All but one ERCOT system generating resources have submitted their winter readiness reports, part of the state’s new requirements, the grid operator’s staff said Friday in a filing with the Public Utility Commission.
ERCOT said it had received 828 of 847, or 97.8%, of the total readiness reports that were required to be submitted by a Dec. 1 deadline. Another 18 reports were received by close of business Thursday, leaving only Rippey Solar, an 81-MW facility in North Texas, unaccounted for.
Rippey Solar is owned by BT Cooke Solar, one of eight generation companies recently fined for failing to provide winter readiness reports by the Dec. 1 deadline. (See “PUC Docks 8 Generators,” Texas PUC Chair Lake: ‘The Lights Will Stay On’.)
ERCOT staff noted 244 resources asserted good cause of non-compliance as of Thursday but said that after reviewing about 70% of the exception requests, “ERCOT does not believe [the assertions] should be taken as an indication that 244 generating units are wholly unprepared for the winter peak period.”
Staff said the attestations include about 25 separate winterization elements, such as enclosing sensors. “Many good-cause assertions identify a failure to comply with only a small number of these elements, but otherwise suggest compliance with the rule.”
Many of the good-cause assertions reviewed by ERCOT “reasonably asserted” that some requirements do not apply to the resource while others proposed a quick timetable to reach compliance.
“For these reasons, ERCOT would caution against an inference that a significant number of generators should be considered unprepared for winter based solely on the number of good-cause assertions,” staff said.
Austin Energy, which filed exception requests for all 13 of its generating resources, told RTO Insider it is making additional improvements based on its experience during February’s winter storm, and it expects the majority of its measures to be completed by the end of the year.
“That work is ongoing because either a unit at the plant site is undergoing planned maintenance that precludes completion of the step until the maintenance outage concludes and/or a contractor scheduled to perform winterization work could not complete the work until after Dec. 1,” a spokesperson said.
The utility noted it was able to maintain operations during February’s cold snap because of its prior weatherization efforts.
“The reports and the requests for exception are having the desired effect of increasing accountability and giving regulators more visibility into weatherization efforts,” the PUC said in a statement.
The commission and ERCOT must both sign off on the exception requests.
The new rules are a result of legislation following the February winter storm, when about half of ERCOT’s thermal generation fleet was rendered unavailable by the freezing temperatures.
Generation owners must implement winter-weather readiness recommendations from a post-event analysis of a 2011 winter weather event and fix any “known, acute issues” from last winter (51840). The generation owners’ highest-ranking executives were required to file notarized attestations that the resource has met its required actions by Dec. 1. (See “Weatherization Rule Published,” PUC Workshop Takes First Stab at Market Changes.)
Dispatchable generators submitted 520 of 530 reports (98%) on time, while 308 of 317 (97%) intermittent resources met the Dec. 1 deadline.
The NEPOOL Markets Committee will vote in January on two proposals to modify ISO-NE’s generator retirement rules, which the proposals’ sponsor contends are “the most onerous and difficult … in the country.”
Sigma Consultants’ William Fowler told the committee Thursday that his proposals would address New England’s large generation surplus. Fowler says the RTO’s plans to eliminate the minimum offer price rule (MOPR) is likely to cause an influx of new state-sponsored resources, which could exacerbate the surplus without rules to enable efficient exit. (See Monitor, Merchants Challenge ISO-NE Plan to Eliminate MOPR.)
Under current rules, retirement bids are due in March, 11 months before the annual Forward Capacity Auction, and cannot be updated to reflect changes that occur between then and the FCA. “This adds significant, unnecessary risk to the process,” Fowler said in a presentation.
He proposed allowing bids to be updated prior to the auction in mid-October, as is permitted for static delist bids.
Offer prices could be no more than 25% below the initial submission. Upward adjustments would not be permitted.
Fowler said he will seek an MC vote on his proposal at its Jan. 11-12 meeting, immediately after it votes on the MOPR elimination. He said the bid flexibility rules would be contingent on FERC eliminating the test price for Competitive Auctions with Sponsored Policy Resources along with the MOPR or a transition package.
Fowler said he hopes the new rules will be filed with FERC prior to the March bid submission deadline for FCA 16, allowing a commission order before the June auction election deadlines. He also plans to seek an MC vote at the same meeting on a second proposal intended to create a “meaningful” mothball option.
Examples of how bid modification would work. | Sigma
Current rules require generation owners seeking to temporarily take a unit out of the capacity market to “string together a series of one-year delists,” Fowler said. “But that has many limitations. Also, once retirement is accepted, [there is] no meaningful way to return to service if there are major regional changes.”
He proposed modifying the “repowering rule,” which requires that the generation owner make a minimum financial investment in the plant to re-enter the market. He also suggested a three-year waiting period — including two consecutive FCAs after the one in which it retired — calling it a “reasonable balance.”
“Three years is [the] longest waiting period that can allow for changed circumstances before risking permanent actions that may frustrate [the unit’s] return,” he said. A shorter waiting period could allow generators to “toggle” into and out of the market, “fishing” for a reliability-must-run designation entitling it to cost-of-service compensation.
Fowler has withdrawn a proposal to eliminate a rule that requires resources that submit retirement bids and fail to clear in that FCA to continue submitting retirement bids until they do clear. He also has withdrawn a proposal to relax Internal Market Monitor reviews in certain situations.
Increased Penalties for Failed Capacity Resources
Competitive Power Ventures will early next year put forward its proposal to increase financial penalties for capacity resources that fail to reach milestones prior to their delivery year and commercial operation.
CPV will be seeking votes at the next Budget and Finance Subcommittee meeting Jan. 26 and at the succeeding MC in February, said Joel Gordon, CPV’s vice president of external and regulatory affairs.
Gordon said existing financial assurance (FA) requirements, designed to keep barriers to entry low, are insufficient to ensure that resources that win capacity supply obligations (CSOs) actually deliver.
Current rules do not distinguish between a project meeting all its milestone commitments, a delayed project and a totally failed project because there are no financial penalties until after the resource has failed to meet its commercial operating date (COD).
He cited ISO-NE’s Nov. 4 filing asking FERC to terminate Killingly Energy Center’s CSO for FCA 16, after the developer failed to advance its project despite participating in three consecutive auctions, FCAs 13 to 15. (See ISO-NE Seeks to Terminate CSO for Conn. Power Plant.)
Failed capacity projects impact other capacity sellers by artificially increasing apparent “supply,” reducing clearing prices and increasing performance risks, he said. He said Killingly’s failure reduced clearing prices by a total of $380 million over three auctions, an average of 31 cents/kW-month.
Currently, the RTO collects a “base” FA — equivalent to one month of net cost of new entry (CONE) — prior to the primary FCA and before the first and second subsequent auctions.
Following a failed project in FCA 10, the RTO also added a “trading” FA that collects any positive trading revenue from resources that engage in “cover” transactions for their CSOs.
CPV proposes to add a “milestone” FA for projects that don’t meet pre-COD obligations and a “delay” FA for projects that fail to meet their obligations at their commitment date:
Resources that have not achieved their financing milestone or their demand reduction value before the first subsequent FCA would be required to post an additional one month of FA.
Resources that have not achieved substantial site construction or achieved their demand reduction value before the second subsequent FCA would be required to post an incremental two months of FA (three months total).
Resources that have not achieved substantial site construction or achieved its demand reduction value before the third subsequent FCA would be required to post an additional three months of FA (six months total).
All milestone FA would be released upon catchup to active construction; projects that meet their commitments would face no increase in FA requirements.
Forfeited FA payments from the new requirements would be distributed pro rata to other CSO holders. Forfeited base and trading FA would continue to be allocated to load, as under current rules.
IMM Reports Summer Energy Costs up 48%
A large increase in natural gas prices and slightly higher loads pushed New England wholesale energy costs up by 48% last summer compared to the same period a year ago, according to the ISO-NE Internal Market Monitor’s quarterly markets performance report.
Wholesale market costs totaled $2.19 billion, up $710 million from summer 2020, according to the report presented by Donal O’Sullivan, IMM supervisor of surveillance and analysis.
The year-over-year increase was large because summer 2020 saw historically low natural gas prices as a result of warmer weather and reduced consumption from the pandemic-driven economic shutdown.
Average day-ahead and real-time hub LMPs were $41.29/MWh (+84%) and $40.22/MWh (+79%), respectively. The average natural gas price was $3.39/MMBtu, more than double the summer 2020 price of $1.62/MMBtu.
The average hourly load of 15,298 MW was up by 0.3% (320 MW), driven by increased humidity and less behind-the-meter solar generation. Capacity market costs totaled nearly $530 million, down by $73 million (-12%).
Summer 2021 was the first quarter of the FCA 12 commitment period, with clearing prices of $4.63/kW-month for Rest of System, compared to an FCA 11 price of $5.30/kW-month.
Gross real-time reserve payments more than doubled to $9 million.
Ten-minute non-spinning reserve (TMNSR) and 30-minute operating reserve payments increased by $1.9 million and $432,000, respectively.
Non-zero TMNSR pricing occurred in 386 hours in summer 2021, down from 506 hours. However, the average non-zero spinning reserve price increased from $9.81 to $14.27/MWh.
Total regulation payments were $7.6 million, up 19%.
The higher average real-time hub LMPs led to a $1 million increase in regulation capacity payments.
Net commitment period compensation (NCPC) costs totaled $10 million, up $3.1 million (+44%). But as in summer 2020, NCPC costs represented less than 1% of total energy costs. Economic payments made up 77% ($7.7 million) of the total, up by $2.1 million from the same period a year ago.
Economic out-of-merit payments increased by 34% to $4.98 million. Local reliability payments were $1.6 million, up 72%.
Maine officials are looking at beginning a phased offshore wind procurement process following an anticipated 2024 Gulf of Maine federal lease sale, Celina Cunningham, deputy director of the Governor’s Energy Office, said Monday.
“What we are seeing from the energy needs for the region and the state is that, over the long term, OSW will be an important part of our energy mix to meet our clean energy and emission-reduction requirements,” Cunningham said during a Maine Offshore Wind Roadmap Advisory Committee meeting.
Cunningham presented the Energy Markets and Strategies Working Group’s initial roadmap recommendations to the full committee, saying an OSW target should accompany the procurement.
The U.S. Bureau of Ocean Energy Management (BOEM) announced plans in October for seven potential new OSW lease sales by 2025, including one in the Gulf of Maine. BOEM said it could designate a gulf wind area by mid-2023 and hold a lease sale in the third quarter of 2024.
The working group expects to finalize an energy needs analysis before identifying what it believes Maine’s OSW target should be, according to Cunningham, who added that pursuing a cost-effective energy strategy for the state is a priority.
Based on water depths, OSW development in federal waters of the gulf will require floating wind turbine technologies. The current floating wind market, however, is small, totaling 79 MW of installed capacity, according to the U.S. Department of Energy’s 2021 Offshore Wind Market Report.
By 2050, DNV estimates the U.S. will have 279 GW of OSW, and 47 GW of that total would be floating, Principal Consultant Ari Michelson told the committee. DNV has been supporting the working group with analyses on OSW potential for Maine.
Floating OSW development likely will not kick off significantly in the gulf until 2040, and it could more than triple in size by 2050, according to Michelson. DNV is currently finalizing its estimates for floating wind capacity in 2040 and 2050 for the roadmap.
In addition, he said the global levelized cost of energy (LCOE) for floating wind should drop rapidly through 2030, potentially hitting $39/MWh for the gulf in 2050. Globally, the average LCOE of fixed-bottom OSW installations is $95/MWh, according to the DOE report. Mayflower Wind has one of the lowest-priced OSW projects in the world at $71/MWh.
The committee heard initial recommendations from three of its working groups Monday, with additional recommendations still to come from the Fisheries Working Group in January. After taking feedback from stakeholders early next year, the working groups will present refined recommendations to the committee in July. The final roadmap is due in December 2022.
Supply Chain and Workforce
Maine should be connecting with the international OSW market as the state builds out its assets in the coming years, Steve Von Vogt, executive director of the Maine Composites Alliance, told the committee.
“We would like to see advocacy on the part of the state through its policies and economic outreach for Maine’s firms and industry, ports, workforce and excellent R&D related to offshore wind,” Von Vogt said in a presentation for the Supply Chain, Workforce Development, Ports and Marine Transportation Working Group.
The group’s initial recommendations included establishing a “commissioner-level industry advocate.”
The state needs a “consistent and high-level strategic effort to align Maine’s assets across industry, R&D, education and workforce development, to market opportunities,” Von Vogt said.
To accomplish that, the group suggested that the state “formally establish clear state policy supportive of OSW” and “announce an OSW goal or mandate.”
Developing Maine’s OSW workforce may require the state to ensure that students are engaged early in understanding the long-term opportunities for the industry, said Jonathan Poole, large business development manager at the Maine Department of Economic and Community Development.
To do that, Maine can expand STEM education for K-12 and continuing education students, Poole said in a presentation to the committee. The state, he said, also could increase OSW opportunities in post-secondary education by replicating its successful efforts to generate talent in the pulp and paper industry.
In addition to promoting the University of Maine’s long-term work on floating wind technologies, the state also could leverage its existing maritime sector programs, according to Poole.
“Improving the professional certifications in the maritime sector is what is going to be required by a lot of OSW developers and operators coming into the gulf,” he said.
Wildlife
Among the Environment and Wildlife Working Group’s top priorities for the roadmap is a drive to ensure that the state is prepared to communicate its needs to the federal government in the OSW citing process for the gulf.
There is a lack of data for the gulf; the existing data are old; and the gulf’s environment is in flux because of climate change, said Wing Goodale, science director at the Biodiversity Research Institute.
With that in mind, the group’s initial recommendations include using existing data to begin identifying areas of greatest conflict and the data gaps that need filling to inform OSW leasing, Goodale said. With input from science and fishery experts, the maps can be updated over time.
The group also wants to investigate Maine’s authority under the Coastal Zone Management Act (CZMA) to review federal activities that could affect the state’s coastal areas. The CZMA may provide the state with opportunities to address “issues of concern” regarding OSW development in federal waters, and the investigation could lead to potential changes in state laws, Goodale said.
Independent power producers warned Monday that policymakers are risking reliability by attempting to transition too quickly from gas and coal — and they said the consequences could be felt in New England this winter.
“We really shouldn’t just … pave the ground with solar panels and then deal with the consequences after you’ve shut down all of your gas projects, like we saw in California,” Gary Lambert, CEO of Competitive Power Ventures, said during a panel discussion at the New England Power Generators Association’s (NEPGA) New England Energy Summit in Boston. “We have to … have a market that compensates us appropriately to keep the reliability resources around.”
Sarah Wright, founder and managing partner of Hull Street Energy, a mid-market private equity firm, said it is “premature” to focus on retiring thermal generation. “You see it in California — the effects of this fictitious narrative that says, ‘All we need to do is install solar panels and batteries and we’ll be fine.’ That is a nice political story, but it’s not actually true,” she said.
Himanshu Saxena, CEO of Starwood Energy Group, noted that renewables only comprise about 20% of the 1,000 GW of installed capacity in the U.S., with coal and gas representing about 600 GW.
“In the best of times, this country installed 20 GW of renewables on an annual basis. So if the best of times continued, it will take 30 years to replace [thermal generation], and this is not even [considering the lower] capacity factor” of renewables, he said. “Everybody has to be realistic about how fast this change is going to happen.”
When Curt Morgan became CEO of Vistra (NYSE:VST) in 2016, he said the company’s generation was more than 70% coal. “And investors that we had were pretty comfortable with it,” he said.
After studying the subject, Morgan said, he and the board of directors concluded that climate change was real and they needed to change the company’s trajectory. It has pledged to reduce its carbon emissions by 60% from 2010 levels by 2030.
“Maybe that sounds simple to everybody in this room. But that was a huge thing for our board to accept and understand with over 70% coal [generation]. And so that put us on a path of not denying, but actually participating” in the transition away from fossil fuels.
“We’re the kind of company that policymakers should want, because we’re doing the responsible thing. We’re helping the three pillars: reliability, affordability … and [reducing] emissions,” Morgan said. “But it’s going to take us some time to do this transition. And we can’t sacrifice one of those three pillars to get there. And so I tell policymakers this all the time: ‘We’re not the guys that you ought to be throwing darts at. We’re the ones that you ought to be supporting, because we are going to be the ones that will help this transition.”
Cash Flow, Financing Challenges
Saxena said cash flows for gas and coal assets have become less predictable because of volatility in capacity prices, making it harder to raise debt or equity to fund the plants.
“You take something to market … if you have any green halo on it, you’re trading at 20 to 40 times EBITDA [earnings before interest, taxes, depreciation and amortization],” he said. “But the capital market community hates coal. So getting everything from insurance for that asset to getting refinancing done is really, really hard.”
Lambert said the influx of zero-cost resources could make it increasingly difficult to keep thermal plants operating. “So then you’ll see a bunch of shutdowns. And we’ll go back to RMRs [reliability-must-run contracts], and that’s the world that we don’t want to go back to, 2003-2005; everything was being run on cost-based RMRs.”
Morgan said his normal optimism is being tested. “I am always a positive person, but I am very concerned that in the next 10 years, it’s going to be a bumpy ride, because we’re relying more and more on government intervention to get our rents.
“PJM did a study that said that, with 50% penetration of renewables, they need a 70% reserve margin. Yet we’ve got people wanting to … literally drive assets out of the market. When I talk to regulators, reliability doesn’t even come out of their mouth. I have to raise it. It’s all about emissions.
“When you allow those things to come out of balance — reliability, affordability and emissions — you’re going to have California, which was driven by a lack of reliability, and Texas, which was driven by too much emphasis on affordability and a lack of focus on the fact that … intermittent resources” create new reliability challenges.
Morgan said the U.S. may need to adopt Australia’s solution of two markets: one for new renewables, and a residual market for dispatchable fossil fuel generators. “I’d hate to see us go there. But I don’t know how [else] we get there,” he said. “The markets are just not functional right now. … The ISOs have knuckled under to political pressure. And they’re not speaking what they believe. I think they’re saying what the politicians want to hear. And that’s dangerous, because … they’re the ones that are going to make sure whether this thing works or not. So we need them to speak up about their grids. And I’m concerned that they are not doing that.”
Increasing Gas Prices, Availability Concerns
In the short term, the speakers said, the increasing price of natural gas and its limited availability are a threat to New England’s energy security.
“So far, it has been a warm winter, and we may skirt through, but prices are certainly projected to be very high in the region,” Lambert said. New England would benefit from a new pipeline that could bring in cheaper gas from outside the region, “but that’s very, very difficult, if not impossible, to get done.”
The increasing globalization of natural gas prices through LNG also is a concern, Wright said. “Algonquin [Gas Transmission Pipeline] prices are high right now because we think it’s going to be cold in China,” she said. “That’s mind-blowing after decades of focusing on gas as a very local matter.”
Saxena said that although his company has firm gas transport agreements for many of its New England assets, “it’s not 100%. And [additional] firm transport is just not available. … There is no price at which you can buy firm gas in this market.”
ERCOT failed during the February winter storm “not because the generation wasn’t there; it failed because gas wasn’t there,” he said. “New England is going to have the same issue.”
Constraints in gas supply in the region will become more challenging as New England states push more renewable resources onto the grid, Morgan said.
“I think New England is the next region to be at risk [of a major blackout] with a lot of focus on offshore wind and a bitter hatred toward gas,” he said. “I know that we’ve got some challenged gas assets that really are going to be needed for reliability reasons, given the intermittency of all the offshore wind coming.”
The New England Electricity Restructuring Roundtable on Friday discussed storage and hydrogen as possible pathways to fully decarbonize the Northeast, including using both technologies in electric power production, transportation and buildings.
The keynote speakers presented views from neighboring New York and Canada, with Jonatan Julien, Québec Minister of Energy and Natural Resources, appearing in a pre-taped video to share the province’s new strategies to produce green hydrogen with hydropower and to develop batteries from indigenous lithium, aluminum and hydro resources.
Regional Approach
“Québec has the potential to be a world leader in renewable energy production and a team leader in decarbonizing the Northeast,” Julien said. “We share the same ambitions for a greener and a more sustainable energy future because we know that climate change knows no borders.”
As proof of the province’s role, Julien referred to New York in November having finalized a contract with Hydro-Quebec Energy Services for the Champlain Hudson Power Express to carry Canadian hydropower all the way to New York City. (See Two Transmission Projects Selected to Bring Low-carbon Power to NYC.)
Dominique Deschenes, Québec Deputy Minister of Energy and Natural Resources, appeared live and clarified that the province will not be manufacturing batteries but wants to invest in in a complementary sector for the manufacture of specialty electric vehicles such as emergency vehicles or fire trucks, and to develop the province’s role in a battery recycling logistics chain.
Clockwise from top left: NYSERDA CEO Doreen Harris; Jonathan Raab of Raab Associates; and Dominique Deschenes, Québec Deputy Minister of Energy and Natural Resources | Raab Associates
On the role of green hydrogen in her province, Deschenes said, “Hydrogen is for us to use where we cannot use direct electricity.”
The Quebecois see green hydrogen being used for heating buildings, but especially for transportation and industry because of sectors like mining that cannot easily use electricity, she said.
“Hydrogen also goes with bioenergy [and] for 2030 we have a target of 37.5% GHG emissions reduction and we think that almost 15% of this reduction will be done with bioenergy and green hydrogen,” Deschenes said.
New York is ahead of schedule on its solar and energy storage targets and is also participating in several national and global groups focused on hydrogen, said joint keynote speaker Doreen Harris, CEO of the New York State Energy Research and Development Authority (NYSERDA).
For example, New York is collaborating with the National Renewable Energy Laboratory on a hydrogen strategy study to compile baseline information and data that will help to determine the role green hydrogen could play in the state’s decarbonization plans, Harris said.
In July, NYSERDA made $12.5 million in funding available for developing long-duration energy storage solutions that are six-plus hours in duration.
The state also is working with the Center for Hydrogen Safety, a global community of more than 75 government, industry and national lab participants promoting and learning about hydrogen safety and best practices across industrial and consumer applications, she said.
“We have also joined the HyBlend collaborative research partnership, which is comprised of six national labs and 15 university and industry partners co-led by NREL and Stony Brook University,” Harris said. “This national partnership will generate a database that allows New York to access the use of existing infrastructure and to develop general principles of operation of blended hydrogen and natural gas delivery systems.”
NYSERDA is looking to leverage the state’s regional clean energy hubs with funding focused on carbon capture and clean hydrogen, which is part of the Infrastructure Investment and Jobs Act, she said.
“This federal context is a very critical one for us as a state,” Harris said. “We see great alignment in the broader policies, but also a huge opportunity to capture those federal investments as we make New York the hub … for this burgeoning industry.”
In addition, the state target of 9 GW of offshore wind by 2035 is “only the beginning,” and will likely double, with plenty of opportunity at low load times to use that relatively low-cost power to produce green hydrogen, Harris said.
Strategy and Policy
Decarbonizing the Northeast can be thought of as a battle between how much and how fast renewable generation can be developed and how that can offset GHG from fossil fuel resources, said Paul Hibbard, principal of Analysis Group.
The concern is that no matter how many thousands of gigawatts are generated from wind and solar there will be times when those technologies are unable to generate enough power to meet demand. And as electrification of the economy grows, such as with adoption of electric vehicles and electric heat pumps, those shortfalls could become big problems.
And that’s why current hydrogen R&D projects are “incredibly important,” said Hibbard. The energy density and phase flexibility of hydrogen make it easily transportable and potentially able to take advantage of existing pipeline and fuel storage infrastructure, he said.
Utilities and wind developers could “overbuild” wind and solar projects and produce hydrogen, which could then be stored and used as a “ramping resource,” whether burned in a combustion turbine or used in fuel cells to help stabilize the grid, Hibbard said.
The major question is whether green hydrogen will be cheap enough to be economic, Hibbard said.
Notwithstanding that question, National Grid, which delivers gas and electricity to 20 million customers across the Northeast, intends to distribute renewable (bio) natural gas and green hydrogen as part of a master plan to get to net zero carbon emissions.
“In some ways our gas network is the largest storage system we have, and through clean, net-zero fuel we see that as a way to provide value to our customers,” said Judith Judson, head of U.S. strategy at National Grid.
Hydrogen will interconnect large scale renewables with a modernized grid, she said.
“The magnitude of growth in clean electric generation needed to get to net zero across New England and New York will require hydropower, 25 gigawatts of onshore wind, 40 gigawatts of offshore wind and over 50 gigawatts of solar,” Judson said.
Energy storage, whether batteries or stored hydrogen, will be the “glue” that holds the system together, she said.
“We’re excited about storage as a transmission asset. It [provides] the opportunity to increase both the capacity of our existing infrastructure and improve the resiliency of the network by acting as a backup to the network,” Judson said.
Hydrogen may face competitive hurdles as a grid storage system, said Audrey Zibelman, vice president of of Tapestry, X’s moonshot for the electricity grid.
Zibelman stepped down as chair of the New York Public Service Commission in 2017 to serve as CEO of grid operator Australian Energy Market Operator, before returning early this year to the Google venture, X.
As for hydrogen as a method of long-term storage, the Australian grid operator decided pumped hydro was more cost effective than hydrogen storage, at least initially because of the cost of green hydrogen, she said.
Green hydrogen’s role in long-duration storage depends on reducing the cost, including the cost of electrolysis equipment used to make hydrogen from water.
“If we are talking about a 1-in-10-year event, where we need long duration storage, for days as opposed to just hours it’s going to become a very difficult market,” Zibelman said.
The answer might be something in the form of a storage reserve, like an oil reserve, but how would someone invest in something that might only be used once in four or five years, she said.
“We have probably not exhausted the DER side in terms of resources to make the grid itself much more efficient,” she said.
Probably the easiest market for hydrogen would be where gray hydrogen is now used, in heavy industry and refineries, Zibelman said.
Case Study Storage
The final panel featured storage and green hydrogen case studies in the power, transportation and building sectors.
Form Energy developed a sophisticated suite of analytics, which allowed it to run very complex technology-neutral investment and operational models for power grids.
Iron is cheap and abundant, two features that enable the company to project it will hit very aggressive cost targets, said Form Energy CEO Mateo Jaramillo.
“We are delivering our first material commercial project in a few years, so by the end of 2023 we will turn on our first pilot project, a roughly 1-MW, 150-MWh battery storage, hundreds of hours of duration for a transmission distribution co-op in Minnesota called Great River Energy,” Jaramillo said.
Form Energy developed a sophisticated suite of analytics that allow it to run complex cooperation problems. The company is today running integrated resource plans alongside the utilities that it’s talking to, so that when those utilities examine their future system needs and asset mix, “we’re able to inject the different types of technologies that may show up and compare them in a financial model,” Jaramillo said.
Mike Hill at FERC asked about the market barriers to deploying long-duration storage.
“The simplest response is that we need to price reliability,” Jaramillo said.
Case Study Transit
Toyota’s various hydrogen fuel cell initiatives are geared toward everything from light- to heavy-duty vehicles, buses, boats and stationary generators, and particularly to eventually power heavy-duty trucks, said Douglas Moore, the automaker’s general manager in the U.S. for fuel cell solutions.
Meanwhile, the world’s largest carmaker is making progress on relieving consumer range anxiety with fuel cell technology.
“Just a couple of months ago we had a hyper-miler run our second generation Mirai in Southern California, and he achieved a Guinness record of longest distance traveled by a fuel cell vehicle. So he was able to go 845 miles on a single fill-up,” Moore said.
Toyota started fuel cell infrastructure development in California and has partnered with a number of station providers, including including First Element, Air Liquide, Shell and Iwatani, to supply fuel and Shell for distribution. There are 49 stations open and more than 120 under development, mainly in the Bay Area, Los Angeles and San Diego, and in the Lake Tahoe area, he said.
Toyota is working to expand fuel cell markets across the country, with areas of promise being Colorado, Texas, the Pacific Northwest and the Northeast.
“On developing the light-duty vehicle refueling infrastructure, what would be the main factors in Toyota’s determination of which if any of these other markets to enter … and how much would the availability of green hydrogen from offshore wind or hydro in the Northeast influence such a decision?” said Roundtable organizer Jonathan Raab.
Moore said that California has obviously been a favorable state from a policy perspective, and developing fuel cell refueling infrastructure has its own challenges. “By sprinkling it around you’re creating a lot of little hotspots that could potentially have failure without backup,” he said.
Toyota concentrated in California on solving the whole equation, from supply to distribution to station provider — driven by supportive public policy. In the Northeast, “culturally I think there’s a huge alignment as well … a strong desire to have green hydrogen and carbon neutralization here,” Moore said.
Case Study Power
Vicinity Energy plans to decarbonize its district energy system, which serves more than 65 million square feet of buildings and facilities in Boston and Cambridge, through a combination of renewable fuels, hydrogen, large scale heat pumps and storage.
District energy is a force multiplier, a way to get inside a building and alter that building’s carbon profile without having to make significant changes or any changes in the building at all, said Kevin Hagerty, chief technology officer of Vicinity Energy.
The company owns about 26 miles of steam piping underneath Boston and Cambridge, and three central facilities situated on the backbone power grid, all serving the equivalent of 55 Prudential Towers.
“If we make a change on just one of our facilities, if we make a small fuel change or small changes to our producing that steam, it alters the carbon profile of all the buildings connected to the district energy system,” Hagerty said.
The company is achieving electrification by installing electric boilers, industrial heat pumps, and thermal batteries, and hopes to take “a big bite out of the Boston and Cambridge carbon emissions” and decarbonize upwards of 800,000 metric tons per year by 2035, Hagerty said.
Industrial heat pumps will leverage heat from the adjacent Charles River, and thermal batteries will help the company improve district energy’s existing good alignment with peak generation from the offshore wind that’s soon coming onto the New England grid, he said. Offshore wind, like heating, peaks in the winter, and its daily production peak from 8 p.m. to 4 a.m. would offer Vicinity low-cost power for its load peak, which is precisely opposite the OSW production peak hours.
The flood of federal dollars authorized by the passage of the Infrastructure Investment and Jobs Act is expected to accelerate clean energy projects, enable utilities to build out infrastructure and sharpen state competition for economic development.
The enormous possibilities have not been lost on the Missouri Energy Initiative, a 12-year-old think tank with a mission to accelerate development in the Show Me State.
MEI’s annual two-day economic development meeting, conducted virtually Dec. 8-9, examined the role utilities played in two economic development projects in the service areas of two Missouri utilities, Ameren Illinois and Evergy.
During the session, MEI unveiled a new report on the extent of electric vehicle charging infrastructure in Missouri, launching an in-depth panel discussion about the pitfalls and expenses of a mass EV charging buildout and what that will mean for the state.
MEI also invited the head of supply chain at Swift Prepared Foods to discuss the company’s expansion and the role played by utilities in site selection that kept the expansion in-state.
Swift Foods, owned by Colorado-based JBS USA Holdings, has 60 meat processing plants in 28 states. More expansion is expected.
In a separate panel, a development director with Evergy discussed how the state landed an 800,000 square-foot logistics center built by Chewy, a pet food company. The project will ultimately employ more than 1,600.
The conference also looked at a new cobalt mining operation in the state, built on the remains of a retired lead mine that had been declared a Superfund Site by the U.S. Environmental Protection Agency. Opened in the 1840s, the mine has sat dormant since the 1980s.
Most of the cobalt used in storage batteries is mined in Africa and processed in China. Missouri Cobalt aims to supply North American battery builders, said John Diehl, Jr., the company’s general counsel. He said the company is planning to open a hydrometallurgical plant in 2022 to produce battery-grade cobalt sulfate.
Virtual attendees also got updates on the state’s efforts to identify a consensus on a new state energy development plan and a few details on the expected rollout of funding that will be made available by the passage of the bipartisan federal infrastructure bill, which President Biden signed into law on Nov. 15. (See Biden Signs $2 Trillion Infrastructure Bill.)
Utilities Play Crucial Role
JBS USA earlier this year committed to reduce its greenhouse gas emissions 30% by 2030 and 70% by 2040, with the ultimate goal of net-zero emissions.
Joe Machetta, Swift Prepared Foods | Missouri Energy Initiative
“It’s really more about building in the energy efficiency, whether it be lighting or [using] clean energy,” said Joe Machetta, head of integrated supply chain for Swift Foods.
The company wanted to build a new bacon plant and started its search for a site with a list of over 90 locations, Machetta said. But electricity was a key issue.
“One of the key things for us was obviously the utilities,” he said. The company decided to build the $68 million plant in Moberly, Mo., creating about 200 new jobs.
“The [economic development incentive] offered by Ameren was clearly critical, and it really pushed Moberly over the edge,” he said, referring to a 40% rate discount the utility was able to offer the company for five years.
“The utility spend this year will be close to a million dollars. Next year it will be north of $2.6 million just in utilities for keeping the lights on and operating the process,” Machetta said.
Chewy’s new logistics and e-commerce fulfillment center that opened this year in Belton, Mo., is another success story for the state in which another utility, Evergy, played a key role.
Lisa Franklin, Evergy | Missouri Energy Initiative
Lisa Franklin, lead economic development manager at Evergy, said the community reached out to the utility because it had not had much luck attracting new development.
“Our energy economic development team — along with the city — conducted a competitive analysis to determine what they needed to position themselves to be competitive globally.
“I think this may be where we’re a little bit different in energy. It’s like putting your house on the market. You know you have some major issues that need to be resolved before you can successfully sell it,” she said.
“We went through an actively competitive assessment. We performed a site identification study. That was us going out and helping them locate a site where an industry would actually want to locate. This happened to be on a major interstate. After that was done, we went through a site due diligence analysis, and that was a research project that allowed us to look at all of the infrastructure needs, whether it was electric, gas, water, sewer,” Franklin said.
Chewy chose Belton over cities in other states and opened the fulfillment center last summer, which is expected to develop a workforce of up to 1,600 employees.
Franklin said the development team is now working on two other projects, each expected to draw 250 MW of demand.
“These are very, very large projects. Ten years ago, we would never see anything that large, but today it’s like everything that’s coming to the door happens to be a very large project. That’s becoming a big issue for us because we’re having to build up infrastructure to meet those demands.”
Job Training Is Key
Job training has become another critical ingredient in economic development as technology has transformed manufacturing. And since the pandemic began, an unexpected new phenomenon has only added to the problem: the “Great Resignation.”
Rosa Schmidt, Center for Energy Workforce Development | Missouri Energy Initiative
“I still remember the time when we were in the single digits, and people would start with our companies and leave from our companies,” said webinar participant Rosa Schmidt, an analyst with the Center for Energy Workforce Development, a nonprofit consortium of nearly 120 utilities. The center’s mission is to take the pulse of the industry’s workforce and issue comprehensive biennial reports
The latest analysis reveals that “64% of folks leave within the first five years. Think about the impact on the industry when you have almost 65% of the population that you hire, spend time and energy to educate and train, and within the first five years they’re walking out the door. This is a major issue for our employers.”
More disturbing, she said is that 19% of people with more than 10 years of service are also leaving their jobs. Almost half of those are … over the age of 53, and 43% are between the ages of 38 and 52. It’s the Great Resignation.”
Added to that problem is that technologies are changing, making it difficult for utilities as well as technical schools and unions to prepare for the future, especially one that will be decarbonized.
Ben Berhorst, Missouri Technical College | Missouri Energy Initiative
The center has been working with several consulting firms in an effort to figure out what job skills utility workers will need in 2035, Schmidt said.
“A lot of our [corporate] members are really struggling with technology because of the way that things are changing. The center is working to develop a ‘competency model’ for future workers.
“We don’t know what that’s going to look like, what knowledge and skills they will need. And so we are going to be working on developing some tools and resources and an assessment for workers of the future,” she said.
Ben Berhorst, dean of the Division of Technology at the State Technical College of Missouri, said the staff there is also trying to develop an energy technology program to account for power plant technology moving from fossil generation to renewable technologies.
Nicole Fondren, Spire | Missouri Energy Initiative
Nicole Fondren, manager of talent acquisition and workforce development at gas utility Spire, pointed out that people today already deal with technologies in everyday life as well as on the job.
“We have a lot of technology that the field [employee] has to use, whether it’s drones or whether it’s utilizing a computer system in the [work] truck. … It’s a learning curve. It’s a change that management has had to face, with individuals who never had to use technology before but are now having to use it,” she said.
Missouri along with the rest of the nation is on the cusp of one of the most significant changes in decades: the electrification of everything from industry to residential to transportation. That also is expected to increase demand for new and comprehensive job training to build out the necessary infrastructure.
EV Charging Stations the Catalyst
EV charging stations are more common in Missouri’s metropolitan areas, but given the predictions of EV growth, that will have to change.
Travis Wood, Missouri Energy Initiative | Missouri Energy Initiative
“EV market share is around 2% now,” said Travis Wood, MEI’s program manager and author of the survey and analysis of EV growth in the state. That share is expected to rise to 10% by 2030 and 58% by the 2040s.
“We can expect relatively explosive growth of the industry compared to what we’ve seen up to this point. Coupled with that growth is the need for charging infrastructure and specifically public charging infrastructure.
“While it is the case that 80% of charging occurs in the home, at least currently, public charging infrastructure is needed to facilitate these longer trips, to top off during shorter trips, to reduce that range anxiety and increase the visibility of EVs and help the industry grow,” Wood said.
“If we look nationally, the U.S. has around 44,000 charging stations, but an estimated 1.25 million are going to be needed by 2030,” he said. “So there’s a lot of growth that is coming for this industry in a relatively short amount of time.”
Missouri has about 9,000 registered light-duty EVs and over 2,000 public charging stations, he said, but only 215 fast chargers — able to refill an EV’s batteries to at least 80% capacity in approximately 20 to 30 minutes. The rest of the public chargers are Level 2 chargers, running on 240 V, and require more time to charge an EV. Many residential Level 1 chargers run on 120 V and are typically used overnight.
“It can be argued that Missouri has sufficient charging ports in place now to meet current EV adoption levels,” Wood said. “But you know, looking out to 2030, it’s estimated there’s going to be over 200,000 EVs on the road in Missouri. So, there’s going to be the need for 8,000-plus public charging ports, at least according to DOE, to support that growing market.”
The buildout of EV charging infrastructure will test not only the utilities but also private electrical contractors who will be asked to bid for private construction of charging stations.
Using the rise of EVs as a starting point, a separate panel looked at the potential impacts on the ability of the state’s utilities to meet new demand while maintaining a stable delivery system and avoiding steep price increases.
Linda Little, St. Louis Electrical Training Center | Missouri Energy Initiative
“I think that Missouri could try to lead in a couple of things. One is coming up with an energy storage solution. So then as we have more and more of these charging stations — even the quick charging stations that are going to need this energy — that we have the energy storage capability to back those up,” said Linda Little, assistant director of the IBEW/NECA Electrical Industrial Center in St. Louis.
Patrick Justis, manager of efficient electrification development for Ameren Missouri, said building home charging stations will be “a big, big issue” in multifamily homes, whether high end condominiums or multicomplex apartment buildings.
“When you’re talking about a 150-car parking garage or parking lot, you’re talking about quite a bit of power,” he said.
“One of the principles we have with utilities is a meter for each domicile. And now you’ve got these vehicles taking up quite a bit of energy and you can’t pull them through your existing meter. Finding technical solutions to this will be really important.”
Panel moderator Maurice Muia, principal of a consulting company and climate adviser to the Natural Resources Defense Council and the city of St. Louis, summed up the future this way:
“I think innovation and workforce development are going to play a key role. We have very good institutions of higher learning. We have a ton of electrical contractors across the state.
“We have what we need to be great in this clean energy economy of the future. We have all the necessary parts and puzzles. It’s a matter of, as everyone has said, how do we prioritize and come up with a vision and mission that meets the needs of the residents and those that visit Missouri as well.”
The California Public Utilities Commission issued a much-anticipated revision to its net metering rules for residential rooftop solar generation Monday, inflaming a controversy that has been growing for months over how much homeowners should be compensated for returning excess electricity to the grid.
The battle has pitted an unusual coalition of large utilities, ratepayer advocates, unions and environmentalists against the rooftop solar industry, trade groups and homeowners who receive generous billing credits for rooftop solar.
Those who want to significantly change the current net metering framework argue it unjustly benefits richer households at the cost of common ratepayers. Those who want to keep it contend changing net metering will decimate household solar adoption in California, where incentives that started in the mid-1990s led to more than a million household solar arrays.
The CPUC has been examining net energy metering (NEM) since August 2020 with extensive input from stakeholders and homeowners. Its 204-page proposed decision published Monday would make some compromises but generally favors those seeking wholesale change by cutting compensation rates, incentivizing home battery storage and promoting solar adoption across a broader socioeconomic spectrum.
“Our review of the current net energy metering tariff, referred to as NEM 2.0, found that the tariff negatively impacts nonparticipating customers; is not cost-effective; and disproportionately harms low-income ratepayers,” CPUC Administrative Law Judge Kelly Hymes wrote. “This decision determines that, to address the requirements of the guiding principles and the findings related to the NEM 2.0 tariff, the successor tariff should promote equity, inclusion, electrification and paired storage, and provide a glide path so that the industry can sustainably transition from the current tariff to the successor.”
The proposed decision is scheduled to be heard at the CPUC’s Jan. 27 voting meeting. The lead commissioner in the effort, Martha Guzman Aceves, will leave before then to become administrator of EPA’s Region 9, while CPUC President Marybel Batjer is retiring. Her replacement, Gov. Gavin Newsom’s energy adviser Alice Reynolds, is scheduled to take office at the end of this month.
Proposed Changes
The CPUC’s proposed changes would revise the structure of net metering, which credits rooftop solar owners for excess electricity they export to the grid. For years, homeowners have received the full retail value of the surplus electricity plus bonuses for producing more energy than they use in a 12-month period.
A new avoided-cost rate would consider the value of behind-the-meter generation to resource adequacy and grid reliability, potentially slashing the reimbursement rate by less than half. It would also impose an interconnection fee that does not currently exist, averaging about $40/month.
“The successor tariff ensures all customers pay for their usage of the grid,” the proposed decision says. It would apply a grid charge of $8/kW of installed solar “to capture residential adopters’ fair share of costs to maintain the grid and fund public purpose programs,” the CPUC said in a news release.
The decision proposes applying time-of-use rates to encourage solar owners to charge batteries during the day and discharge them after sunset, the net-peak hours when California has run short of electricity during heat waves the past two summers.
“More accurate price signals…will promote greater adoption of customer-sited storage, which will help California decrease its dependency on fossil fuels during the early evening hours, when the sun is down and energy demand is high,” the CPUC said.
The proposal would create an equity fund with up to $600 million to “improve low-income customer access to distributed clean energy programs with strong consumer protections,” the commission said. A stakeholder process would determine how the funds are spent, for instance on community solar projects.
One compromise in the proposed decision seeks to address concerns that slashing net metering credits would ruin the rooftop solar industry. A proposed four-year “glide path” for the industry would pay a monthly market transition credit of up to $5.25/kW for new residential solar-plus-storage and solar-only systems.
“Customers will lock this amount in for 10 years,” the CPUC said in its news release. “During the four-year glide path, the credit will step down 25% a year for prospective customers, who will also lock in their amount for 10 years.”
To soften the blow to homeowners, the decision proposes a “storage evolution fund” to provide rebates for existing net-metering customers who add storage systems to their homes and switch to the new net-metering structure in the next four years. Otherwise, it would transition current customers to the new compensation structure after 15 years of continuous interconnection.
Opponents React
Reaction from the solar industry was swift and angry.
“Today the California Public Utilities Commission issued a proposal that will create the highest solar tax in the country and tarnish the state’s clean energy legacy,” the Solar Energy Industries Association said in a statement. “The proposal imposes fees on solar and storage customers, making solar and storage more expensive and less accessible to all Californians. The new program will rapidly reduce the bill credit solar customers get for selling electricity back to the grid, adding unpredictability and instability for customers that already have solar.”
SEIA said the proposed decision would deter residents from installing rooftop solar, “leaving the state’s grid vulnerable to blackouts and power outages and harming California’s ability to reach its clean energy goals.”
“Before today’s decision, about 40% of all rooftop solar installations in California were going to low- or middle-income homes in California, but the new costs and fixed fees are going take away the value proposition for virtually all Californians,” it said. “This will slow the massive momentum the state was building toward a grid powered by clean energy.”
Cutting net metering payments is mainly about boosting utility profits, critics argued.
Main proponents included the state’s three large investor-owned utilities, ratepayer advocates such as The Utility Reform Network (TURN) and environmental groups including the Natural Resources Defense Council.
Pacific Gas and Electric, the state’s largest utility, said the proposal “is a step in the right direction to modernize California’s outdated rooftop solar program. Over time, NEM has resulted in deep inequities between customers with rooftop solar and those without, who are often lower-income customers. Sensible reform is necessary to support customer equity and help continue California’s success toward a clean energy future.”
Independent research firm ClearView Energy Partners said the proposed decision seemed to strike a balance.
“We are still reviewing the 204-page document but think [it] may provide a reasonable middle ground between the different proposals offered by stakeholders earlier this year,” the firm said in a note to clients. “While the [proposed decision] would reduce export compensation, it would also include a 10-year transition credit for customers that deploy distributed generation such as rooftop solar within the next four years.
“That said, a proposal to impose a comparatively high monthly charge on rooftop solar customers may prove very contentious,” ClearView said.
Fights over net metering have occurred in other states, with utilities set against the solar industry.
In July 2020, FERC rejected a challenge to net metering by a purported ratepayer group called New England Ratepayers Association, which argued that the commission had exclusive jurisdiction over sales of rooftop solar power. (See FERC Rejects Net Metering Challenge.)
Hawaii, Indiana, Maine, Michigan and North Carolina have struggled with net metering policies, which were introduced to promote solar when it was rarer and rates were higher. Solar has since become far more common and inexpensive. (See Net Metering Reform Means Asking New Questions.)
TAYLOR, Texas — Meeting publicly for the first time with almost a full complement, ERCOT’s new Board of Directors made a point to reassure any Texans listening to the webcast that a new sheriff is in town following last February’s devastating winter storm.
“This is a work in progress,” Director Carlos Aguilar said. “We’re doing everything we can to stay abreast of the situation and ensure the system remains stable.”
Fellow Director John Swainson, who has more than 40 years of technology experience, said during a quick round of introductory statements that he hopes to leverage his IT background for the grid’s benefit.
“I want to focus on how we can look 10 years into the future and even longer,” he said. “How can we get past the current set of issues, but continue to provide this same abundance of reliable energy for decades to come?”
The storm resulted in the resignation of much of the previous board, most of whom Texas’ political leadership faulted for living out of state. Following new state legislation, they have since been replaced by six independent directors, two short of a full slate, who all live in the Lone Star State. (See 2 More Directors Appointed to ERCOT Board.)
“Look at those pictures,” interim CEO Brad Jones said, pointing to a screen with images of the board’s four newest members. “It’s great to have a nearly full board.”
“I can’t tell you how happy I am to see you today,” Public Utility Commissioner Will McAdams said. “You have a big job in front of you. Winter is upon us, and this organization has made giant strides to ensure we’re ready. This grid is resilient and hardened and will survive [another winter weather event]. The public remains safe.”
Jones stressed the amount of work ERCOT staff have undertaken since the storm. The legal department has been swamped with litigation issues; a new 12-person department has been created to handle winter readiness inspections as a result of new legislation; and staff are working to improve communications within the industry and not just within ERCOT.
The workload has resulted in above-normal turnover for ERCOT, but fears have lessened that the light at the end of the tunnel is another oncoming train. Jones said staff are already closely monitoring a storm due to hit Texas near the end of December.
“We’ll be ready because we’re working with the PUC,” he said. “Tweaks that will have significant value to the market, we’re making today. We’re in the same room together.”
Response to NERC-FERC Winter Storm Inquiry
Staff told the directors they have begun or completed work on nearly all of the recommendations applicable to ERCOT identified in NERC and FERC’s joint inquiry into the storm. That doesn’t include the numerous recommendations made by staff, stakeholders, regulators and legislators since February.
The federal agencies released their report in November, highlighting the failure of electric and gas utilities to adequately prepare for the storm’s extremely low temperatures. The event caused more than 23 GW of manual firm load shed as generators and their supply lines froze. (See FERC, NERC Release Final Texas Storm Report.)
Compiled by a team of more than 50 subject matter experts, the report listed 28 recommendations that covered the electric and gas industries and went beyond NERC reliability standards revisions to address cold weather, which were approved in August 2021.
Jones reassured board Vice Chair Bill Flores and the webcast’s viewers that the problems were regional and not isolated to ERCOT. Among several recommended improvements to ERCOT’s grid are improving interconnections with other grid operators beyond the current 820 MW worth of DC ties.
The report’s authors “recognized the ability to move power all the way east to Texas would have been very limited,” Jones said. “Our power supplies were cut because we have an agreement with the regions around us that if one of us gets into trouble, we can terminate the power supplies [we’re exporting]. We recognize that was an appropriate action to take.”
Betty Day, ERCOT’s vice president of security and compliance, said the grid operator is finalizing its own report on the storm and will publicly post the document when it’s complete.
“This is standard after any grid event,” she told the board.
ERCOT to Correct Prices
The directors signed off on staff’s request to correct prices for eight operating days in September and October stemming from a modeling error for a generation transmission constraint in the day-ahead market. Resettling the error resulted in more than $816,000 in increased charges and more than $122,000 in reduced charges to market participants. (See “Staff to Seek Price Correction,” ERCOT Technical Advisory Committee Briefs: Nov. 29, 2021.)
Price corrections “are largely event-based and don’t have a consistent cadence,” Dave Maggio, ERCOT’s director of market design and analytics, said when questioned about the frequency of price corrections. “There have been a handful or so of various events that have occurred.”
The grid operator’s staff must seek board approval of price corrections when they are identified outside of a short multiday deadline to make corrections themselves.
TAC’s 2022 Membership Approved
The board unanimously confirmed the 2022 Technical Advisory Committee, which will continue in its present form and with its familiar members as elected by their market sectors. The board has not yet decided whether to make any changes to the committee’s stakeholder membership. (See ERCOT Technical Advisory Committee Briefs: Nov. 29, 2021.)
PUC Chair Peter Lake welcomed the committee’s membership and offered a reminder that “with this new board, this new leadership will continue to leverage the expertise of TAC while also optimizing its effectiveness.”
“We look forward to working with you during this transition as you see fit,” said TAC Chair Clif Lange, of South Texas Electric Cooperative.
Lange will continue in the chairman’s role, and Just Energy’s Eric Blakey will remain as vice chair. The committee is responsible for recommending protocol changes and endorsing other operational issues to the board and is assisted by four sub-committees.
Board Approves $1.28B Tx Project
The directors approved a number of staff and stakeholder recommendations during the meeting, including a $1.28 billion transmission project in the Rio Grande Valley. The project would add 351 miles of transmission lines radiating from a new substation in the Lower Rio Grande Valley, which ERCOT and the PUC have both identified as in urgent need of more transmission capacity. (See “TAC Endorses $1.28B Tx Project,” ERCOT Technical Advisory Committee Briefs: Nov. 29, 2021.)
Director Aguilar asked whether the project would be eligible for funding under the federal infrastructure bill signed into law last month, saying, “Should we identify more of these that are essential and could be implemented sooner than later because of the infrastructure bill?” (See Biden Signs $1.2 Trillion Infrastructure Bill.)
“Our function is to identify the needs in the system and hand that process over the transmission provider who will do that development,” Jones said.
ratification of several actions taken by the prior board during its remote meetings.
Directors Zin Smati and Bob Flexon abstained from the last vote.
The consent agenda, which cleared unanimously, included seven nodal protocol revision requests (NPRRs); a Nodal Operating Guide revision (NOGRR), an other binding document changes (OBDRR), a revision to the Planning Guide (PGRR) and a modification to the resource registration glossary (RRGRRs):
NPRR1077: expands NPRR1026’s self-limiting facility concept to include sites with one or more settlement-only generator (SOG) and introduces additional revisions to fully address requirements for generators and energy storage systems (ESSs) connected at distribution voltage. The NPRR requires the SOG’s qualified scheduling entity to provide telemetry of the injection or withdrawal at the point-of-interconnection (POI) for transmission-connected sites or point-of-common coupling for distribution-connected sites.
NPRR1091: addresses energy-price suppression and liquidity issues created by ERCOT’s early and greater procurement of ancillary service by extending the treatment of must-take energy from reliability unit commitments in pricing runs to offline non-spinning reserves, when it is manually deployed. The change also increases the amount of responsive reserves and non-spin services that an entity can self-arrange above its obligation.
NPRR1094: allows a transmission operator (TOP) and transmission/distribution service providers (TDSPs) to manually shed load connected to under-frequency relays during a Level 3 energy emergency alert (EEA) if the affected TOP can meet its overall under-frequency load shed (UFLS) requirement and its load shed obligation under the Nodal Operating Guide.
NPRR1101: modifies load resources’ deployment grouping requirements if they’re not controllable load resources providing non-spin to include generation resources providing offline non-spin.
NPRR1103: establishes the processes for assessing and collecting default charges and default charge escrow deposits for the debt-obligation order securitizing about $800 million owed to the market by cooperatives and municipalities.
NPRR1104: corrects the definition of real-time liability extrapolated (RTLE) to include market activity for entities that have no load or generation but do have real-time exposure.
NPRR1107: adds new fees for ERCOT’s weatherization inspections of the resource entity’s capacity divided by the entity’s aggregate capacity.
NOGRR233: allows a TOP and a TDSP to manually shed load connected to under-frequency relays during a Level 3 EEA if the affected TOP can meet its overall UFLS requirement and load-shed obligation.
OBDRR035: aligns the non-spinning reserve deployment and recall procedure with NPRR1101’s revisions.
PGRR092: allows an interconnecting entity (IE) proposing a SOG to designate it as part of a self-limiting facility during the generator interconnection or modification (GIM) process, consistent with NPRR107.
RRGRR029: allows an IE proposing a SOG to designate it as part of a self-limiting facility during the GIM process.
The directors separately approved five non-unanimous revision requests recommended by the TAC:
NPRR1106: codifies the grid operator’s current practice of deploying emergency response service when physical responsive capability falls below 3 GW before declaring an EEA.
NPRR1109: allows a resource entity to bring a decommissioned generating unit back to service if it notifies ERCOT within three years of its removal from the network operations model.
NOGRR236: allows ERCOT to instruct TDSPs to deploy any available distribution voltage-reduction measures before declaring an EEA.
NOGRR237: aligns the Nodal Operating Guide with NPRR1106’s protocol changes.
OBDRR036: revises the ERS procurement methodology document to mesh with NPRR1106.
North Carolina Gov. Roy Cooper on Thursday vetoed a bill that would have prohibited the state’s cities and counties from banning natural gas hookups in residential construction.
To date, similar bills — heavily supported by the natural gas industry — have been passed in 20 states and are pending in four more. These “pre-emptive bills” have all been enacted in the past two years in response to ordinances or building codes now adopted in 50 cities in California to promote home electrification and reduce carbon emissions by banning natural gas hookups in new construction, according to S&P Global.
In a statement released with the veto announcement, Cooper said, “This legislation undermines North Carolina’s transition to a clean energy economy that is already bringing in thousands of good paying jobs. It also wrongly strips local authority and hampers public access to information about critical infrastructure that impacts the health and wellbeing of North Carolinians.”
The governor has been pushing for the state to cut its emissions by 70% over 2005 levels by 2030, a goal codified in a new law, HB 951, which he signed in October. According to a 2019 greenhouse gas inventory produced by the North Carolina Department of Environmental Quality, residential emissions then accounted for 3.5% of the statewide total.
The vetoed bill, HB 220, would stipulate that cities and counties in the state cannot “adopt an ordinance that prohibits, or has the effect of prohibiting, the connection, reconnection, modification or expansion of an energy service based upon the type or source of energy to be delivered to an individual or any other person as the end user of the energy service.”
The specific sources of energy that cannot be prohibited are defined in the bill as “natural gas, renewable gas, hydrogen, liquefied petroleum gas, renewable liquefied petroleum gas or other liquid petroleum products.”
To date, no North Carolina cities or counties have passed or proposed such bans, which led some Democratic lawmakers to question the need for the bill when it was introduced earlier this year. Defending the pre-emptive action, Rep. Dean Arp (R), a bill sponsor, said, “Energy policy is a state issue,” and a bill protecting consumer choice “absolutely clarifies that before it becomes a problem.” (See Gas Industry Brings Fight Against Building Electrification to NC.)
In a statement released following Cooper’s veto, Arp said the bill was intended to leave “household decisions like whether or not to have a gas stove in their home to consumers themselves. The heavy hand of government has no place in the personal decisions North Carolinians make for their households.”
House Speaker Tim Moore (R) also criticized the veto, characterizing it as an act of “partisanship over common sense.”
To override a veto, a three-fifths majority is needed in each chamber of the General Assembly: 30 votes in the Senate and 72 in the House of Representatives. There are 28 Republicans in the Senate and 69 in the House.
‘It’s not About Today’
Maggie Shober, research director at the Southern Alliance for Clean Energy, praised Cooper for “standing up for local control of how to make our buildings safer and cleaner. These ban-the-gas-ban bills have been pushed by special interests across the country, with little thought to the customers that will be forced to pay for expanding fossil fuel infrastructure in their neighborhoods while the science has been clear: To avert the worst of climate change, we need to reduce, not expand, our use of fossil fuels.”
According to the U.S. Energy Information Administration, about one in four North Carolina homes are heated with natural gas. EIA also ranks the state as one of 10 in the U.S. with the lowest per capita use of natural gas, although natural gas consumption there has quadrupled in the past decade, mostly from its use in electricity generation.
But the debate here and in other states has centered on the economics and emissions of natural gas versus electricity.
The American Gas Association does not take positions on state policies, such as pre-emptive laws prohibiting bans on natural gas hookups, but spokesperson Jake Rubin argued that natural gas is both a cheaper, cleaner and more reliable fuel for home heating and cooking.
“A natural gas home has fewer CO2 emissions than a home that uses electricity for its various applications … because of the efficiency of the delivery infrastructure,” Rubin said. “It takes a lot more energy to get electricity to a home than it does to get natural gas to a home.”
And because “most of electricity is made using either coal or natural gas,” he said, a home using natural gas for space and water heating and cooking will have lower emissions than an all-electric home.
But Ram Narayanamurthy, program manager for buildings at the Electric Power Research Institute, said that calculations of an electrified home’s emissions will depend on the generation mix of the utility providing the electricity. And, he noted, many utilities are now committing to decarbonizing their power supplies.
“We find that in places like California, the generation mix they have today, all-electric homes [produce] about 40% less emissions than a mixed-fuel home,” he said. “In a place like Texas, it’s closer to neutral.
“The fact is that as you set the goals for going zero carbon, as the electricity gets cleaner, the grid gets cleaner and cleaner,” he said. “The trend is that your all-electric home is going to have far less emissions. It’s not about today, but if you look at 2030, the generation that’s in 2030, that all-electric home that you build today is going to be a lot cleaner.”
Which Will be Cheaper, Cleaner?
In New Jersey, the latest state to consider a pre-emptive prohibition on bans on natural gas hookups, gas advocates are also pointing to the future potential for low-carbon fuels as a reason to maintain gas pipelines.
At a recent hearing in the New Jersey Senate, Robert Pohlman, managing director of innovation and strategic initiatives at New Jersey Natural Gas, said that ratepayers had invested $17 billion to create the infrastructure through which natural gas is supplied to their homes. That infrastructure could be used to bring alternative fuels, such as hydrogen or renewable natural gas, to consumers, but it would be discarded if buildings transitioned to electricity. (See NJ Legislators Back Alternatives to Electric Heat.)
“The state must not close itself off from the future benefits of investment, innovation and competition happening around low-carbon fuels today,” Pohlman said.
But whether natural gas or electricity is cleaner and cheaper for North Carolina consumers will depend, again, on the local generation mix and rates. EIA ranks North Carolina in the top 10 for overall electricity consumption and the top five for residential electricity sales.
Duke Energy, the state’s largest utility, has committed to cutting its carbon emissions by 50% by 2030 and achieving net-zero emissions by 2050. However, the utility’s integrated resource plan, still pending before the North Carolina Utilities Commission, anticipates adding thousands of megawatts of natural gas generation through 2035.
The utility’s rates will also likely increase in coming years. Under HB 951, Duke will be able to file multiyear rate plans, under which it will only have to file a full rate case once every three years, rather than yearly as it does now. It will be able to raise rates up to 4% per year in between without the approval of the NCUC.
A subsidiary of New York-based utility Consolidated Edison (NYSE:ED) has submitted a proposal for a 2.4-GW transmission “backbone” to the New Jersey Board of Public Utilities (BPU) to bring offshore wind-generated electricity to the PJM grid.
The proposal submitted by Con Edison Transmission would create Clean Link New Jersey, a high-voltage network of multiple undersea transmission cables.
“The offshore mesh-style network is flexible and modular to allow various offshore wind projects to plug in as they become ready to generate,” the company said in a Dec. 6 statement outlining the project. A description of the proposal posted on the PJM website states that an undersea “power corridor” through which cables will run “provides the opportunity to better manage costs and improve grid stability, while significantly reducing permitting and environmental impacts.”
Con Ed submitted the proposal under the competitive solicitation by the BPU and PJM for new transmission and grid upgrades to handle the 7,500 MW of offshore wind energy that the state expects to bring online by 2035. (See New Jersey Seeks OSW Transmission Ideas.)
The organizations issued the solicitation under FERC Order 1000’s state agreement approach, under which the BPU requested that PJM integrate the state’s offshore wind goals into the RTO’s Regional Transmission Expansion Plan process. About 80 documents are posted on the PJM webpage that lists proposals submitted under the solicitation. (See PJM, NJ Staff Brief Stakeholders on State Agreement Approach.)
Proposals were accepted until September, and PJM officials are now reviewing them. The BPU expects to begin evaluating them early next year and will decide which ones fit their needs in the third or fourth quarter.
First NJ Venture
New Jersey has so far approved three offshore wind projects in two phases totaling 3,758 MW, about half the state’s target. Danish developer Ørsted’s Ocean Wind, an 1,100-MW project, won the first solicitation in 2019, and in June the state awarded the developer a second project, its 1,148-MW Ocean Wind II, in the second solicitation. The BPU also backed Atlantic Shores, a 1,510-MW project developed by a joint venture between EDF Renewables North America and Shell New Energies US.
Con Edison Transmission’s project is the subsidiary’s first venture into New Jersey, although another subsidiary of Con Ed, Orange and Rockland Utilities, serves customers in Northern New Jersey, company spokeswoman Anne Marie Corbalis said. The release said Con Edison Transmission is “developing a portfolio of transmission projects delivering renewable energy to customers.”
The Clean Link New Jersey proposal includes plans for a 27-mile fiber optic undersea cable and 23 miles of onshore cable, and the project will be capable of handling energy from multiple projects, according to the proposal. The project consists of eight transmission components, including substations onshore and offshore, transmission lines and a 500-foot-wide right of way, which will together cost $2.75 billion, according to the proposal.
Public Service Enterprise Group (NYSE:PEG) announced in October that it has submitted several projects to the BPU/PJM solicitation in partnership with Ørsted, collectively known as Coastal Wind Link. The company declined to provide details of its submissions. Proposals listed on the PJM website under PSEG’s name only include one to conduct a series of upgrades to the Central Jersey grid system.
The list of projects on the site submitted under Coastal Wind Link includes a 92-mile offshore transmission line that will come ashore at the Raritan River and then run 6 miles onshore, mainly on public rights of way, to a converter station in Sewaren, in Middlesex County, at a cost of $848 million. Another proposal would create a converter platform in the South Hudson offshore area planned for the two Ørsted developments that will receive AC power from the wind farms, convert it to HVDC and move it to the shore, with a cost of the various components of $1 billion.
Coastal Wind Link’s proposals would “provide a reliable, resilient and cost-effective infrastructure to the state,” the company said in a statement. The proposals “encompass individual and networked solutions and would ensure that New Jersey has a clear path to connect to the offshore wind energy coming online during the next decade while minimizing environmental impacts along New Jersey’s coastline,” the statement said.
