refueling facilities so all agencies can use them. He added that tax exemptions should be set up for the earliest purchasers of hydrogen-fueled vehicles.
He said co-locating hydrogen refueling stations with gas stations is an easy path to take. A hydrogen-refueling station in California capable of handling 1,400 vehicles a day costs about $3 million to develop, roughly the same cost as an electric-vehicle charging center cable of handling the same volume of vehicles, he said. However, hydrogen refueling takes three to five minutes compared to up to 30 minutes for an electric recharging.
Seattle City Light and Tacoma Power plan to study getting into hydrogen vehicles and possibly production, said officials from those utilities.
CHARLOTTE, N.C. — About 300 representatives from independent power producers, utilities, law firms and regulatory agencies met at Infocast’s sixth annual Southeast Renewable Energy conference last week to discuss the region’s progress in integrating solar power.
Michael B. Woodard, a partner with McGuireWoods, introduced a panel of regulators by showing a chart of states’ growing solar capacity since 2016, with Florida now in the top spot, having supplanted North Carolina. The Sunshine State trails only California and Texas nationally as of the second quarter of 2021, according to the Solar Energy Industries Association.
Other states in the Southeast, however, are playing catch-up, speakers said. Here’s some of what we heard.
State Regulators Panel
Arkansas regulator Ted Thomas joined Georgia’s Lauren “Bubba” McDonald and Mississippi’s Brandon Presley (participating virtually) in a panel on issues facing their states.
Thomas, chairman of the Arkansas Public Service Commission, said state regulators must be flexible to respond to the pendulum swings of federal clean energy policy. “We don’t know what’s going to happen. What happens might, in fact, change in four years,” he said. “What we’re trying to do is be prepared regardless of which of the scenarios happen.”
Thomas said regulators look to entrepreneurs to help them judge emerging technologies. “We don’t know what the customer wants. We don’t know what the feds are going to tell [us we] have to have,” he said. “But entrepreneurs test demand.”
McDonald, re-elected to the Georgia Public Service Commission last year, defended his support of the delayed and overbudget Vogtle Units 3 and 4, which he proudly noted are the first new nuclear plants built in the U.S. in more than three decades. The cost of the project has nearly doubled from early estimates of $14 billion to about $27 billion.
Southeast solar capacity by state (MW) as of Q2 2021 | Solar Energy Industries Association
“It hasn’t been easy, [but] I’ve committed to it,” he said. “Nuclear is the best friend that solar energy has, because [it] runs 24/7 [at] 99.8% [capacity factor]. And it’s cheap, and it’s clean.”
McDonald acknowledged Vogtle’s cost overruns and delays. “My personal preference as a regulator is the least regulation is the best regulation. But we do have to intervene sometimes when a project gets out of hand. We’ll have to spank somebody a little bit and straighten it back up.”
Presley, a Mississippi Public Service Commissioner, acknowledged his state has trailed in renewable energy development but said the PSC will be issuing “forward-looking” rulemakings soon on net metering rules and community solar in a bid to attract new generation.
“Money, it completely votes with its feet. … The Fortune 100 [companies], the Fortune 50s — in any economic development project — one of the biggest questions on the map is whether or not you have a renewable source of power,” he said. “We know that [other] states are ahead of us on [that], and we’re working like the dickens to catch up.”
He said the PSC is to blame. “For a long time, they did pretty much what Mississippi Power and Entergy and others wanted done, and that has really led over time to things like the Kemper County power plant,” he said. Initially estimated at $2.4 billion, the cost of the carbon capture and sequestration plant more than tripled to $7.5 billion before the project was canceled.
“Imagine if we had invested those dollars at that time in renewable energy research, renewable energy projects, where we would be on the rankings today,” Presley said. “If the South is going … to pull forward out of the economic morass that we find ourselves in … we’ve got to attract this development.”
Presley said the state’s utilities should take full advantage of federal infrastructure funding for upgrading transmission and hardening assets. “There’s going to be some dollars in this infrastructure bill that can go to offset that. The utilities are going to have to be aggressive. I really don’t want to hear them come in before me and tell me about how laborsome and awful it is to go through and apply for this federal money,” he said. “We’ve got to get this work done. And God forbid that we look back 10 years from now, 15 years from now, and we sat on our hands and did not take advantage of what’s on the table today.”
Build Back Better Impact
Democrats’ Build Back Better act, approved by the U.S. House of Representatives and pending before the Senate, was also a subject of discussion.
Akin Gump partner Shariff Barakat said the law’s direct pay provisions won’t eliminate the need for tax equity investors because of the volume of extended and expanded tax credits and “timing issues,” including the inability to offset estimated tax payments. He also said depreciation may be more valuable with a tax equity investor and that projects beginning construction after 2023 will need to satisfy domestic content requirements to use direct pay without penalties.
Solar Panels Increase Resilience in Hurricanes?
PosiGen Solar, which develops rooftop solar for low- and moderate-income residents, has 12,000 systems in Louisiana, many of them along Interstate 55 — coincidentally the path that Hurricane Ida took in August. More than 3,000 houses suffered storm damage, but less than 50 systems had to be replaced, CEO Thomas Neyhart said.
“The solar systems reinforced the roof; the solar systems help harden it,” he said, displaying an aerial photo showing blue tarps over damaged roofs beside undamaged roofs with solar.
“We’re having a study done right now by [Louisiana State University] on how to harden roofs, not just by putting solar on but then also using the right types of shingles and the right types of construction to allow them to sustain direct winds of 130 to 150 mph. We think there’s a great future in our ability to help harden roofs in some of these hardest hit areas,” he added. “More importantly, though, as you think about the future, we start to think about batteries. … We’re working right now with the governor’s office and the incoming [City] Council members to try and put together a battery program for the hardest hit people in Louisiana, which is down in New Orleans.”
Hydrogen emerged as one possible solution to climate change during the recent 26th U.N. Climate Change Conference of the Parties, but details of the transition to the fuel were sketchy, leaving the door open to competing solutions.
What was clear even before the historic conference is that hydrogen research has been underway for some time and that moving away from energy-dense oil, coal and natural gas would be as consequential as the switch from burning wood to coal at the start of the industrial revolution.
The Center for Strategic and International Studies (CSIS), a non-partisan think tank founded to address national security issues, has been focusing on what that transition might look like, including the underlying economy necessary to support such a change.
CSIS has hosted a series of energy webinars on the topic, the most recent of which examined the “building blocks for a hydrogen economy.” The discussion was sponsored by Japan House of Los Angeles.
Moderated by Jane Nakano, a CSIS senior fellow heading the security and climate change program, the Nov. 16 discussion focused on:
efforts in California to expand the current fleet of 100 fuel cell buses and more than 10,000 fuel cell cars and light trucks already on the roads and expand the network of hydrogen fueling stations;
plans to begin switching a small number of the nearly 3,000 diesel and gasoline trucks and unloading equipment at two major California ports to either fuel cells using hydrogen or batteries charged on the local distribution grid;
efforts in Japan to burn anhydrous ammonia (NH3) with coal at power plants and ultimately modify gas turbine power plants to operate with hydrogen — and importing all that hydrogen or ammonia through a global supply chain still under development.
Fueling the FCEV Fleet
Bill Elrick, executive director of the California Fuel Cell Partnership, said fuel cell electric passenger cars and light trucks would provide the foundation for building a hydrogen refueling system for heavy trucking.
His organization launched a retail-oriented hydrogen market about six years ago, opening hydrogen refueling stations, typically at gas stations already in business. The point was to convince potential owners of fuel cell electric vehicles (FCEVs) that they would have a steady supply of hydrogen. Now they want to expand the system in order to increase the light-duty FCEV fleet.
“By achieving that light-duty market, we see it lowering the cost not just for that market, but [lowering] hydrogen infrastructure and fuel cell technology costs for other applications and even other regions,” he said.
Whether EVs are powered by batteries or fuel cells is not as important as what fuels them, he added. Both hydrogen and electricity stored in batteries are 100% carbon-free.
Toru Sugiura is a senior manager at Toyota Tsusho America, a Kentucky-based subsidiary of Toyota Tsusho, a global trading company dealing in metals, automotive parts, chemicals, food and fuels. He said his company has been working to develop the kind of hydrogen supply chain that Elrick described.
“We operate hydrogen stations in Japan,” Sogiura said. “That is currently a challenging business model for economic viability by simply waiting for customers to come.”
In California, the company is about to begin a demonstration project, supported by several federal grants to create hydrogen from methane produced from cow manure and then deliver that gas to the Port of Los Angeles, where efforts are underway to switch out diesel-powered equipment with that powered by fuel cells.
“By making the whole value chain together as one business model, we are trying to create a supply and demand [and] at the same time a self-sustainable supply chain from upstream to … [down]stream,” Sugiura explained.
He said the company has held extensive discussions with terminal operators at the Port of Los Angeles and at Long Beach, about 25 miles away.
The two ports are home to 13 shipping container terminals. The nearly 3,000 trucks, gantry cranes and other cargo handling equipment, powered by diesel or gasoline engines, operate around-the-clock at the terminals.
The company has developed a mobile fueling station that will deliver the renewable hydrogen to the terminal equipment powered with fuel cells, he said.
A related company, Toyota Motors, has partnered with truck maker Kenworth to build 10 fuel cell terminal trucks, now operating at the ports.
“Port terminals have determined a very clear goal of zero emission. The equipment must be 100% zero-emission by 2030 and … the trucks that must be-zero emission by 2035,” Sugiura said.
“There are many challenges to overcome for this technology transition from diesel to hydrogen in the port area. The first one is hardware commercialization by the [original equipment manufacturers]. So we work closely with the OEMs to promote the development and also the actual manufacture of the equipment.
“Another obstacle is that currently only the Port of Los Angeles will require the fuel cell-powered equipment.”
Finally, fuel cell trucks are more expensive than diesels. And hydrogen is more expensive at this point than diesel fuel, he said.
Even if the demonstration is successful, moving to mass production of hydrogen and full commercialization of fuel cell trucks will be a challenge, Sugiura said, including regulatory issues that must still be worked through.
Hydrogen fueling protocols and fire code permits will be critical, he said. “This is a slow process, so we are working closely with the government and related authorities.”
Room for Both
CSIS’s Nakano asked whether it would make more sense to rely on batteries rather than fuel cells.
“We need both of them because they both have strengths and weaknesses that actually match each other,” Elrick said. “Just like neither diesel nor gasoline dominated everything in either market, but they found where they worked best.”
“I think we’re going to find that generally and in transportation especially,” he continued. “And I don’t think it’s out of place to say the heavier applications will clearly play with the advantages of hydrogen more, where batteries, on weight alone, can be one of the disadvantages.
“But in the light duty, especially in the urban communities, we will see more battery vehicles because they don’t go as many miles and that’s a really nice niche for them. But I also think there will be a lot of overlap.”
Izumi Kai, president of Houston-based LNG company JERA Energy America, a subsidiary of Japan’s largest electric power producer, said LNG will remain important for the next two to three decades, especially in developing countries.
He said JERA wants to blend ammonia with coal at its most efficient coal-fired power plants with the goal of completely replacing coal. Similarly, the company hopes to begin to switch its gas turbine power plants to 100% hydrogen by co-firing hydrogen and natural gas. (Anhydrous ammonia is a gas but turns to liquid at -28 degrees Fahrenheit.)
“But it takes 20 years or so, to achieve a full replacement … to enable such co-firing. It is very difficult to be responsible for a stable energy supply and also a competitive energy supply,” Kai said.
Japan now imports its LNG but in the future hopes to import ammonia because it is easier to transport, he added, and it can be converted to hydrogen at its point of use if necessary.
Asked by Nakano whether carbon pricing or the creation of a carbon market might speed up the development of hydrogen as a fuel, all three panelists agreed it would.
Kai said Japan and other Asian nations, which will be importing low carbon fuels, would especially benefit.
“It’s important to have some kind of government support or some kind of commercially viable mechanism. A carbon credit system is one of the key options,” he said.
Sugiura, whose company wants to electrify the Port of Los Angeles, agreed. “In order to make hydrogen a common fuel, I think it’s very important that we start using hydrogen, whatever the color,” he said, adding that hydrogen would be become a “common fuel” if given a credit in a federal carbon market.
And Elrick, whose organization is poised to go national in its advocacy of hydrogen fuel cells, said decarbonizing the fuel is equally as important as switching to FCEVs.
“If we changed every car, or vehicle, if we changed every heat pump and every stove to zero emission, it doesn’t necessarily mean that fuel, whether hydrogen or electricity, was decarbonized,” he said.
CHARLOTTE, N.C. — Renewable developers said last week they don’t expect much from the controversial Southeast Energy Exchange Market (SEEM), saying it falls far short of the transparency and competition found in RTOs and ISOs.
The developers reacted coolly to representatives of Southern Co. (NYSE:SO) and Duke Energy (NYSE:DUK), who defended SEEM at the Infocast Southeast Renewable Energy Conference.
Proposed by more than a dozen utilities and cooperatives including Southern, Duke and the Tennessee Valley Authority, SEEM would automate bilateral trades, allowing 15-minute energy transactions, and use free transmission to reduce rate pancaking. The SEEM agreement took effect Oct. 12, after FERC deadlocked 2-2 on the proposal. (See SEEM to Move Ahead, Minus FERC Approval.)
Critics of the proposal say it would only perpetuate the utility monopolies of the Southeast and produce a fraction of the savings that could come from an RTO.
Utilities’ Control
“I think there’s a lot of concern that participation — controlling who participates — is in the hands of the people developing SEEM. And so whether or not we get the chance to actually participate, we’ve got a lot of questions about that,” Blan Holman, vice president of regulatory affairs for solar developer Pine Gate Renewables, said during a panel discussion at the conference.
Noel Black, vice president of federal regulatory affairs for Southern, responded that SEEM’s sponsors are seeking wide participation.
“Participation and liquidity [are] really important for SEEM and how much benefit it brings to customers, so we are eager and excited to have more participants. I want to be clear on that,” he said. “The opportunities I believe are fantastic. If you get a giant footprint … 160,000 MW, 50 million customers, 1,000 miles between Savannah and Springfield, Mo., with zero transmission [cost] … the more participants, the more liquidity, the more opportunity we have to bring value … to our customers. So if we buy something, in SEEM, it’s cheaper than something we would have run … that goes straight to our energy costs, to our customers. If we [make] short-term opportunity sales, the margin we make flows back through to our customers, either through lower rate base or energy clauses.”
Cost, Speed
Black said the cost of establishing SEEM — $5 million to $6 million — is “extraordinarily inexpensive” compared to alternatives such as an RTO.
Molly Suda, associate general counsel for Duke, also touted the speed at which SEEM will be launched, with hopes to begin operations by the end of 2022. “For other market designs, there are substantially longer lead times,” she said.
In response to questions, Black and Suda acknowledged SEEM will not offer LMP or provide a clearinghouse for environmental attributes.
SEEM’s sponsors said an independent third-party consultant estimated the market will provide members a total of $40 million to $50 million in annual savings in the near term, potentially growing to $100 million to $150 million annually “as more solar and other variable energy resources are added.”
“By the utilities’ own admission, [comparing SEEM to an RTO is] sort of like comparing a flea to a basketball,” Chris Carmody, executive director of the Carolinas Clean Energy Business Association (CCEBA), said in a separate session at the conference. “The projected savings that the entire SEEM project would do across these many, many utilities is $40 million a year [and] I think $10 million for North Carolina. … Ten million is less than half of the salary of a significant CEO.”
In September, the American Council on Renewable Energy released a report that found an energy imbalance market (EIM) would reduce total resource costs from $64.7 billion in 2020 to $42.1 billion in 2040, a 35% savings, versus a more modest reduction to $53.1 billion (18%) under SEEM. (See Report: SEEM’s Benefits Beaten by Other Models.)
Black said SEEM’s sponsors considered an EIM but rejected it because of its “command-and-control nature” and the cost and time to stand it up. “So the question becomes can you get the same benefits at a much lower cost without the bureaucracy and burdens of some of the other structures? And right now, the answer, in our minds and in our hearts and on paper seems to be ‘yes.’ [We] can effectuate scope and scale without the bureaucracy and burdens of more complex structures.”
Transparency
Transparency is another concern of renewable developers, said Pine Gate’s Holman. “If you have a full-blown RTO, you get visibility in the pricing. And here, I think there’s concerns about whether or not you can be able to … see the transactions in a way that helps send signals to the market for further investment,” he said.
Black said there is a “fine line between transparency and … exposing commercially sensitive information.”
“We were trying to thread that needle so that we give enough exposure … to build that trust [and ensure SEEM is] executing the tariff as designed, but also not expose information that participants might find too sensitive. I think we struck the right balance. We’ll see. I think time will tell.”
Black said the cost-benefit study done for SEEM found that 2% of the energy in the region will flow through the market, which he said, “feels defensible, and maybe a little conservative.”
Although only 5% of the Western Energy Imbalance Market’s regional energy flows through the market, BIack said “you get a sort of cost transparency on 100% [of transactions] off that 5% at the top of the stack.”
“I believe that [SEEM] has the potential to bring those sorts of benefits to customers as it grows. And the more participation we have and the transparency and comfort grows, I think we’ll see those sorts of benefits. So I feel comfortable coming out of the gate and looking anyone and everyone in the eye and saying, ‘Here’s what we believe this will do,’ … and then having hopes and dreams that it will be much bigger and amazing as we move down the road.”
In a statement Oct. 20, FERC Chairman Richard Glick expressed concern that because the commission did not issue an order approving SEEM, its sponsors might not honor the promise they made to provide transparency. (See FERC’s Christie Accuses Glick, Clements of Prejudice for RTOs.)
In response to a FERC deficiency letter, the sponsors promised in June to provide confidential weekly submissions of market data to the commission and SEEM’s Market Auditor, “comparable” to the data provided by RTOs under Order 760, including participants, bid/offer prices, quantities and locations. They also agreed to make the “just-and-reasonable standard” the default for most SEEM rules rather than the lower Mobile-Sierra public interest standard. (See SEEM Members Offer Rule Changes.) In Mobile-Sierra, the Supreme Court ruled that when sophisticated parties negotiate at arm’s length, their agreement should be presumed just and reasonable unless it can be shown to harm the public interest.
Black said Glick has no reason to worry. “I would say the SEEM members are all comfortable with those commitments, and highly likely — within the next week or two — to file those commitments with FERC in some form or fashion,” Black said. The transparency provisions “are there to build trust in the system, for not just participants, but members as well. The more trust in the system, the more likely the system will work and [there will be] liquidity. … So we will be filing something to put those commitments in … place, regardless of whether we were ordered to do that.”
No Boon for Solar Developers
Meredith Chambers, general counsel and regulatory compliance officer for EDP Renewables (OTCMKTS:EDPR), said SEEM is unlikely to affect the plans of the Madrid-based company, which is new to the Southeast market, with 60 MW of generation operational and 350 MW under construction.
“We would like to work with other stakeholders to see a more a more regional approach that includes conversations with all the stakeholders,” she said. “I don’t know that [SEEM] changes what we do at this at this moment. But I think that there are opportunities over time to have broader conversations about ways to integrate.”
Carson Harkrader, CEO of Carolina Solar Energy, which develops utility-scale solar projects in North Carolina, Virginia and Kentucky, said large energy consumers share the frustration of renewable developers that the regulatory and market structure of the Southeast doesn’t allow them the options they have in RTO territories, such as the ability to sign long-term power purchase agreements. Financing solar projects requires a minimum 10-year PPA, she said.
In RTOs, “we’re able to sell for long-term, fixed-price contracts with energy users. … Obviously, SEEM would not enable that kind of transaction. … I think any solar developer would tell you that’s what we’re hoping for,” she said.
“So for new solar, playing in an open market with fluctuating prices, it would be hard, I think, to finance a new solar project,” she added. “Potentially for projects that are coming off an initial PPA, that might be an opportunity.”
Fight not Over?
Moderator Weston Adams, of Nelson Mullins Riley & Scarborough, noted that rehearing requests have been filed over SEEM’s proposal, and that Democrat Willie Phillips has been confirmed as the commission’s fifth commissioner, with the potential to break the 2-2 deadlock. “Certainly there are parties that think this fight is not over — that this is going to be litigated into the D.C. Circuit” Court of Appeals, he said.
Duke’s Suda said she doesn’t see legal obstacles to SEEM.
“In our view, given the recent order earlier this month on the transmission tariff changes … really the only issue holding back a three-vote majority on this is [a dispute over the application of] Mobile-Sierra.”
Suda was referring to FERC’s Nov. 8 order accepting revisions to four SEEM utilities’ tariffs that implement the special transmission service used to deliver the market’s energy transactions. Chairman Glick, who had opposed the market’s creation, sided with Commissioners James Danly and Mark Christie, saying the parties’ filings, unlike the SEEM agreement, do not apply Mobile-Sierra provisions that would limit FERC’s authority to require changes.
Integration, Transmission Costs
Hamilton Davis, vice president of markets and regulatory affairs for Southern Current, a developer of large-scale solar and energy storage projects, said SEEM does not address independent power producers’ concerns over increasing curtailments and rising integration costs in the Carolinas.
“What Duke and Dominion [Energy] [NYSE:D] both said in their recent [integrated resource plans] is that SEEM is not actually going to help with integration costs. There are big opportunities to improve the design of this market so that it actually does at scale; some of what Noel has pointed out is nothing more than aspirational right now.
“I don’t think from an IPP standpoint [that] we’re anticipating participating in that market; the business model is not structured in a way where you would go finance a project based on the ability to sell. … From an IPP standpoint, it looks pretty limited.”
CCEBA’s Carmody also said SEEM will do nothing to address the “black box” of transmission costs in the Carolinas.
“It is becoming harder to understand. The information is becoming less accessible rather than more accessible,” he said. “We’ve spent a lot of time talking about generation in both states over several years … but if we don’t have a transparent and objective process for determining investments in transmission, then we are really in big trouble in a lot of ways, economically and environmentally.”
Washington Gov. Jay Inslee is mostly happy with how state agencies are dealing internally with reducing their carbon emissions, but he still believes they must speed up their efforts.
Agency officials agreed last week during a virtual briefing with the governor.
“Whatever we’re doing, we have to have higher ambitions because we’re not meeting our goals,” Inslee said.
Hanna Waterstrat, director of the Office of State Efficiency and Environmental Performance in the Washington Department of Commerce said, “The science indicates our targets need to be accelerated.”
The biggest shortfall of those related to charging infrastructure for electric vehicles, the briefing revealed. Currently, 81% of the roughly 5,000 state-owned vehicles are hybrid gas-and-electric. Three percent of all the vehicles, including trucks and vans, are totally electric, while 7% are totally electric. The inadequate number of charging stations require electric cars to rotate through them rather than all being able to recharge overnight simultaneously.
The state needs to analyze its electric charging systems to come up with numbers, budgets, installation plans and policies, including allowing agencies to use each other’s chargers, said Kelly Lerner, chief of leased facilities and maintenance for the state’s Department of Social and Health Services.
“We need to have standard charging systems and policies rather than agency-by-agency systems. … I want to accelerate transitioning to electric vehicles,” Inslee said.
“We need the money for the infrastructure first,” Lerner said.
Building for Net Zero
In Spokane, the state government recently completed its first net-zero building. The 6,200 square-foot structure is a garage and storage building for the Department of Ecology’s emergency response team for the state’s 20 easternmost counties. The team covers hazardous spills, methamphetamine labs and illegal marijuana operations.
The building includes rooftop solar panels. However, the team’s vehicles are still gasoline-powered because potential hazardous sites could be beyond the round-trip range of an EV, said Sam Hunn, the department’s spills response supervisor for Eastern Washington.
Meanwhile, the state government is looking at constructing the first zero-emissions building on the Capitol Campus in Olympia — a daycare center for the children of state employees.
The agency that manages New Jersey’s $100 billion state pension fund has codified a strategy to reduce carbon emissions at companies backed by the fund, with measures that will include an in-house assessment of emission reduction efforts across its entire portfolio and participation in shareholder pressure tactics.
Addressing Wednesday’s meeting of the State Investment Council in Trenton, Suzanne Hannigan, the sustainable investing portfolio manager for the New Jersey Division of Investment, presented a summary of the state’s new climate action investment plan. The plan would take a “holistic approach to addressing climate change risks and opportunities” while adhering to the agency’s fiduciary duty to make investments that are profitable, and boost the wealth in the fund, Hannigan said.
The council is primarily an advisory body and does not vote on specific proposals. However, the division posted a 5-page outline of the policy called “Principles and Practices Regarding Climate Change” on its website Wednesday afternoon, and said the policy is now in effect.
Divest NJ, an activist group that has pressured the division to divest from fossil fuel companies, said the agency’s announcement was the first time it had set down a concrete set of climate-change initiatives.
“It is a significant day,” said Tina Weishaus, co-chair of Divest NJ. “It is the beginning of a climate action plan. I think they’re definitely going in the right direction, and we appreciate that. And we’re glad they put it on paper.”
Hannigan told the meeting Wednesday that the goal of the plan is to “identify, understand and manage the investment risks and opportunities that arise from climate change, and from the transition to a low-carbon economy.
“We recognize that we cannot have a social agenda or act as agents of change for any reason unrelated to the financial interest of our beneficiaries,” Hannigan said. Still, she said, “We believe our practices will encourage portfolio companies to consider how climate change and the energy transition will impact long-term shareholder value.”
Climate Change Investments
The emission reduction strategy follows the division’s recent decision to put $200 million into a climate-themed private equity fund, Rise Climate managed by TPG Capital Partners, which invests in companies working to develop opportunities related to climate change and carbon reduction. It was the division’s second investment in a climate-change related fund, following a 2020 investment of $100 million in the Stonepeak Global Renewables Fund, which is dedicated to “executing renewable energy investments.” (See NJ Ups Pension Investments in Climate Funds.)
The council on Wednesday also reviewed another proposed climate change investment putting $600 million into the Brookfield Global Transition Fund. The fund has a “strong ESG and sustainability focus,” the division said.
Ryan Goodwin, an investment analyst who presented the Brookfield proposal, said the fund will invest in “wind and solar projects as well as industrial companies with the intention of generating both strong financial returns and a positive and measurable environmental impact.” The fund has a goal of “decarbonizing each investment made,” and expects an annual return of 13%, said Goodwin. He called it “one of the largest private owner and operators of renewable assets,” with 21,000 MW globally.
The division said the Brookfield proposal is still under negotiation and will need the final approval of Acting Director Shoaib Khan.
New Jersey’s climate-themed investments reflect a growing interest among much larger pension funds in backing such investments and leveraging their funds to pressure companies to take steps toward reaching net-zero emissions.
For example, New York State Comptroller Thomas P. DiNapoli announced in December 2020 that the $226 billion New York State Common Retirement Fund would “transition its portfolio to net zero greenhouse gas emissions by 2040.” The initiative will involve a four-year review of the fund’s investments in energy sector companies that will assess “transition readiness and climate-related investment risk,” according to a release announcing the move.
Climate Risk Analysis
Hannigan, summarizing New Jersey’s policy, said it had been reviewed by the division’s Investment Policy Committee, Operations and Governance Committee and the Environmental, Social and Governance (ESG) Committee before being brought to the council.
“Broadly speaking, the division must consider all risks and opportunities that can have a material impact on risk-adjusted returns,” Hannigan said. These include environmental, social and governance (ESG) factors, she said, adding that “today, climate risk is the most meaningful of those.”
The division’s “holistic approach” means that “we will look at all economic sectors, subsectors, asset classes and geographies when analyzing our exposures,” she said.
“Climate risk spans the economy. Utilities, manufacturing companies, transportation, agriculture, all have high emission intensity, in some cases higher intensity than fossil fuel companies do,” Hannigan said. “So, we will review each of those exposures over time.”
The measures outlined at the meeting included:
the incorporation of “climate risk assessment” into the division’s investment evaluation process, and its proxy votes in “accordance with our ESG policy;”
the creation of an in-house Climate Change Practice Group, which will evaluate the exposure of each investment to climate change forces and review risk mitigation strategies at the companies or funds in which the division invests;
the adoption of a policy of “engagement” with companies, through letter writing and shareholder proposals, proxy voting and using the power of investor coalitions to pressure investment managers on climate change issues. The division will also use “due diligence questionnaires and interviews on private investments;”
advocacy with peers and the public to promote “transparency and targets around material climate risk.”
Hannigan said that the first phase of the portfolio evaluation would begin early next year.
“These principles and practices are intended to ensure that our portfolio companies are fully integrating climate change considerations into their governance and strategies with the goal of maximizing risk-adjusted returns for the pension fund,” she said.
Council members, aside from two questions on the policy’s implementation, did not comment on the plan.
Fossil Fuel Concerns
While welcoming the division’s initiative, Divest NJ said it is still just one step in the right direction, and real change will require the agency to divest from fossil fuel companies.
Barbara Pal, co-chair of the organization, told the council that nearly 1,500 institutions from 71 countries, representing $39 trillion worth of assets, have “committed to full or partial fossil fuel divestment.” Among them are two pension funds in New York City, which removed $4 billion from fossil fuels in January. Canada’s second largest pension fund, Caisse de depot et placement du Quebec, said in September it would divest from oil production.
Pal urged the division to divest from fossil fuels.
“All of these organizations have the same goal as the NJ State Pension Fund,” she said. “They want to maximize their profits, and they are convinced that the best way to go about it is by divesting from fossil fuels, not holding onto them.”
Weishaus said she is encouraged that the division has hired additional staff to focus on the climate change evaluations. Melinda Caliendo, division spokesperson, said the agency appointed Hannigan as its first sustainable investing portfolio manager, appointed Jeff Warshauer as corporate governance officer, and dedicated several analysts to ESG work, which includes climate change.
At the same time, Weishaus expressed skepticism that a policy of engagement could work with the fossil fuel industry.
“The history of the fossil fuel sector is one of deception, disinformation, lobbying against any kind of serious climate mitigation,” she said.
“If you’re dealing with a construction company or a cement company, you can demand that they decarbonize their production process,” she said. “But if you’re talking to a fossil fuel company, you’re telling them to not be who they are, which is a company that explores, drills and burns the very thing that is kind of suffocating the world.”
CHARLOTTE, N.C. — Virginia’s landmark Clean Economy Act is unlikely to face major changes any time soon despite Republicans’ victories in the Nov. 2 election, speakers told attendee of Infocast’s Southeast Renewable Energy Conference last week.
Although Republicans gained control of the House of Delegates as well as the governorship and lieutenant governor’s post, Democrats will continue to hold a 21-19 edge in the Senate, which does not face re-election until 2023.
“The numbers that really matter are not the governor, not lieutenant governor, not the House numbers, but it’s the Senate Commerce and Labor [Committee], where the composition is 12 Democrats and three Republicans,” said Cliona Mary Robb, director of law firm ThompsonMcMullan and chair of the Virginia Renewable Energy Alliance. “I would posit to you that … any massive overhaul legislation is not going to get through that roadblock.”
Karla Loeb, policy adviser for Arcadia, an energy software company, and former chief policy and development officer for Sigora Solar, agreed, noting that the VCEA had bipartisan support in both houses of the legislature, including from Terry Kilgore, the incoming House majority leader. “Yes, there were deals made, as there [always] are. But you know, he’s already put his name [behind the bill]. For the past four years, [he] has hosted renewable energy conferences and get-togethers. And he believes that this is coming. Southwestern Virginia, which is his territory, is very excited about the opportunity for clean energy deployment.”
“This legislation was not passed by just the renewable energy industry,” she added. “We worked in concert with Dominion [Energy] [NYSE:D], with [Appalachian Power] [NASDAQ:AEP], on a day-to-day basis to get consensus [on] a piece of legislation that we can all live with. [The utilities] are already procuring their [renewable generation] targets. They’re already making their plans. … The ship has left the port.”
Approved in April 2020, the VCEA requires Virginia to close most of its coal-fired generation by 2024 and makes it the first Southern state to adopt a 100% clean energy standard. It established goals of 5,200 MW of offshore wind and 16,100 MW of solar and onshore wind as “in the public interest.” (See Va. 1st Southern State with 100% Clean Energy Target.)
The GOP victories showed that predictions that the commonwealth had become a reliably blue state were incorrect and raised questions about its commitment to reaching 100% carbon-free electricity by 2050.
Energy policy was not a central issue in Republican Glenn Youngkin’s victory in the gubernatorial race, although he and Democrat Terry McAuliffe differed sharply on the VCEA, with McAuliffe calling for eliminating fossil fuel power by 2035, while Youngkin said even the law’s 2050 target is unrealistic. (See GOP Wins in Va. Raise Questions About State’s Climate Policy.)
Scott Gaskill, Dominion’s director of regulatory affairs, agreed that major changes to the law are unlikely.
“Clearly, there’s going to be change in the administration in terms of [the Department of Environmental Quality], the Department of Commerce. Those types of things could have some tangential impacts, but a wholesale rollback of VCEA doesn’t seem to be in the cards, as long as the Senate” remains in Democratic control, he said.
Limited Supply, Local Zoning Present Obstacles to Solar Goals
But Gaskill said Dominion’s efforts to meet its renewable procurement targets are being hampered by local opposition to utility-scale solar and the backlog in PJM’s interconnection queue.
“When we’re talking about 6 to 8 GW of new solar, that’s a lot of land, and you’re already starting to see some pushback from localities,” he said.
The PJM queue is “quite frankly … a bit of a mess right now,” he said. “Their processes worked very well for years [when there were] a few large units coming in. … Now you’ve got thousands of relatively small [generating projects], and the process isn’t geared towards that.
“We just filed for 1,100 MW [with the State Corporation Commission]. I mean, that was almost every project that we could find.”
Implementation Challenges
Loeb said that while much attention was paid to legislative battles over the VCEA and Congress’ infrastructure and Build Back Better bills, the challenges of implementing the legislation should not be minimized.
“It’s not just a one and done. The [renewable portfolio standard] has annual filings, on top of [integrated resource plans]; storage, again, also regular filings. And so we’re just creating docket after docket after docket, and then, compounding that, with the infrastructure plan, and God willing, Build Back Better … it’s just going to compound things,” she said. “If you guys have teenagers or college-age students, tell them to please become regulatory attorneys, because we do not have enough of them. We do not have enough electrical engineers. We’re grossly understaffed for the transition that we’re about to embark on.”
Robb said persuading local governments to approve solar projects will be key to meeting the VCEA’s goals. “And right now we’re finding them not as friendly as certainly as I’d like them to be,” she said. “You’re [asking permission for] turning over farmland to solar farms for 20, 30, I’ve seen 40 years. … There’s other roadblocks, but nothing happens if you can’t get it … through the local board of supervisors. So I think that’s where we want to win over the hearts and minds.”
FERC on Thursday voted 3-1 to reduce the base return on equity for Exelon’s (NASDAQ:EXC) Mystic Generating Station as part of its reliability-must-run agreement with ISO-NE following requests for rehearing by Connecticut regulators and plant owner Exelon (ER18-1639-010).
The decision, issued during the commission’s monthly open meeting, lowers the ROE to 9.19% from the 9.33% in set in an order in July. Exelon must submit a compliance filing within 30 days revising the agreement that begins on June 1, 2022. (See FERC Sets ROE for Exelon’s Mystic Plant at 9.33%.)
ISO-NE and Exelon in 2018 reached an agreement to continue operating Mystic, and recover associated costs, past a previously sought retirement date of May 31, 2022, into 2024.
In their rehearing request, Connecticut regulators — the Public Utilities Regulatory Authority, Department of Energy and Environmental Protection and Office of Consumer Counsel — said FERC did not correctly apply a “natural break analysis” to results from the discounted cash flow (DCF) model used to determine the ROE rate.
When determining an ROE using the DCF model, FERC uses a proxy group of companies for comparison. A natural break analysis determines whether certain companies in the group screened as outliers, or those almost screened as outliers, truly represent outliers and thus should be removed.
The Connecticut agencies argued that Otter Tail Power should not have been included in the proxy group for Exelon, as its DCF result was far too high: 147 basis points over that of the next highest company in the group. FERC agreed, removing Otter Tail from the group, lowering the DCF calculation and, thus, lowering the resulting ROE.
FERC noted, however, that “while the 147-basis-point gap represents a natural break between potential proxy group companies here, that same gap or even a larger one may not represent a natural break that warrants exclusion of a company in a future case.”
Commissioner James Danly wrote in a concurrence that he remains “concerned” with the continued exclusion of Avangrid from the proxy group as in the previous order, though it was not enough to warrant a dissent. As in July’s order, Danly argued that FERC’s current ROE methodology, “like its predecessors, is too complicated and threatens to cause great uncertainty going forward.”
“The inevitable consequence will be the chilling of investment in transmission development,” Danly wrote. “I would likely not have voted in favor of our revised ROE methodology had it come before me in the first instance, but I also have not seen the kind of evidence that would be necessary to justify jettisoning it for yet another revised methodology.”
In her dissent, Commissioner Allison Clements reiterated her opinion from the July order, from which she also dissented. She argued that FERC’s current ROE policy “applies a flawed methodology that does not adequately protect consumers and does not yield just and reasonable rates.” She said that while the order addresses the ROE portion of cost-based compensation to keep the Mystic online for two additional years, “our ROE policy extends to all cost-based rates within our jurisdiction, including transmission rates.”
Clements added that the grid will require tremendous investment in transmission, which “can ultimately be a net win for consumers.” However, Clements said, consumers are dependent on the commission’s “rigorous scrutiny of the rates charged for transmission service, of which ROE is a central component.” She worries that FERC’s ROE policy does not meet “this core consumer protection responsibility.”
“Smart transmission investment not only enhances reliability and resilience, but it unlocks low-cost power supply, allows more efficient use of existing infrastructure, and minimizes the cost of meeting changing customer demand and public policies,” Clements wrote.
New wind resource data for the Great Lakes is showing higher wind speeds than originally thought at potential spots for offshore wind development.
“This is a good result,” Walt Musial, manager of offshore wind at the U.S. Department of Energy’s National Renewable Energy Laboratory, said Tuesday.
Wind speeds in locations where wind projects might go on the New York side of Lake Erie and Lake Ontario average between 8.5 and 9 meters/second, Musial said during a public webinar on New York’s Great Lakes wind power feasibility study.
“We now have a 21-year record using ensemble-based analysis and an advanced weather research forecasting model that comes from the National Center for Atmospheric Research,” he said.
The new dataset replaces NREL’s Wind Integration National Dataset Toolkit for the Great Lakes, which used a seven-year record.
Higher wind speeds were found in new data for the Great Lakes, showing average speeds between 8.5-9 meters per second. | National Renewable Energy Labora
NREL’s analysis also found that the wind resource has “very little variability,” Musial said.
The New York State Energy Research and Development Authority (NYSERDA) is reviewing work that has already been completed for the feasibility study to produce a draft version before the end of the year, Sherryll Huber, project manager for offshore wind contracts, said during the webinar.
Last year, the New York Public Service Commission directed NYSERDA to identify the viability of Great Lakes wind energy as a resource. (See NY Kicks Off ‘Dynamic’ Great Lakes Wind Study.) NYSERDA expects to submit the final study to the commission early next year.
“Based on the findings of the study, the commission … will conclude if Great Lakes wind is a feasible addition to the state’s renewable energy portfolio, likely in 2022,” Huber said.
Ports
Lake conditions of Erie and Ontario will drive the turbine, vessel and port requirements for project development.
On Erie, Musial said, the water is shallower than in Ontario and will require fixed-bottom substructures that need heavy-lift vessels for wind turbine construction on the lake. Turbine size for Erie projects will be limited by the crane capacity of the vessels that can be on the lake.
Ontario, on the other hand, has deeper water and will “probably” require floating wind turbines, he said. Wind turbine assembly for floating turbines would take place in a port facility, and turbine size would be limited by the crane capacity at the port.
NREL reviewed four port possibilities for Ontario (Ogdensburg, Clayton, Oswego and Rochester) and three for Erie (Buffalo, Dunkirk and Erie).
With some upgrades, Oswego, Buffalo and Erie could accommodate OSW activities, Musial said.
Still to Come
NREL is still working on an economic analysis for the feasibility study.
Musial said the analysis will assume a project size of 600 MW, comprising 100 6-MW wind turbines, with locations yet to be determined. Costs for port upgrades and land-based connections will not be part of the project economics, and financing will be similar to projects already in development in the Atlantic.
NREL will customize its models for the specific conditions of each lake and run cost and sensitivity studies for a geospatial analysis and time-dependent parameters past 2030, according to Musial. The modeling, he said, will assume floating turbines for Ontario and fixed turbines for Erie.
In addition, NREL will conduct a jobs and economic development analysis. The results, Musial said, will calculate the actual jobs created by projects on the lake and the local revenues along with induced impacts of the workforce in local communities. An additional analysis will identify existing workforce availability and programs in the region that can train workers.
Extreme low temperatures remain a major threat to the Texas power grid in the upcoming winter months, according to NERC’s 2021-2022 Winter Reliability Assessment, while other regions face risks including natural gas supply disruptions and hydropower shortfalls.
February’s winter storms and the mass outages they caused across ERCOT, MISO and SPP are a natural focus in the report. John Moura, NERC’s director of reliability assessment and performance analysis, said the storms inspired an “innovative approach to our assessment [that] fundamentally changes the questions we’re answering as we perform our analysis.”
In a media call accompanying the release of the report on Thursday, Moura said that while all regions showed sufficient anticipated reserve margins — NERC’s traditional proxy for reliability — for the season, the events of February left the organization concerned that this metric was no longer adequate for a system increasingly comprising alternative types of generation like wind and solar power. Last year’s winter assessment showed adequate reserve margins but did not account for the failure of utilities in the south-central U.S. to prepare for unexpected extreme low temperatures. (See NERC Warns of Fuel Bottlenecks in Coming Cold Months.)
“Over the years, as the resource mix has changed, that measuring stick is not so useful anymore, because now we find that there’s not on-site fuel; that we can’t dispatch at will; that we have variable resources; that cold weather forces certain resources to come offline,” Moura said. He explained that for this assessment, NERC wanted to see how the grid might fare in the worst-case scenario, even if it is unlikely to happen.
“I think what we’ve done this year is say, ‘OK, instead of just looking at the things that happen most often, and [the] most likely thing to happen, let’s look at the tails, and let’s look at the worst things … that can happen and measure the resilience to them,’” he continued.
Severe Cold Dangers Persist in ERCOT
With February’s storms still fresh on everyone’s minds, NERC’s report identified severe cold weather as the most pressing concern in ERCOT, SPP and MISO.
For ERCOT, NERC warned that “resource derates for extreme conditions” similar to those seen in February could reach 28.1 GW, leading to a capacity deficit of up to 37.1%. This is despite the report finding that “operating plans for winter are in place,” based on responses to NERC’s Level 2 alert in August. (See NERC Issues Cold Weather Alert.) For MISO, conditions like those in February could cause a deficit of 1.2%, while SPP could see its reserve margin drop to 0.8%.
Seasonal risk scenarios for MISO, SPP, and Texas RE-ERCOT | NERC
NERC said that generator owners and grid operators’ “responses to questions about winterization plans and fuel coordination indicate that some plant vulnerabilities can be anticipated” this winter.
In an email to ERO Insider, Texas Public Utility Commission spokesperson Michael Hoke noted that the first phase of the PUC’s new weatherization rule, set to take effect Dec. 1, “requires generators to implement the recommendations that came out of the 2011 winter outages and to address the specific equipment failures” from February’s storm. (See Texas Senators Call for New RRC Weatherization Rules.)
He added that many of the recommendations in FERC and NERC’s joint report on this year’s storm “mirror the steps we have already taken to make sure the grid is more resilient this winter.” (See FERC, NERC Release Final Texas Storm Report.)
Additional steps taken by the PUC include designating natural gas facilities that supply power plants as critical infrastructure in order to avoid the gas supply shortfalls that caused many outages in February. Participants in Thursday’s media call acknowledged these efforts and said the goal of the report was to draw attention to areas where additional work can benefit more consumers.
“Our message is, the operator needs to be prepared to implement the plans, but relentless preparation is in order,” said Mark Olson, NERC’s manager of reliability assessments. “And if we follow that plan, the outages rates can be improved, and the situation [may] not be as catastrophic as was experienced earlier this year.”
Gas, Coal Shortfalls Possible
Hazards faced by other regions include limited natural gas infrastructure (WECC-California/Mexico and NPCC-New England) and limited water for hydropower because of the Western drought (WECC outside of Alberta and the Southwest Reserve Sharing Group). The potential gas shortfalls in NPCC-New England are because the fuel is used for both heating and electric generation, creating the possibility of bottlenecks in the region, while those in WECC-CAMX are because of limited storage capability.
Assessed unavailable capacity caused by insufficient weatherization plans | NERC
Global supply chain problems have also led to challenges in obtaining fuels; NERC noted that coal stocks in particular “have trended quickly downward in the last few months … after a buildup since last winter” and are at their lowest point in more than 10 years. While Olson said this level is “not an immediate concern for BPS reliability,” he said owners of fossil fuel-fired plants should monitor the situation closely because “late-state acquisitions this winter could be particularly challenging.”
NERC recommended several steps to reduce the risk of outages this winter:
Grid operators, generator owners and generator operators (GOPs) should review NERC’s cold weather Level 2 alert and take recommended steps before winter arrives.
Grid operators should prepare operating plans to manage potential supply shortfalls and take proactive steps for generator readiness, fuel availability and sustained operations in extreme conditions.
Balancing authorities and reliability coordinators should conduct drills on alert protocols, while BAs and GOPs should verify protocols and operator training for communication and dispatch.
Distribution providers and load-serving entities should review non-firm customer inventories and rolling blackout procedures to ensure that critical infrastructure loads such as gas and telecommunications are not affected.
