FERC on Thursday affirmed the Henderson, Ky., municipal utility’s status as a transmission owner in the MISO region, ruling its facilities can be classified as transmission rather than distribution lines (ER19-776-001; ER19-809-001).
Big Rivers Electric Corp. has disputed Henderson Municipal Power and Light’s standing as a MISO transmission owner, arguing that the city’s lines are distributed in nature and that it shouldn’t share in Big Rivers’ transmission pricing zone.
FERC previously found in 2019 that Henderson’s 69-kV and 161-kV lines can be categorized as transmission, making the city a MISO transmission owner in the pricing zone. The utility is interconnected with Big Rivers’ transmission system.
The commission said it’s appropriate that Big Rivers “share its imputed revenues for its bundled load with Henderson for transmission service provided by the Henderson facilities.” FERC added that a joint pricing zone is appropriate in this instance because it provides for Henderson to recover revenue from the facilities’ physical location and is similar to MISO’s other joint pricing zones.
The commission said Big Rivers and Henderson should both have a stake in the pricing zone, despite Big Rivers’ reconfiguration of its system in 2019 by disconnecting a substation tie line between its facilities and Henderson’s.
FERC’s decision confirms an administrative law judge’s opinion last year.
MISO’s Board of Directors approved the transmission-owning membership of Henderson in 2018. The grid operator applied FERC’s seven-pronged transmission test under Order 888 to determine that most of Henderson’s system qualified as transmission. (See “6 Added to MISO Membership,” MISO Board of Directors Briefs: Dec. 6, 2018.)
Big Rivers in 2019 alleged that MISO presented for stakeholder review the results of the transmission test during a Planning Subcommittee meeting after it had already filed Henderson’s application as a transmission owner with FERC.
Before it closed in 2015, the Hobet coal mine in southern West Virginia was one of the largest surface coal mines in the U.S. Now, Kansas City-based renewable developer Savion is planning to turn 3,000 acres of the site into the state’s largest solar farm with up to 250 MW, enough to power more than 30,000 homes.
The SunPark Solar project is one of many former coal mines being transformed into solar generating sites.
The Environmental Protection Agency recently identified 17,756 mine sites totaling 1.5 million acres, enough space to generate almost 90 GW of power. In June, the Department of Energy announced it would spend $500 million from the Infrastructure Investment and Jobs Act to transform former mine lands into “clean energy” sites. At least two of the projects must be solar; also eligible are geothermal, fossil fuel generation with carbon capture, energy storage and advanced nuclear. (See DOE Launches $500M Project to Put Clean Energy on Mine Lands.)
Founded in 2019, Savion was acquired in December by Shell New Energies (NYSE:SHEL) and has solar and storage projects in various phases across 31 states. The SunPark project is the result of an agreement the company reached earlier this year with SEVA WV, a West Virginia-based company that also hopes to develop an industrial park, lodging and recreation on the remaining 1,500 acres of the former mine.
The electricity Savion generates will be sold into the wholesale electric market. Commercial operations could begin between 2025 and 2028.
Elsewhere in West Virginia, a state formerly famed for its coal mines, FirstEnergy subsidiary Mon Power (NYSE:FE) is planning a solar power facility at a 44-acre reclaimed strip mine in Tucker County. That site is one of five locations where Mon Power plans to build a solar energy facility, for a total of 50 MW of renewable power generation. In May, Mon Power and FirstEnergy’s other West Virginia subsidiary, Potomac Edison, announced they had begun accepting West Virginia customer subscriptions to purchase power from the facilities through solar renewable energy credits (SRECs). More than 87,000 SRECs per year will be available when all five projects are up and running.
“We expect to obtain customer commitments this year for 85% of the solar renewable energy credits to be generated by the projects and will then seek final approval from the [West Virginia Public Service] Commission,” Will Boye, a spokesperson for FirstEnergy, said in an email. The company hopes to start full-scale construction next year at its first site, Fort Martin Power Station, with construction at the other four sites commencing in 2024 and 2025.
Silver Spring, Maryland-based Competitive Power Ventures (CPV) has two such projects in its portfolio: the Backbone Project in the western Panhandle area of Maryland, and Maple Hill Solar Farm in Cambria County, Pennsylvania. The former will generate 175 MW, enough to power roughly 30,000 homes. That project is waiting for an interconnection agreement with PJM, CPV’s Matt Litchfield said in an interview. “We hope to start construction in the next six months.” The Pennsylvania project will generate 100 MW, after an investment of more than $200 million, he said.
Seven Sites on Nature Conservancy-Managed Lands
The Nature Conservancy announced in July 2021 that it had reached agreements with Sun Tribe, based in Charlottesville, Virginia, and Washington, D.C.-based Sol Systems, which will build solar energy facilities on former coal mining lands that the environmental group manages in southwestern Virginia.
In September 2021, Dominion Energy Virginia (NYSE:D) announced its own partnership with the Conservancy for the Highlands Solar project, which will reuse about 1,200 acres of the former Red Onion surface mine and surrounding properties in Wise and Dickenson Counties. The partners said the project will generate approximately 50 MW. Additional benefits for the area could include “an increase in local tax revenues, the ability to provide additional funding through solar siting agreements, and the creation of clean energy jobs,” they added.
Dominion plans to begin construction in 2024 or 2025, subject to approval by the Virginia State Corporation Commission, and will use the project to work toward its mandate under the Virginia Clean Economy Act to produce its electricity from 100% carbon-free sources by 2045.
While most of the Cumberland Forest Project that the Nature Conservancy manages — almost 253,000 acres in southwestern Virginia, eastern Tennessee, and eastern Kentucky — consists of woodlands, it includes seven former coal mining sites as well, including the Highlands Solar site, five other sites in Virginia, and one just over the state line in Tennessee. Sun Tribe is developing the latter six sites, Brad Kreps, Clinch Valley Program Director for the Nature Conservancy, said in an interview.
The Conservancy says the three companies’ solar farms will cover nearly 1,700 acres and generate an estimated 120 MW.
“We are trying to find ways to create benefits for nature and new economic benefits for localities, such as tax revenues and jobs,” Kreps said.
But he conceded that most of the job creation involved will take place during the construction phase of the projects; no one expects the new solar farms to replace the number of jobs lost with the demise of mining. “It doesn’t take very many people to operate the facilities,” he said.
According to job posting site Indeed, solar panel installers in Virginia average about $24.50 per hour. Less than 12% of construction workers in the solar industry are unionized, according to the Solar Energy Industries Association. Although that is less than the national average for construction, it is double the 5.6% union participation rate reported in 2020 for the mining, quarrying, and oil and gas extraction segment, according to the Bureau of Labor Statistics.
But while converting coal mine sites to solar won’t provide all the economic benefits that have been lost in Appalachia, supporters say it is essential to use sites such as these to minimize the need to convert farmland and woodlands. Princeton University energy and climate expert Jesse Jenkins has estimated that the most cost-effective scenario for reaching net-zero emissions will require solar over an area equivalent to the states of Connecticut, Rhode Island and Massachusetts.
The Pennsylvania Public Utility Commission (PUC) swore in three new members Thursday, bringing the five-member board to full strength for the first time in 30 months as it faces the challenge of balancing the push toward clean energy with the continuation of the state’s strong fossil fuel sectors.
The Republican-controlled state Senate approved Democratic Gov. Tom Wolf’s nominations Wednesday, reappointing John F. Coleman Jr. to the PUC after 12 years as a commissioner. Newly appointed members were Stephen M. DeFrank, a government relations professional who spent 24 years in state government, and Kathryn L. Zerfuss, a veteran government affairs strategist who worked on regulatory and policy issues.
The PUC last held a full board complement prior to April 2020, when Commissioner Andrew Place resigned to take a job outside the state. Commissioner David Sweet’s position became vacant in 2021 when his term expired, and Coleman’s job had been vacant since Oct. 1 when his term expired, leaving the PUC with just two members.
Coleman will serve until April 1, 2027, DeFrank until April 1, 2025, and Zerfuss until April 1, 2026.
The three commissioners join Chair Gladys Brown Dutrieuille and Commissioner Ralph V. Yanora in steering an agency with 526 employees and an $85.3 million budget. The PUC regulates about 9,000 entities in industry sectors that include electricity, natural gas, telecommunications, water, rail, motor carriers and pipelines.
In a release announcing the Senate’s approval of the three nominees, Dutrieuille welcomed the continuation of Coleman’s “experienced voice” on the board and the “new perspectives” of DeFrank and Zerfuss.
“Pennsylvania continues to face a diverse list of utility issues, and their voices, insights and backgrounds will be vital as the PUC moves forward,” Dutrieuille said.
Energy Disputes
The appointments come amid criticism from environmentalists at the slow pace of Pennsylvania’s embrace of clean energy — solar provides less than 1 % of the state’s energy — but strong support elsewhere for the state’s legacy energy industries. They also accompany uncertainty over Wolf’s effort to bring the state into the Regional Greenhouse Gas Initiative (RGGI), which Republicans oppose.
The RGGI effort was blocked in July when Commonwealth Court Judge Michael Wojcik issued a temporary injunction in response to petitions by the coal industry, operators of the Keystone and Conemaugh plants, and others. That case is pending. (See Court Blocks Pa. from Joining RGGI.)
The dispute over RGGI had earlier derailed Wolf’s effort to fill the PUC board when Republicans last year refused to approve the governor’s nomination of Hayley Book, a climate adviser in the state Department of Environmental Protection who led the effort to join RGGI. Republicans said they would not approve PUC nominees until Wolf dropped his unilateral effort to join RGGI, and the governor eventually dropped Book’s nomination.
The approval of the three nominees who took office Thursday was part of a deal between Wolf and Senate Republicans under which the GOP would back two Wolf nominees and he would reappoint Coleman, a Republican, according to a local press report. Without the deal, the vacancies could have been left for the next governor to fill, after the November election.
Business and environmental representatives welcomed the appointments.
Elowyn Corby, Mid-Atlantic regional director at Vote Solar, who co-authored an opinion piece last week contending that Pennsylvania’s clean energy strategy is inadequate, said she was “delighted” by the approval of the three commissioners.
“The PUC plays an integral and often under-appreciated role in shaping Pennsylvania’s energy landscape, and I’m grateful and relieved that it will once again have the five Commissioners it needs to do its important work,” she said.
Jon Anzur, vice president of public affairs at the Pennsylvania Chamber of Business and Industry, said the organization was pleased to see the Senate “bring the panel to full complement.”
“The PUC commissioners and their staff work on important issues affecting the business community, like siting energy infrastructure, protecting ratepayers, and having a voice in ensuring that the PJM grid is reliably managed,” he said.
Qualifications, Aspirations
Coleman was serving as CEO of the Chamber of Business and Industry of Centre County in 2010 when then-Gov. Edward Rendell, a Democrat, nominated him. He served as PUC vice chair from 2011 to 2015 and from October 2021 to September 2022.
He is a member of the National Association of Regulatory Utility Commissioners (NARUC) Committee on Gas and was an inaugural member of NARUC’s Pipeline Safety Committee. He served as a board member of the Organization of PJM States from 2013 to 2017.
Addressing the state Consumer Protection and Professional Licensure Committee, which supported all three nominations, Coleman cited his accomplishments at the agency. Among them: his work advocating for legislation to enhance enforcement of the PA One Call Law, which aims to prevent accidental disruption of underground utility infrastructure. He also cited his effort to lead “the implementation planning for the PUC reorganization” and in “enhancing natural gas expansion pilot projects.”
In written testimony, he said his future priorities would include leading a PUC One Call Working Group; ensuring the commission “continues to be structured in the best way to accomplish our mission;” and “keeping a close eye on energy suppliers to make sure everyone is following the rules in our competitive marketplace.”
In his only mention of clean energy, Coleman said he would “foster new technologies and competitive markets in an environmentally sound manner.”
DeFrank, in written testimony to the committee, said that, if confirmed to the board, he would focus on utility regulation, including the “PUC’s core function of ensuring the delivery of safe and reliable utility service to our ratepayers.”
“I also intend to focus on the ever-increasing cyber threats that exist to our distribution systems and ensuring our utilities are prepared to meet those challenges,” he said. “Cyber threats are only going to increase in quantity and sophistication. We must be prepared to meet those challenges.”
Until his confirmation to PUC, DeFrank was a principal in the government relations group of Buchanan Ingersoll & Rooney, of Harrisburg, where he moved after 24 years working in state government, including stints for three senators. Among the positions he held was chief of staff/executive director to Sen. Lisa Boscola, Democratic chair of the Senate Consumer Protection and Professional Licensure Committee, which endorsed him for the PUC position.
Zerfuss, who in testimony to the committee said she was the first person in her immediate family to go to college, served as deputy secretary for legislative affairs in Wolf’s office at the start of his second term. While there, she helped establish an initiative to encourage students, workers and businesses to collaborate on programs that meet the needs of a 21st century workforce. She also helped secure Pennsylvania’s first tax credit to help working families with childcare.
Zerfuss had earlier served as director of legislative affairs at the state’s Transportation and Agriculture departments, and as deputy director of legislative affairs at the state Department of Revenue. She also worked at the Pennsylvania Gaming Control Board.
“Everything that I have done in my almost 20 years in Harrisburg has prepared me to become a public utility commissioner and taught me something about the commission’s constituencies,” she said.
Plug Power, once a manufacturer of small fuel cells for warehouse forklifts, but now emerging as a global fuel cell and hydrogen electrolyzer maker and the largest producer of green hydrogen in the U.S., may have a Wall Street credibility problem.
The company’s top executives opened Plug’s manufacturing and research facility — known as the Gigafactory — near Rochester, N.Y., on Wednesday to host its annual symposium for analysts and corporate customers. They presented a scenario of a company that has grown exponentially through acquisitions and partnerships and is on the road to a profitable future.
But investors weren’t having it. Plug’s share price (NASDAQ:PLUG) opened at $18.93 but fell by nearly $1 before the first hour of the symposium had elapsed. The stock closed at $16.95, down 11.30%. More than 29 million shares changed hands over the course of the day, up from an average daily trade of 20.8 million. The price decline continued Thursday with shares closing at $16.33.
The four-hour presentation, which followed a live tour of the manufacturing facilities the night before, included video reports from the company’s new U.S. and European projects, creating a story of a company on the move.
The presentations, both remote and at the Gigafactory, were crafted to show how Plug is designing and building large electrolyzer and hydrogen liquefaction plants to supply its U.S. customers with hydrogen, now delivered by a fleet of 30 very large cryogenic tanker trucks, which the company also designed.
‘Easy and Ubiquitous’
Ole Hoefelmann, General Manager of Electrolyzers for Plug Power | Plug Power
Ole Hoefelmann, Plug’s general manager of electrolyzer solutions, explained how Plug’s expansion has included acquiring other companies for the technologies that they had developed, including electrolyzers that could be scaled from 1 to 5 MW and then to 10 MW and much larger.
“In order for us to be super successful, what we need to do is we need to have a fabricator network, the ability to be able to build electrolyzers around the world. What we’ve done is through the acquisition … we have been able to build a fabricator network that we’ve established around the world.”
Through one of these acquisitions, Plug is now building an offshore electrolyzer — and liquefaction technology — in Europe to produce hydrogen from nearby wind turbines and deliver it to shore through a pipeline, he said.
Chief Strategy Officer Sanjay Shrestha told the crowd of about 200 at the symposium and 2,000 watching remotely that the company’s strategy is “to make hydrogen easy … and ubiquitous.”
“We are laser-focused in terms of execution … and we’re very confident about it. We will make sure this happens. We are going to be the category king in this $10 trillion hydrogen economy,” Shrestha said.
He added that the Inflation Reduction Act, which provides production tax credits for green hydrogen, is “absolutely a game changer for Plug and for the green hydrogen generation industry.”
Sanjay Shrestha, Chief Strategy Officer and General Manager of Energy Solutions, with Lazard Vice Chair George Bilicic | Plug Power
Addressing how the company has grown into a vertically integrated maker of fuel cells, electrolyzers and clean hydrogen, Shrestha said: “You want to buy a world class electrolyzer, you come to Plug. You want to buy the world’s most efficient liquefier, you come to plug. And if you want to actually buy the best payload … on-site storage, you also come to Plug.”
Buttressing his presentation were remote reports from Georgia and Texas, where the company is building large electrolyzers. A third project will be in Louisiana through a partnership with Olin Corp. (NYSE: OLN) for a plant that will produce 15 tons of green hydrogen per day.
He said the company is on course to have commissioned 50 tons of hydrogen production per year by the end of this year, less than the 70 tons that the company once projected. But 20 tons of that projection were for gaseous hydrogen, not liquid hydrogen. Permit problems in New York delayed a 45-ton project there for a year. The company also this year decided to delay similar projects in Canada and Pennsylvania.
“I do want to remind everybody that we are absolutely on track to be commissioning 200 tons today by year end 2023,” he said.
“We are looking to have about 100 tons of generation capacity in Europe sometime by 2026 — again, making us a major player in that market on our journey to get to that 1,000 tons per day by 2028,” he said, reminding his audience of the company’s longer-term goals.
“You know folks, what we’re doing here, frankly speaking, is not an easy thing to do. It’s very difficult. It’s hard, and nobody’s done it before. And we’re trying to do this at the speed and scale that has never been done before, either.”
Shrestha put that tonnage into context when answering a question about whether Plug would address making hydrogen for Class 7 and Class 8 large trucks, noting that the market for trucks running with fuel cell systems rather than diesel would account for about 200,000 tons per day of additional demand.
Multiplier Effect
Plug has been funding its massive projects with 100% of its own equity in order to accelerate its entry into the emerging hydrogen market. But that will change with the passage of the federal production tax credit (PTC) in the Inflation Reduction Act.
“We’ve been funding these plans with … 100% of our own equity capital, but with [the] PTC, as some of these plants come online, what we think happens is that you will at least get four to five times multiplier effect on that equity capital,” he said.
Shrestha expects to see the company’s “capital stack” (the type of funding available to finance business) transition from representing 100% equity to 20 to 40% over time. “And this will follow a very similar pattern to [what] you all saw in the solar and wind industry in the last decade.”
In a conversation with George Bilicic, vice chair of investment bank Lazard, Shrestha wondered to what extent future hydrogen projects would be affected by rising interest rates and uncertainty despite passage of the IRA, which offers federal loan guarantees, as well as a production tax credit.
“You and Lazard obviously do a lot of work with infrastructure funds, private equity funds. Has that changed their view on what … equity return that they’re [investors are] looking for? Maybe even for solar and wind? Is that going to end up impacting the cost of capital for green hydrogen buildup? How do you see that playing out?” Shrestha asked.
Bilicic said he expects the loan office of the U.S. Department of Energy to provide support, if necessary, in the immediate future but not over the long-term.
“You can look at some recent transactions and it’s as if nothing’s happened in the capital markets. … We think cost of capital will go up, but we don’t think it’s going to make a difference to the energy transition and what Plug Power is going to try to accomplish,” Bilicic said. “There is not a capital formation or a capital access program around the energy transition. It’s going to flow.”
Investors were skeptical about Plug even before the start of the symposium. The company on Oct. 14 issued a press release warning that its prior 2022 revenue guidance of $900 million to $925 million could be 5 to 10% for the year, citing supply chain issues that have slowed electrolyzer construction.
On the morning of the symposium, the company issued two press releases: one announcing the joint venture with Olin, and a second announcing a contract with an existing customer, FreezePak Logistics, to supply hydrogen made on site to power forklift trucks at more of the company’s warehouses.
With above-average temperatures expected across most of the continental U.S. this winter, FERC staff on Thursday said the grid seems well positioned to weather the cold months. However, rising demand for natural gas in Europe, coupled with lower-than-average domestic storage inventories, is expected to drive gas prices higher than last year’s.
Natural gas storage inventories are expected to begin the winter below both last year’s level and the five-year average. | EIA
Presenting FERC’s Winter Energy Market and Reliability Assessment at the commission’s October open meeting, Alexander Ovodenko of FERC’s Office of Energy Policy and Innovation said that data from NERC indicated “all planning regions forecast enough generation available to meet their planning reserve margins” — the available electric generation capacity in excess of expected peak demand — “through the winter.” Projected net internal demand for all regions is about the same as it was last winter, and resources and net transfers tell the same story.
One reason for the reassuring reliability forecast is the relatively mild temperature expectations for the months of December, January and February in most of the U.S. According to data from the National Oceanic and Atmospheric Administration, the West, Southwest, Southeast and Northeast all have a 55% chance or higher of above-normal temperatures, while only the Northwest and West Central have a 55% or higher likelihood of below-normal temperatures. The upper South and Central regions have equal chances of above-normal and below-normal temperatures.
ERCOT, MISO Vulnerable to Winter Weather
While FERC Chair Richard Glick and his fellow commissioners expressed relief about the overall positive weather outlook, Sasan Jalali from the Office of Electric Reliability warned that these projections assume normal operating conditions, and that “capacity may be especially tight in several regions due to extreme weather conditions” — particularly ISO-NE, ERCOT and MISO.
NOAA’s winter 2022-2023 temperature forecast shows high probabilities of below-average temperates in the Northwest and West North Central U.S. and high likelihood of above-average temperatures in the West, Southwest, Southeast and Northeast U.S. | NOAA
Jalali said that ISO-NE “has implemented several measures” to prepare for the winter, including delaying the retirement of the Mystic 8 and 9 natural gas-fired units and continuing its 21-day Energy Assessment Forecast, which the RTO began in 2018 to enhance its preparedness for severe weather. However, FERC’s report showed that the region could still need to use mitigations such as energy imports and voluntary or mandatory conservation to address emergency conditions.
Concerns also remain about the ability of generators in Texas to ride out extreme winter conditions, though Jalali acknowledged that many of the grid improvements made since last year’s winter storm “should reduce the likelihood and severity of” the state’s severe weather risks. He cited new state regulations requiring generators and transmission owners to winterize their equipment and facilities, along with more than 300 winter readiness inspections conducted by ERCOT over the last two years.
While MISO has sufficient reserves for normal conditions, FERC’s report suggested that under extreme conditions, the RTO might experience a shortfall of up to 15.6 GW, even with operational mitigations. MISO said that maintaining reliability in this state would require “triggering [load-modifying resources], non-firm transfers into the system, using energy-only interconnection service resources not receiving capacity credit, or internal transfers” between MISO North/Central and MISO South.
European Demand for US Gas Rising
On the natural gas side, the report said production “will likely outpace domestic natural gas demand growth” in the upcoming winter, with overall production expected to rise 3.2% from last winter to 99.1 Bcfd and demand growing 2.4% to 121.2 Bcfd. The biggest share of demand once again is expected to be residential and commercial heating, at 44 Bcfd, followed by industrial and other at 34 Bcfd, electric generation at 30 Bcfd and net exports at 13.4 Bcfd.
Liquid natural gas and gross pipeline exports are both projected to rise from last winter’s levels, while imports are expected to be around the same as last year. | EIA
The level of exports of both pipeline gas and LNG is expected to rise 24% from last year because of increased overseas demand. This year the demand from Europe has outstripped that from East Asia, typically the primary destination for U.S. gas exports, because of the cutoff of Russian natural gas flows amid the ongoing Russo-Ukrainian War.
At the same time, the Energy Information Administration expects U.S. natural gas storage inventories to begin the winter below both last year’s level and the five-year average. During the 2022-2023 withdrawal season, which begins in November 2022 and ends in March 2023, gas storage levels will peak at 3,472 Bcf despite a 10.3% increase in injections in 2022. However, the expected winter withdrawals of about 2,012 Bcf are also anticipated to be about 7.4% less than the five-year average thanks in part to the mild temperatures.
No Agreement on Blame for Gas Prices
With the rising demand expected to keep gas prices high throughout the winter, attendees at Thursday’s meeting had divergent opinions on the best way to address the likely hardships for consumers. Commissioner Mark Christie suggested that recent “premature” retirements of coal-fired facilities have left a hole for dispatchable generation that utilities frequently fill with natural gas plants.
Mark Christie, FERC | FERC
“When you retire a coal generating unit that still may have 15, 20 years of useful life remaining — and let’s say it’s a 2,000-MW unit — you’ve got to replace the 2,000 MW of capacity that you just lost,” Christie said. “So what’s been replacing the premature retirements of coal has been gas. … NERC has been very vocal about that: We’re going to have to have gas through the transition. But it’s adding to demand for gas.”
In a press conference following the meeting, Glick acknowledged Christie’s concerns but said the question of utilities’ generating resources was “not for FERC to decide.”
“It’s been an issue we’ve talked about for many years, [but] it’s for the states to decide what the resource mix should be,” Glick said. “To say, ‘Oh, they should put the coal units back, and that would solve everything,’ that’s a fantasy. That’s like saying, ‘I should try out for the Mets because I could make the Mets’; it’s not going to happen.”
James Danly, FERC | FERC
Glick also pushed back on Commissioner James Danly’s criticism of the “significant delays in the processing” of gas pipeline applications, in some cases from environmental reviews that Danly called “unprecedented” and “unnecessary gilding the lily.” The chairman disputed Danly’s assertion that the delays in pipeline construction had anything to do with rising natural gas prices, though he acknowledged that New England needs additional capacity.
“The problem [there] is … that for a variety of reasons, it’s never going to get built, in large part because pipelines want long-term contracts, and generators don’t want to pay for long-term contracts when they only need the gas 10 to 14 days a year,” when it’s coldest, Glick said. “So [high prices have] nothing to do with the amount of pipeline capacity. … It’s simple supply and demand, and demand in particular is going up at a very great rate.”
Wide deployment of ground source and district heat pumps (GS/DHP) could reduce New York’s peak electric loads by up to 12 GW, but it’s unclear whether the increased cost of the systems would produce net savings, according to an analysis shared with the state Climate Action Council (CAC) last week.
The New York State Energy Research and Development Authority (NYSERDA) conducted the analysis as a follow-up to a case study last year that found a higher adoption of GS/DHP would result in a net increased cost versus air source heat pumps, which have lower coefficient of performance. “But we recognized there were a lot of uncertainties in that work, so we committed to coming back to the council to further explore some of those uncertainties,” said Carl Mas, director of NYSERDA’s Energy and Environmental Analysis Department.
The new analysis found that boosting the share of buildings with GS/DHP from 25% to 65% would increase building sector costs by up to $19 billion because the technologies are more expensive than air source heat pumps. The more efficient heat pumps would save the electric system between $15 billion and $23 billion in reduced firm capacity, battery storage and renewables — meaning a net increase of up to $4 billion or a net decrease of $4 billion.
“On balance, we see that the savings that can accrue from heat pumps are on the same order as the net costs,” Mas said, meaning that there is not “clear winner [but] significant opportunity.”
As a result, Mas said the CAC’s scoping plan should include “an adaptive policy process” to monitor the relative costs of air versus ground heat pumps over time.
“As we see the evolution of the grid, and what the costs of those are, we can over time decide what the best tradeoffs are going to be,” he said.
Buildings cause one-third of the state’s greenhouse gas emissions, making them central to meeting the goals of the state’s Climate Leadership and Community Protection Act (CLCPA).
Managed vs. Unmanaged Electrification
In addition to comparing ground and air source heat pumps, the new analysis also considered the tradeoffs between a “managed” electrification — more energy efficiency and smart devices to manage peaks — versus an “unmanaged” electrification with less EE and smart devices. Managed building electrification would see building stock experience “significant levels of deep energy efficiency,” while unmanaged load growth would see “fewer deep shell retrofits,” Mas said.
NYSERDA projects peak load, currently 30 GW, will grow to 40 GW by 2050 under a managed scenario, as the state transitions from a summer- to a winter-peaking system. With unmanaged electrification, the peak would nearly double to 58 GW, but that would be cut by as much as 12 GW with higher GS/DHP penetration. The conclusion? More GS/DHP would have “a significant impact if we don’t realize the high levels of energy efficiency and peak load management” under a managed transition, Mas said.
A managed electrification would have a cost of around $80 billion, while an unmanaged system would see costs at least $27 billion higher because of a need for 14 GW of additional firm capacity and battery storage and 4 GW of incremental renewable generation. Uncertainty over distribution system impacts could add another $14 billion to the price tag, Mas said.
Mas said the analysis did affirm that improving building energy efficiency is critical for achieving CLCPA emissions reductions. But with the added costs of installing GS/DHP systems estimated at up to $19 billion, he said, there is not a clear case for recommending the more efficient systems now.
“We see the ground source heat pumps and district heat pumps have the potential [to reduce] the development risks that would come with having to build additional gigawatts of clean firm resources and the other distribution and transmission infrastructure that come from it,” he said. “And that’s what we’re recommending: that there be a continued effort to monitor and evaluate the relative … costs of ground source heat pumps and district heating, compared to how the electric system actually evolves over time.”
Comments
New York Public Service Commission Chair Rory Christian said the study “hit the nail on the head” when highlighting the significance of energy efficiency. “If you can be much more efficient in how our buildings are built and operate, then the need to build up bigger systems … is diminished significantly.”
Anne Reynolds, executive director for the Alliance of Clean Energy New York, asked whether there was significant difference in the costs of heating systems in urban versus suburban areas.
Mas responded that there were “different economics depending on the environment.” He noted that the analysis only used averages, saying there “certainly needs to be a specific utility-by-utility analysis for their specific service territories.”
Next Steps
The CAC will reconvene on Tuesday to give another integration analysis update and discuss any remaining feedback topics, including climate justice, before assembling a full draft scoping plan.
The council plans to spend November discussing redlines to the draft plan, then spend December making decisions on outstanding items, with a vote on a final scoping plan set for Dec. 19.
ANN ARBOR, Mich. – Ann Arbor Mayor Christopher Taylor appears on his way to a third term after cruising to victory with 61% of the vote in the August Democratic primary; Republicans did not field a candidate.
Whether voters will also back his proposal for a 1 mill property tax increase to fund climate projects on Nov. 8 is less certain.
There is a “moral imperative to act on climate change,” Taylor said in an interview, repeating a phrase he has used since proposing the tax increase a year ago. While some suggest voters may be feeling “millage fatigue” after approving several city and school district tax increases in recent years, Taylor said he is confident residents and business owners will recognize the need to pay for actions to meet the city’s goal of reaching net zero emissions by 2030.
“I hope and believe Ann Arbor voters recognize we can’t get the benefits of climate restoration without resources,” Taylor said. “We’re all gonna pay for climate change,” he said, whether civilization takes steps to “counterbalance climate change,” or to protect itself from its impacts.
The tax, which would add $153 annually for an average property with a taxable value of $153,000 (half of the average fair market value of $306,000), would be in place for 20 years. In 2021, Ann Arbor property owners paid 50 mills.
The tax would raise an estimated $6.8 million in the first year. City Council passed a “shadow budget” saying it would spend
$1 million on compost programs and expanded recycling for “a zero waste, circular economy;”
$2 million on community solar, district geothermal and discount pricing of renewable energy;
$750,000 on services to help low-income residents save money and improve weatherization;
$500,000 on energy efficiency for residents and businesses;
$500,000 on neighborhood and community preparedness for climate change, including tree planting, rain garden installations and heat and flood mitigation;
$1 million to expand walking paths and bike lanes; and
$1 million to expand electric vehicle charging access — with an emphasis on renters and multi-family housing — and support electrification of appliances and heating and cooling.
The city currently spends about $2 million annually on climate measures, half from a Washtenaw County rebate and half from the city’s general fund.
Taylor said helping the city’s low-income Southeast Bryant neighborhood is a priority. Taylor said the city’s efforts to rebuild the tree canopy has been lacking in lower income areas. He also expressed a desire to help low-income households acquire more efficient appliances and access to renewable energy.
After winning his primary in August, Taylor’s only opponent in the liberal-leaning home of the University of Michigan is an independent. Taylor also appears poised to increase his 7-4 margin on council, as three candidates on his ticket defeated incumbents opposed to him.
City Council authorized a referendum on the tax last December. Ann Arbor would be one of the few communities in the nation to have a tax dedicated to climate action. Boulder, Colorado, voters enacted a similar tax in 2006 that raises about $1.8 million annually. No other localities in Michigan are considering such a proposal.
Tax increases have often proven contentious in Michigan, but the campaign on the tax proposal has been relatively quiet. There is an organization backing the proposal, A2 Climate Voters, which has gathered campaign donations. The city, which has a webpage backing the tax, spent nearly $20,000 to mail a postcard describing the proposal to some 56,000 city addresses.
There is no actively organized opposition to the tax proposal. One of the few, criticisms of the proposal came from a co-host of a podcast that deals with Ann Arbor issues and politics. The co-host said local residents may feel millage fatigue after voting in recent years on a sidewalk proposal and a large school improvement proposal. Even though she raised the criticism, the co-host also said she would probably vote for the proposal.
Missy Stults, Ann Arbor’s sustainability and innovations director, acknowledged that property owners don’t welcome tax increases, but said there are few other ways for local communities in Michigan to raise funds needed for projects. “We’ll see” if the city’s voters are tired of millages, she said.
Taylor expects the campaign will heat up with less than a month left to the election. More mailings are planned, and pro-proposal yard signs will be distributed, he said.
Taylor said businesses have a range of opinions on the proposal. But businesses also understand that all have to take action to combat climate change and want to be part of a community that meets its environmental responsibilities, Taylor said.
“On balance, everyone recognizes we need to do our part,” he said.
Taylor said he has heard nothing from other municipalities about the tax proposal. If the tax passes, Taylor said, he might get a phone call from another official considering similar action.
If the voters reject the tax, Taylor said, he expects the phone to stay quiet.
ISO: Champlain Hudson Critical to NY Reliability in Future
The NYISO Operating Committee last week approved the ISO’s draft 2022 Reliability Needs Assessment (RNA), which did not identify any reliability needs for the 10-year study period but found that resource adequacy and transmission security margins are tightening over time.
But NYISO emphasized that the Champlain Hudson Power Express (CHPE) transmission project is critical to meeting future reliability needs, and delays could result in even thinner margins, creating significant risks to certain peakers who may be asked to continue operation when they otherwise would be unavailable because of non-compliance with new rules. An ISO representative said that “we’re putting all of our reliability eggs into the CHPE basket.”
The state also views the HVDC line, which would run from Quebec to New York City, as critical to its clean energy goals. (See NYSERDA Seeks 1-Year Delay for Tier 4 RECs.)
The report also noted that New York is likely to experience even smaller margins if additional power plants become unavailable or if future demand outpaces current forecasts. (See “RNA Draft Report Findings,” NYISO Transmission Planning Advisory Subcommittee Briefs: Oct. 3, 2022.)
The RNA also found that extreme weather events can result in transmission security deficiencies in the city, while gas supply shortages during winter peak conditions can eventually threaten reliability needs after 2032, when gas is predicted to become deficient in meeting statewide system needs.
The draft will be presented to the Management Committee on Wednesday for voting and to the NYISO Board of Directors for final approval in November.
NYISO-PJM Stability Analysis
NYISO recommended that its interconnection reliability operating limit (IROL) with PJM be removed after a study showed no stability issues even at transfer levels well in excess of the limit.
Robert Golan, NYISO manager of operations and engineering, presented the OC with the results of the study, which modeled three 115-kV tie lines with maximum transfers, winter ratings and optimized generation dispatch. NYISO-to-PJM flow achieved an emergency transfer limit of 2,440 MW, while PJM to NYISO achieved 3,175 MW.
NYCA transmission system interface | NYISO
The study also evaluated 61 NYISO and 68 PJM contingencies, finding that for NYISO to PJM, transfer levels were increased to 164% of the limit, giving the ISO a new proposed stability limit of 3,600 MW. From PJM to NYISO, the emergency transfer thermal limits increased to 150%, creating a new proposed limit of 4,250 MW.
The ISO “saw acceptable responses” in both the New York Control Area and PJM when examining “both angular and voltage response of each system,” Golan said.
Golan was quick to note, however, that both NYISO and PJM would reassess the need for the reinstatement of an IROL based on future system changes and five-year periodic reviews.
In response to questions around PJM’s status, Golan said NYISO has been “working hand-in-hand with PJM over the past year,” and that the RTO is currently waiting for the ISO to “go through the stakeholder process so that they can know when this report is approved.”
CESIL Updates
The committee approved manual updates implementing recently approved tariff revisions that preclude demand-side resources from curtailing critical electric system infrastructure load (CESIL) in response to ISO-called events and tests, beginning Nov. 1.
CESIL includes natural gas compressors and storage facilities; LNG storage, liquification and vaporization; refineries; electric system control centers; and natural gas system control centers, terminals, and metering and regulation stations. The revisions are intended to improve conditions for the upcoming winter, when gas supplies may short. (See “Critical Infrastructure Load,” NYISO Business Issues Committee Briefs: June 22, 2022.)
Ancillary Services
The committee also approved manual revisions regarding NYISO’s voltage support, operating reserves and black start capability services, such as preparing for the possibility of new technologies entering black start capability service and adding a 15-business-day window for ISO review of voltage support test data.
The ISO incorporated a “wish list of little things” that it had wanted to include in their manuals to confirm that market and review functions were in line with real-time situations.
Along with the new review period for voltage support reporting submissions, NYISO added a new allowance for out-of-period reactive capability testing and clarified language around data transmission requirements.
The 15-day review period was welcomed by stakeholders, with Brookfield Renewable’s Christopher LaRoe saying that the proposal for “the ISO to reply with a status besides ‘pending’ is helpful” because it will solve the current problem of “tight time constraints around the deadlines for suppliers to submit data for testing.”
The ISO also made terminology changes within its black start capability manual that would prevent innovative technologies from being excluded from these processes, with NYISO’s Harris Miller stating that the ISO is “trying not to exclude anyone.”
The changes become effective Nov. 1.
Interconnection Queue Streamlining
Zach Smith, NYISO’s vice president of system resource and planning, told the committee that the ISO has identified analyses that can be eliminated from the System Reliability Impact Study (SRIS) for 30 to 40 projects in the interconnection queue.
Smith noted that NYISO has been actively looking for ways to expedite SRIS processes to fix the backlog of projects currently waiting in the interconnection queue. (See NYISO Proposes Fixes for Interconnection Backlog.)
The categories identified are “immediate actions the ISO can take” to address these concerns without “sacrificing the quality of work or reliability of the grid” while remaining “in compliance with the relevant tariff and NERC standards,” according to Smith.
Stakeholders expressed support for these efforts, with Kaley Bangston from Invenergy stating that her team “thanks the ISO for putting the work and thoughts together to make this happen.”
NYISO plans to return to the Transmission Planning Advisory Subcommittee and the OC in November to share a more detailed list of projects that the ISO proposes to modify the study scope.
NYISO stakeholders on Monday voted to recommend that the ISO’s Class Year 2021 (CY21) study results and cost allocations move to the Operating Committee for a vote next week.
Nearly 120 stakeholders attended Monday’s Transmission Planning Advisory Subcommittee meeting, where NYISO shared the list of upgrades required to reliably interconnect the 57 projects included in the CY21 study, at a cost of up to $900 million.
NYISO Manager of Facility Studies Wenjin Yan shared that 54 projects were requesting both energy resource interconnection service and capacity resource interconnection service (CRIS), while three members were CRIS only.
Decision Process and Timeline
With the upgrades and cost allocations for the CY21 projects identified, the ISO will now seek OC approval for the class year study reports, which include the allocations for CY21 system upgrade facilities (SUF) and system deliverability upgrades (SDU).
The OC’s approval of the CY21 study report will trigger the start of the initial decision period, during which class year developers will have 30 calendar days to accept or reject their cost allocations for SUFs and SDUs, and deliverable megawatts, if available, by providing NYISO either an acceptance or non-acceptance notice.
Developers who reject their cost allocations during this initial period will trigger additional decision rounds in which the ISO will issue within 14 calendar days a revised CY21 that removes projects that rejected their cost allocation, whereupon the remaining developers will have an additional seven calendar days to provide their acceptance or rejection to the revised CY21 cost allocations.
If additional rejections occur in subsequent rounds, the rejected projects are removed from the CY21 and the ISO will issue another revised CY21, and this iterative process will continue until all remaining CY21 members accept their respective cost allocations.
Once the remaining CY21 projects have accepted their cost allocations, developers will have five business days to pay cash or post security for the full cost allocation amount, and any developers who intend to post security are encouraged to reach out to applicable transmission owners to ensure the type of security that they intend to post meets the applicable transmission owners’ security arrangement requirements.
NYISO pointed out that developers who fail to notify the ISO by a stated deadline will be deemed as submitting a non-acceptance notice and removed from the class year.
Due to projects that reject their cost allocations in one round, the remainder of the CY21 members may see their CY21 cost allocations and any deliverable megawatts revised based on the updated study results.
NYISO also shared rules and procedural elements of this decision process, noting how developers that have additional SDU studies may accept their SUF project cost allocations, but separately accept or reject their SDU costs.
Developers with additional SDU studies not yet completed before the start of the CY21 initial decision period are given the ability to accept their SUF costs at this time and proceed with the additional SDU studies until they are completed or they can wait until the additional SDU studies are completed and, at that time, accept or reject the SUF and SDUs.
The ISO shared anticipated CY21 calendar breakdown, noting that the CY23 study could start as early as Jan. 3, 2023, with one decision round, or Feb. 13, 2023, should the CY21 study enter three decision rounds; however, CY21 can proceed with more than three decision rounds.
In response to questions about the timeline and whether the process could be sped up, Yan responded that “there is no reason we are going to hold up the results” if things could move faster than anticipated as the ISO “will use all their efforts to meet class year and tariff schedules.”
CY21 is considered complete once the class year report has been completed and all remaining developers have accepted and paid — or posted — security for their respective cost allocations.
Next Steps and Voting
Attending stakeholders recommended that the CY21 final results and cost allocations proceed to the OC for approval, though one objection was submitted by Empire Offshore Wind LLC, which represents two CY21 projects: Q958 (EI Oceanside 1) and Q959 (EI Oceanside 2)
The final report will be presented for approval at the next OC on Oct. 24. If approved, developers will have 30 calendar days to decide whether to accept their respective CY21 cost allocations.
If all 57 CY21 members accept their cost allocations, and no further decision rounds are required, then the ISO anticipates CY21 will end on Dec. 2, with the Class Year 2023 (CY23) study expected to start on Jan. 3, 2023.
MISO remains committed to beefing up and making information from its generation retirement studies more public as it outlined a number of study changes it plans to soon file with FERC.
The grid operator told stakeholders Wednesday it plans to impose a yearlong notice requirement on retiring generation before it begins retirement studies under Attachment Y of its tariff. It also plans to conduct the studies on a quarterly basis, share with stakeholders the megawatt value of retirement requests, and discourage reliance on load shed as a valid mitigation option when voltage and thermal violations are uncovered in its steady state analyses. (See MISO Bolstering Generation Retirement Studies Amid Capacity Shortage.)
“I know it’s a major change, but this will help us perform better studies. We believe there may be a ramp up in retirements, and this will help us study them,” Sydney Yeadon, with MISO’s resource utilization team, told stakeholders during a Planning Advisory Committee meeting.
Currently, generators intending to retire must notify the RTO six months ahead of time and studies are conducted as the notices are received. Staff says the changes are needed given the increase in retirement notices.
MISO says it will need four quarterly study periods worth of notice, rather than 52 weeks, from generation that is being retired or suspended.
MISO will define first-quarter retirement studies as beginning the first business day of March through the last business day of May; the second quarter as beginning the first business day of June through the last business day of August; the third quarter as beginning the first business day of September through the last business day of November; and the fourth quarter as beginning the first business day of December through the last business day of February.
The new study process will allow one quarterly study period after FERC approval for generator owners to prepare to use the new system.
Stakeholders asked whether the grid operator will study alternatives to keeping aging or uneconomic generation online under system support resource (SSR) agreements. Staff responded that it annually re-evaluates the need for SSRs after they are designated and said they view the agreements as a last resort for reliability.
DTE: Consider Old Generators for Reactive Power
DTE Energy is continuing its push to give old thermal generators new life as synchronous condensers that furnish the grid with reactive power.
During an Oct. 11 Planning Subcommittee, DTE’s Kenneth Gavin said that as dispatchable power retires and renewable integration gains traction, MISO will find a greater need for reactive power.
The utility says that existing generators can be cost-effectively converted to zero-emissions synchronous condensers after they suspend operations through MISO’s Attachment Y retirement process. It says that such conversions “can supply clean reactive power to the grid that maximizes performance and maintains customer affordability.”
Sustainable FERC Project’s Lauren Azar said the sooner MISO and members begin addressing grid technologies to support a majority renewable mix, “the better off we’ll all be.”
WPPI Energy’s Steve Leovy said it’s an opportune time for the RTO to signal a need for synchronous condensers because several thermal generators are announcing or weighing retirements.
Currently, retiring generators in the MISO footprint that are converted into synchronous condensers aren’t eligible for compensation under the tariffs Schedule 2, which outlines compensation for reactive supply and voltage control. The grid operator’s retirement process would take away a converting plant’s interconnection rights.
