Search
`
November 16, 2024

Posted on

SERC Gives Spring Checkup on Transmission Line Ratings

Maintaining bulk electric system reliability is similar to maintaining personal health, Tim Ponseti, SERC vice president of operations, said at the regional entity’s Spring Reliability and Security webinar Tuesday.

That begins with preventative measures, such as outreach and education about risks. SERC has “had 13 straight board meetings where we’ve highlighted the various issues, common failure modes, best practices and things to look out for regarding facility ratings,” Ponseti said.

Inaccurate transmission line ratings can cause a system operator to lose real-time situational awareness, or to operate equipment beyond its capabilities, damaging it or causing lines to sag beyond design, which could result in unplanned and potentially widespread outages.

Eighty-six percent of FAC-008 violations in SERC’s footprint are related to discrepancies between documented facility ratings and actual field conditions, said Dulce Plaza, SERC legal counsel, who offered a sneak peek at a report the RE will release later this month.

“If you give operators a rating, they’re going to operate to it, right or wrong, so it’s important they have good numbers and data to operate from,” Ponseti said in giving his own presentation. Planners use facility ratings to design capital projects and future improvements to the grid, so accurate facility ratings have a far-reaching impact. “Whether it’s every one, two, three or four years, we’ve touched base and given health checkups essentially covering almost 90% of our transmission models and generation megawatts in our footprint.”

Operations and planning audits often run into missing or altered equipment, or jointly owned equipment, said Heath Martin, SERC senior O&P auditor, who closed the session with a presentation on “things to think about.”

Road Debris (SERC) Content.jpgSERC

Equipment might need special consideration when applying the facility ratings methodology, generally older equipment that has older construction practices and clearance thresholds, perhaps older equipment in general that may not meet current standards, Martin said.

He showed a picture of a painted white line marking the edge of a country road that curved around a fallen branch.

“‘It’s not my job to remove that limb, so I’m just going to paint around it and keep going’; that is not the correct attitude when it comes to jointly owned facilities,” Martin said.

Posted on

Deficiency Notices for MISO’s Seasonal Capacity Auctions Bid

FERC doled out two deficiency letters to MISO Wednesday over the grid operator’s plans to institute a four-season capacity market, availability-based resource accreditations and a 50% minimum capacity obligation.

The commission said it lacked several specifics on the resource adequacy overhaul, including a fuller defense from the RTO of the minimum capacity rule’s new accreditation and deadline information.

MISO late last year sought FERC’s approval to perform four seasonal capacity auctions with separate reserve margins by 2024 and apply a seasonal accreditation based on a generating unit’s past performance during tight system conditions (ER22-495).

The RTO also made a related filing to establish a minimum capacity obligation that requires a load-serving entity to demonstrate it has secured at least 50% of the capacity required to meet their peak load before the voluntary auctions (ER22-496).

Stakeholder reactions have been mostly negative. They have said a stricter accreditation based on risky hours that can’t be predicted with certainty would result in volatility and unfair penalties to generation. Others also have said staff hasn’t explained the reliability problems the minimum capacity obligation is meant to correct. (See MISO’s Seasonal Capacity Proposal Opposed at FERC.)

The commission told MISO “quantitative evidence” that demonstrates historical performance of units is “more indicative of future performance during emergency periods” than the existing unforced capacity accreditation process.  

FERC said it was interested in seeing analyses that show the need for a higher reserve margin requirement in the winter than the summer in some zones during certain years. It asked why MISO intends to clear four seasonal auctions simultaneously instead of conducting sequential, single-season auctions. The commission also said it needed a rationale as to why the RTO would allow clearing prices in a single season to exceed generation’s cost of new entry.

The commission asked MISO to explain why it wasn’t similarly ascribing seasonal variability to its planning reserve margin analysis and local clearing requirements within resource adequacy zones. It also asked what steps the RTO will take to establish a seasonal planning reserve margin and how the new availability-based resource accreditation will factor into loss-of-load calculations.

FERC said it was unclear whether MISO intended to use different predicted risky hours across different units for accreditation. It also asked whether a unit’s performance in other seasons would be used as a basis for accreditation in another season.

The commission said it did not understand why the grid operator didn’t extend the availability-based accreditation beyond thermal resources to its solar and wind resources, which are under an existing accreditation that’s also based on availability during times of system need.

FERC also asked for justification in requiring its demand response resources to increase their availability for more calls in a seasonal paradigm versus an annual construct.

Finally, the commission asked MISO to more fully explain its requirement that units replace their capacity if they’re on outage longer than 30 days when there is a requirement for a 120-day period between a unit’s planned outages.

On the minimum capacity obligation, FERC wondered why the RTO said it will initially apply the obligation on a systemwide basis and then transition to a subregional application of the rule in 2025.

The commission asked MISO to explain how it settled on a five-month period for a market participant that receives an obligation before submitting proof it will meet 50% of its load before. It also asked the grid operator to describe the health of its bilateral market and the ability of market participants to secure excess capacity.  

Posted on

MISO: 2021 Member Savings Exceeded $3B

MISO said Wednesday that it saved members more than $3 billion over the course of 2021.

The grid operator said its value proposition analysis showed a range of $3-$3.8 billion in savings for members that participate in the markets only through bilateral contracts.

The value proposition measures the collective annual savings for members. Last year, MISO estimated it saved its members around $3.5 billion in 2020. (See MISO Touts $3.5B in 2020 Savings for Members.)

The grid operator said on average, it saves its membership about $3.4 billion annually.  

MISO said it quantifies benefits through the more efficient use of generation, reduced need for new generation, and the stronger reliability that comes with a resource sharing pool. The grid operator said it has tracked about $36.3 billion in savings since 2007.

The diverse geographic footprint offered the biggest value to members in 2021, saving them $1.7-$2.3 billion, the RTO said. It said differing loads and diverse generation sources has allowed it to operate with a reserve margin of 17.9%. It had been more than 20%.

The grid operator said the system’s additional wind generation has yielded $467-$530 million in savings. MISO also said its ability to optimally dispatch the most economic energy in its real-time and day-ahead markets saved members anywhere from $471 million to $521 million over the year. It estimated savings from heightened reliability at $285-$310 million.

“Our grid is changing at a rapid pace, and MISO is working closely with our member utilities to better understand how their plans will impact the MISO grid,” Wayne Schug, vice president of strategy, said in a press release accompanying the report. “We are committed to ensuring MISO’s value proposition evolves and aligns with the changes impacting our members and MISO.”

Posted on

Massachusetts Startup Pitches Event Waste Management for Cleantech Accelerator

The startup G Force Waste Sorters is trying to disrupt the waste industry and reduce greenhouse gases by recovering high-value, post-consumer recyclables from trash at major sports and entertainment venues.

Michelle Guiney, president of Massachusetts-based G Force, pitched the startup Wednesday at a virtual event for the Cleantech Open Northeast accelerator program, answering the question, “Why venue trash?”

Between 40 and 50% of trash at large event venues is recyclable and 20 to 30% is compostable, according to Guiney.

“To exponentially increase the volume of trash sorted, I designed a mobile mechanical waste-sorting system that will be able to defer up to 80% of the venue trash from landfill or incineration,” she said.

For context, she added, one venue with a seating capacity of 40,000 generates about 1,200 tons of trash annually. G Force could recover 600 tons of recyclables and 360 tons of compostables from the facility’s annual waste while also helping avoid 2,300 metric tons of carbon dioxide (MTCO2).

“It’s an unprecedented environmental benefit for just one venue,” Guiney said.

An Outdoor Media Buyers ranking of U.S. arenas and stadiums includes 141 facilities with seating capacities between 40,000 and 107,000, putting the minimum emissions avoidance potential for the G Force business model in those locations around 325,000 MTCO2/year. The yearly avoided emissions could equate to removing 71,000 internal combustion engine passenger vehicles from the road, based on EPA vehicle emissions estimates.

The anticipated environmental benefits of G Force’s business are what technology accelerator Cleantech Open looks for in companies applying to become a new cohort member. With the support of sponsors, the Northeast arm of the national program works in partnership with the Northeast Clean Energy Council to help early-stage startups that have an environmental focus.

Companies chosen for a cohort receive training, mentorship, investor connections and opportunities to compete for cash prizes.

The mentoring part of the program is a “great process” for mentor and mentee, said Mark Dockser, professor of practice at Northeastern University’s D’Amore-McKim School of Business, and a Cleantech Open mentor.

“For the mentors, it’s a chance to meet and work with some great folks who have very similar interests and different expertise,” Dockser said during the event Wednesday. “For the mentees, it’s a chance to learn to analyze, to vet ideas, to do some problem solving … and get to market to find some of the right partners.”

Mentors for cohort members match the specific needs of the startup business model, according to Andrew Myers, professor of civil and environmental engineering at Northeastern. Myers and Jim Papadopoulos, a senior research engineer at Northeastern, won the 2020 Cleantech Open NE for their startup T-Omega Wind.

The team won for a redesigned floating offshore wind turbine that could reduce material costs and simplify manufacturing.

“The go-to-market strategy that we conceived of as part of the Cleantech Open in 2020 is the one that we are now fleshing out and including in our pitch deck for investors the spring,” Myers said during the event.

Startup applications for the 2022 Northeast cohort are due April 17. The administrators will select cohort members in May and announce program winners at an event in September, when the cohort’s top startups will have a chance to pitch in a public form.

Posted on

PJM Monitor: Prices, Coal Power Bounced Back in 2021

PJM energy prices last year surged to their highest levels since 2014, more than making up for declines from the pandemic-driven economic downturn in 2020, according to the Independent Market Monitor’s annual State of the Market report, released Thursday.

The RTO’s average load-weighted real-time LMP ricocheted to $39.78/MWh, up 82.8% from 2020’s record low of $21.77. While the increase was perhaps to be expected, real-time load only increased by 3.6%, returning to pre-pandemic levels after falling by 4% in 2020.

Average short-run marginal costs (Monitoring Analytics) Content.jpgAverage short-run marginal costs in PJM since January 2014 | Monitoring Analytics

The increase in energy prices was mostly a direct result of increased fuel costs for generators, including higher natural gas prices. In a press conference Thursday presenting the report, Monitor Joe Bowring said that among the factors driving the increase in gas prices was reduced production in 2020 and severe weather events, including the February 2021 winter storm.

The Monitor did not measure the impacts of the storm on PJM separately, but Bowring said “it definitely had an effect, especially in the Midwest.” It also raised a concern that the Monitor has about the gas market.

“There’s no logical reason to have gas prices be $2,000/dekatherm, or even $1,000/dekatherm,” he said. “So we’re very concerned about market power on the gas side … during extreme conditions. That’s outside our purview, but it’s at least partly within FERC’s purview, so we think that needs to be looked at.”

In its report, the Monitor wrote, “The role of gas-fired generation highlights the importance of ensuring that PJM has real-time, detailed and complete information on the gas supply arrangements of all generators and that PJM consider rules requiring capacity resources to have firm fuel supplies. It is also essential that FERC consider and address the implications of the inconsistencies between the gas pipeline business model and the power producer business model and the issue of market power in the gas commodity market under extreme weather conditions.”

Return of the King

While gas remained the dominant fuel source in PJM, coal-fired generation shot up last year.

Electricity generation from coal rose 17.8%, compared to a 2.4% decrease in gas-fired output. Coal also made up 22.2% of the fuel mix in 2021, compared to 19.3% in 2020. Oil-fired generation rose 11.5%.

Coal prices likely increased on the back of rising gas prices. But as coal mines continue to shutter unabated, supply continues to thin. “The changes in relative fuel prices slowed but did not change the long-term decline in the share of coal and the increase in the share of gas,” the Monitor wrote.

The Monitor’s report came after the International Energy Agency reported Tuesday that energy-related global CO2 emissions increased by 6% in 2021, mostly from the use of coal-fired generation.

“The recovery of energy demand in 2021 was compounded by adverse weather and energy market conditions — notably the spikes in natural gas prices — which led to more coal being burned despite renewable power generation registering its largest ever growth,” the IEA said.

While solar nearly doubled its output last year, increasing by 91.6% to 7,412.2 GWh, it still only makes up less than 1% of the fuel mix in the RTO. Renewable output — including solar, wind, waste, hydro and biofuel — only rose by about 10.2% and just barely increased its share of the fuel mix, mostly because of the increase in solar.

REC Market

The Monitor included 13 new recommendations for PJM in its report, but Bowring singled out an old one, dating back to 2010, in his presentation: a single PJM-operated forward market for renewable energy credits.

The recommendation has perhaps taken on more urgency as some states aggressively increase their renewable portfolio standards each year up to 2030.

“Given that states are going to continue to subsidize renewable energy through RPS standards and through RECs, the markets would work better for everybody” with a single market for RECs, Bowring said, with an agreed-upon definition for what qualifies for credits and a single clearing price. “Of course, all of that would be dependent on the states wanting to do it and agreeing to do it. But we think that would be a way to make the provisions of those subsidies … significantly more efficient.”

The Monitor still recommends a single, PJM-wide carbon price as the most efficient way to reduce emissions, but a single REC market would be the next best thing, it wrote. Such a market “would provide better information for market participants about supply and demand and prices, and contribute to a more efficient and competitive market and to better price formation. This could also facilitate entry by qualifying renewable resources by reducing the risks associated with lack of transparent market data.”

Posted on

Renewables Highlight 2021 PJM RTEP Report

PJM saw interconnection requests for solar generation more than triple since 2019, now making up more than half the interconnection queue, according to the 2021 Regional Transmission Expansion Plan (RTEP) report released Tuesday.

The annual report highlighting transmission projects approved last year by the PJM Board of Managers features several trends, including the continuing shift in the RTO’s generation mix driven by new natural gas-fired plants, the deactivation of coal-fired plants and the increasing volume of renewable generation.

PJM processed 1,351 new service requests in 2021, nearly triple the 476 requests made in 2018. The new service requests totaled 104,316 MW of nameplate capacity in 2021.

A total of 139,937 MW of generation interconnection requests was actively studied by PJM last year, a number nearly equal to the RTO’s all-time winter peak of 143,295 MW set on Feb. 20, 2015.

On the renewable energy front, solar generation currently makes up 58% of the interconnection queue, a total of 94,000 MW of the 160,000 MW of resources in the queue. In the 2019 RTEP, solar requests stood at 47% of the 75,432 MW in the queue.

“Previously, solar projects were smaller in size and limited to a handful of areas,” the report said. “Now, individual projects can reach hundreds of megawatts, driven by states’ renewable portfolio standards goals, and are seeking interconnection in every PJM transmission zone.”

Project Numbers

The PJM board approved a total of $920 million among 118 baseline transmission projects in 2021.

Total approved RTEP projects (PJM) Content.jpgTotal approved RTEP projects by the PJM Board of Managers as of Dec. 31, 2021. | PJM

Of the projects, 52% ($478 million) of them were driven by transmission owner criteria, 25% ($229 million) by PJM and NERC criteria and 23% ($213 million) by 52 generator deactivations or retirements.

PJM noted that large-scale transmission projects above 345 kV remain “uncommon” in the RTO, as load growth fell below 1% to a normalized 10-year RTO summer peak growth rate of 0.6%. The average 10-year-annualized summer growth rates for individual PJM zones ranged from -0.5% to 1.5%.

“Load forecasts from the past five years reflect broader trends in the U.S. economy and PJM model refinements to capture evolving customer behaviors,” PJM said in its report. “These include more efficient manufacturing equipment and home appliances and distributed energy resources, such as behind-the-meter, rooftop solar installations.”

PJM said the projects approved in 2021 responded to “diverse needs” such as upgrades and replacement of aging equipment and facilities to meet reliability and resilience criteria, the “minimization” of system congestion for market efficiency, localized reliability needs and generator deactivations.

In preparation for new generation resources coming onto the grid, the board also approved 34 network system enhancement projects totaling more than $47 million. The board has approved network facility reinforcements totaling more than $6.5 billion since the inception of the RTEP process in 1997.

Offshore Wind

With the growing number of offshore wind projects coming into the interconnection queue, PJM said the injection of thousands of megawatts of power will change how power flows across the grid in the Northeast and Mid-Atlantic. PJM said “efficiently harnessing” the new power source is going to require extending the existing transmission grid to offshore generation sources and deliver their energy to load centers along the East Coast.

Maryland, New Jersey and Virginia have established offshore wind targets totaling 14,723 MW with planned in-service dates of 2035.

In 2021, PJM planned for the offshore wind transmission expansion, partnering with NYISO and ISO-NE with the goal of achieving 30 GW of operational offshore wind by 2030. The RTO also worked with New Jersey under the “state agreement” approach to help identify the most efficient and economic solutions to accommodate offshore wind.

“Although offshore wind is on a longer planning horizon, the potential for development is substantial,” PJM said in the report. “Future system enhancements will solve the challenges that these locationally constrained resources present. Moreover, they will also address the interregional implications associated with wind lease areas that can also serve adjoining systems north and south of PJM’s RTO borders.”

Posted on

IEEFA: Blue Hydrogen not Clean nor Competitive

The private, nonprofit Institute for Energy Economics and Financial Analysis (IEEFA) argues that “blue” hydrogen, produced using natural gas, cannot be environmentally friendly or affordable.

In a report completed in February and discussed in a webinar Thursday, IEEFA analysts bluntly rejected the entire Department of Energy initiative to create regional hydrogen hubs producing and using blue hydrogen as a costly technological blunder based on “flimsy economic and environmental footing.”

Blue hydrogen production starts with high-temperature steam reforming of methane (CH4), splitting the hydrogen atoms from the carbon atoms. The resulting carbon dioxide is simultaneously captured and sequestered.

Gray hydrogen, in which the carbon split from the methane is not captured, has been produced for years as an industrial gas, frequently used in oil refining. It is significantly less expensive than green hydrogen, produced by electrolysis of water using renewable energy. Thus, blue hydrogen has been advocated by an avalanche of DOE and industry webinars and reports as a more environmentally friendly compromise.

But IEEFA is sharply critical of that argument. Because blue hydrogen is made from natural gas (which is 77% methane), any analysis of its environmental integrity must account for drilling, fracking and leakage at the well head and pipelines. Though methane only lasts about 12 years in the atmosphere, it is 25 times more effective at trapping heat than carbon dioxide.

IEEFA analyst David Schlissel said a major problem in making blue hydrogen as clean as green hydrogen is that at least 90% of the resulting carbon dioxide would have to be captured.

“Capturing 90% or more of the CO2 produced at a project is the holy grail for CCS [carbon capture and sequestration]. Proponents of blue hydrogen will say outright, or will more likely suggest or imply, that 90% carbon capture has been proven or demonstrated at existing projects.

“But this is not true. No commercial-scale project has captured 90% or more of the CO2 produced by the project over the medium or long term, by which I mean years and decades, which they will have to do if carbon capture and sequestration will be an effective tool for reducing CO2 emissions and concentrations,” he said.

“Achieving this goal sporadically clearly is not enough. Blue hydrogen combines the worst of two worlds. It uses fossil fuels and an unproven carbon-capture technology. What could possibly go wrong?”

Blue hydrogen’s reliance on CCS means it has “has very weak economic prospects,” IEEFA analyst Suzanne Mattei said. And sequestering carbon deep underground is another expensive technology that has not been proven to be economically viable, Schlissel said.

Mattei added another problem blue hydrogen producers will face: The cleaned-up gas is not as attractive to many corporate buyers as green hydrogen will be.

“The blue hydrogen projects are of limited value to investors who are looking to up their green credentials. Because they are pulling this fuel out of the ground, sending it through pipelines; and the leakage problems are significant, rampant really,” she said.

Proponents have asserted that they will use responsibly sourced natural gas, she said. But “a major theme of our report is that you have to look at the real-world experience … that the Environmental Protection Agency has been trying to control methane from drilling and pipeline transport for a long time,” she said.

EPA is currently trying to develop a new regulatory process, she added. If the agency is successful in forcing the gas industry to address the problem, the cost of gas will increase, she said.

Blue hydrogen “is both an environmental issue and an economic issue,” she said. “Not every invention makes it into the mainstream. And blue hydrogen has been trying to get into the mainstream for a long time; it’s just not happening.”

Posted on

Solar Growth Expected to Slow from Supply Chain Challenges, Rising Prices

Supply chain delays and rising prices could cut U.S. solar market growth this year by almost 20% below prior projections, but demand remains strong and the petroleum price shocks caused by Russia’s invasion of Ukraine could help drive an industry recovery in 2023, said Michelle Davis, a principal analyst at Wood Mackenzie.

While the impacts of the war may not be felt immediately in domestic solar markets, Davis said, “increases in [natural] gas prices are only going to make solar more economic … even with solar price increases of the last year.”

“The big challenge for the solar industry right now is resolving those supply chain constraints and trying to tackle various policy and trade issues,” said Davis, lead author of the Solar Market Insight 2021 Year in Review report released Thursday by Wood Mackenzie and the Solar Energy Industries Association (SEIA).

“There is more demand than current supply, which is why we expect long-term for the prospects for the market to be very strong and for recovery to begin, starting next year,” she said in an interview with NetZero Insider.

Similarly, SEIA CEO Abigail Ross Hopper stressed the key role solar can play in U.S. energy security. “In the face of global supply uncertainty, we must ramp up clean energy production and eliminate our reliance on hostile nations for our energy needs … and our nation will be safer because of it,” Hopper said.

With Democrats and Republicans in Congress calling for a major increase in U.S. fossil fuel production, Hopper said, “America’s energy independence relies on our ability to deploy solar, and the opportunity before us has never been more obvious or urgent.”

The report shows that the U.S. added a record 23.6 GWdc of solar in 2021 ― a 19% increase over 2020 ― even as prices for utility-scale fixed tilt projects rose 18%. For the third year in a row, solar added the highest proportion of new power generation on the U.S. grid ― 46% ― with panels added to more than 500,000 residential roofs, another all-time high, the report says.

Utility-scale solar was the primary driver for market growth, with 17 GWdc installed in 2021, but an uncertain pipeline lies ahead, the report says.

“About one-third of the capacity slated to come online during Q4 2021 was delayed by at least a quarter. For the 2022 pipeline, developers have postponed at least 8% and canceled at least 5% of planned capacity,” the report says

Even so, Davis sees the sector as strong. “There are a lot of utilities across the country who are increasingly including way more procurements and mandates for solar in their own utility-specific targets,” she said. For example, she pointed to the Tennessee Valley Authority’s 227-MW Muscle Shoals project in Alabama, which helped catapult the state from 51st to 18th place in the report’s state rankings for new solar installed last year.

Utility-scale projects also put Texas at the top of the state rankings for the first time, with more than 6 GW of new projects, pushing California’s 3.6 GW to the No. 2 spot.

Triple-B and the NEM Effect

The market impacts of federal and state policy surface as another key theme in the report. With no change in current federal policies, Wood Mackenzie is projecting the U.S. solar market will expand from its current 120 GWdc to 464 GWdc by 2032. But with the 10-year extension of the federal investment tax credit in the stalled Build Back Better Act, the report says the 10-year outlook for solar could grow an additional 66% to nearly 700 GW.

Even at that level, the nation would fall short of the deployments needed to meet President Biden’s goal of a 100% clean energy grid by 2035, Davis said.

“We still see growth in the solar industry, even if the various clean energy incentives that are included in the triple-B Act don’t get passed,” Davis said, referring to Build Back Better. “If we care about hitting some of those decarbonization goals, you really need a catalyst like the clean energy incentives in the triple-B Act, to even hope to get partially there.”

SEIA is also pushing hard for the act’s tax credits for advanced manufacturing to accelerate the buildout of a domestic solar supply chain that would wean the U.S. industry off its dependence on China.

“If we want to have a greater level of energy security in this country, if we are going to build a U.S. solar manufacturing supply chain that is robust, that will be here 20 years from now, we as a nation need to make a stronger commitment to it,” Dan Whitten, SEIA’s vice president of public affairs, said at a March 3 industry event.

Panel prices and supply chain issues lie at the heart of the cost increases being seen across all sectors of the U.S. solar industry, from residential and commercial to utility-scale. For example, the report shows installed system costs in the commercial sector rising from $1.36/w at the end of 2020 to $1.55/w at the end of 2021 – with panels and supply chain accounting for about 75% of the increase.

In this context, supply chain is an umbrella term covering shipping and freight costs and “a lot of things that are not necessarily broken out in all the other categories,” Davis said. “Every developer is going to differ a little bit in how they’re passing along costs. Some of them are going to absorb some of those cost increases … some of them are going to pass along those costs to customers.”

On the state policy side, all eyes are on California as the state’s Public Utility Commission wrestles with the third version of its net metering regulations (NEM 3.0). The proposed revisions to the state’s current net metering plan would slash the compensation rates solar owners receive for the power they put back on the grid, from present rates of 20 cents to 30 cents/kWh to around 5 cents/kWh, according to Wood Mackenzie. Solar owners would also have to pay a “grid participation fee” of up to $40 per month. (See California PUC Proposes New Net Metering Plan.)

Alice Reynolds, the commission’s new president, has put the revisions on hold, pending further review, but Wood Mackenzie estimates that if enacted, NEM 3.0 could cut California’s residential and commercial solar markets in half. “And since California remains the largest distributed solar market in the U.S., these reductions result in nationwide market contraction for both segments starting in 2023,” the report says.

Hybrid Storage

One key development not discussed in the report is the growing number of projects that combine solar with battery storage. The 2022 Sustainable Energy in America Factbook by the Business Council for Sustainable Energy and BloombergNEF noted the trend, especially for the utility-scale sector. (See BNEF: 2021 a ‘Blockbuster Year’ for Clean Energy Investment.)

Acknowledging the omission, Davis agreed, “Utility-scale, in-front-of-the-meter solar installations are overwhelmingly attached with storage today.”

Speaking at a launch event for the Factbook on March 4, Jack Thirolf, head of public policy and institutional affairs for renewable developer Enel North America, said building a solar project without a battery “is going to be an oddity going forward.”

Enel is planning “a ton of projects,” Thirolf said. “And the use case absolutely appears to focus on not just on the energy but carbon reduction as part of energy.”

“It also gives us so much more resilience. Thinking about changes in electricity markets, pricing and structures and fundamentals today are not going to be what they are in 15 years,” he said. “We need to be able to build in flexibility to be able to adapt; we’re building our projects so we can add more storage and different kinds of storage.”

Posted on

NERC Reports Mixed Data on Supply Chain Progress

Results from NERC’s recent supply chain effectiveness survey show that the organization’s Critical Infrastructure Protection (CIP) reliability standards are having a positive impact on the industry, staff said Tuesday.

However, more work remains to clear up misunderstandings about their requirements and applicability.

NERC conducted the survey between Oct. 12 and Nov. 30 last year, after the Board of Trustees requested an update on the effectiveness of the supply chain risk management (SCRM) standards:

  • CIP-013-1 (Supply chain risk management);
  • CIP-005-6 (Cybersecurity — electronic security perimeter(s)), parts 2.4 and 2.5; and
  • CIP-010-3 (Cybersecurity — configuration change management and vulnerability assessments), part 1.6.

All three standards took effect Oct. 1, 2020, following their approval by FERC two years prior. (See FERC Finalizes Supply Chain Standards.) Since then the commission has approved their replacements, CIP-013-2, CIP-005-7 and CIP-010-4, which will take effect on Oct. 1. (See FERC OKs Updated Supply Chain Standards.)

The voluntary survey was sent to “approximately 900 compliance contacts at registered entities,” with 201 responding. Eleven surveys were handed back without selecting any answers from the multiple-choice component or providing any comments. Of those that did fill out the survey, 114 said the SCRM standards were applicable to them, while 76 said they were not.

Presenting the survey results at Tuesday’s meeting of NERC’s Reliability and Security Technical Committee, Tony Eddleman, director of NERC reliability compliance at the Nebraska Public Power District and chair of NERC’s Supply Chain Working Group, highlighted responses that indicate registered entities are going beyond the letter of the relevant standards.

In particular, he noted that 24 of the 76 entities that said the SCRM standards did not apply to them — nearly a third — said they are “applying the SCRM principles … to [their] operational, business and/or contract language.” In addition, more than half of those that said the standards do apply to them said they are applying SCRM principles to systems that are not in their scope, such as low-impact bulk electric system cyber systems, which are not covered in the current or upcoming versions of the standards.

“What they told [is] that the standards are a good basis to determine what is needed if the entity wants to have a formal program,” Eddleman said. “So the standards are relatively new, and some entities don’t have compliance requirements, but they are using these to help develop programs.”

Not All Entities Clear on Requirements

While the willingness of entities to go beyond the minimum required by the supply chain standards is promising, the survey also brought to light some potential problems with the standards. For example, even though more than 60% of respondents said they felt the standards’ requirements are clear, they still said they had “questions about compliance evidence,” indicating that they were not sure how auditors might assess their compliance. Additionally, more than 40% of respondents indicated they did not have “a clear understanding of what constitutes a violation” of the standards.

Another finding that raised eyebrows at NERC was that while entities reported dedicating about 22% of their CIP compliance program resources on average to SCRM issues, those compliance programs themselves have only grown about 9% since the introduction of the standards. This indicates to NERC that rather than hire new staff specifically for supply chain compliance, utilities have tended to simply assign employees who normally handle other CIP issues to the SCRM beat. Eddleman expressed concern that this approach might put excessive burdens on already-stretched security professionals.

“One of the quotes that we saw … kind of summed up several of the comments we received … and it said, ‘We all cringe when we know we have to make a purchase,’” Eddleman said. “Supply chain risk management is requiring significant resources … and it’s stealing resources from other CIP programs, [which] is not just a resource strain on utilities, it’s also on vendors.”

Posted on

Nevada Looks to Other States for Ways to Replace Gas Tax Revenues

In the search for ways to bolster the state’s transportation funding, Nevada might borrow approaches used in other states, such as a parcel delivery fee adopted in Colorado or Utah’s per-mile charge for EV drivers.

Those are some of the ideas being considered by an Advisory Working Group on sustainable transportation funding convened by the Nevada Department of Transportation (NDOT). The group met Tuesday to narrow down some of the transportation funding options.

Formation of the working group was a requirement of AB413, passed during the state’s 2021 legislative session. The 29-member panel began meeting in July. A report on the group’s findings and recommendations is due by Dec. 31.

Funding Shortfall

The working group is looking at sources of revenue for the State Highway Fund, whose use is restricted to highway construction, maintenance and repairs.

In addition, the group is evaluating “flexible” funding options that could be used for transportation projects that fall outside of the restricted uses of the highway fund. Those projects might include public transit or bicycle projects.

Revenue from the gas tax, which is Nevada’s largest source of transportation funding, has been decreasing on a per-mile-driven basis as vehicle fuel economy improves and more drivers switch to electric vehicles, according to an NDOT report to the working group.

Fuel tax deposits to the highway fund have dropped from 1.27 cents per mile in 2010 to 1.03 cents per mile in 2020.

At the same time, construction costs are rising and demand for transportation infrastructure investments are growing, including at the city, county and regional level, the report said.

Narrowing Options

The working group has reviewed a wide range of transportation funding options and is now narrowing down the choices.

During a meeting on March 8, consultants with CDM Smith presented three potential packages of transportation funding measures. The packages included short-term and long-term strategies, along with options that offer flexibility on how funds are spent.

Working group members then selected the funding strategies they viewed as the most promising. The options will now undergo further analysis.

One option the group supported as either a short- or long-term strategy, or a flexible funding source, was a parcel delivery fee.

A report from CDM Smith proposed a 50 cent fee for deliveries made by USPS, FedEx, UPS and Amazon, and even food-delivery services. The fee would be collected from the seller of the goods, similar to sales tax collection.

The report proposed reducing the fee to 25 cents for deliveries made by a zero-emission vehicle.

The proposal “responds to concerns that e-commerce is overburdening roadways and not paying fair share,” the report said. The fee, as proposed in the report, would raise an estimated $67 million per year.

Colorado has adopted a 27 cent fee on retail deliveries made by motor vehicle that will take effect in July. The fee was included in SB21-260, a transportation funding bill signed into law in June.

Per-mile Fees

As a longer-term strategy, the working group supported exploring a road usage charge for light-duty vehicles.

In its simplest form, the road usage charge would be a modest fee applied equally to all light-duty vehicles based on miles traveled. But the fee could also vary for electric versus gas-powered vehicles, according to speakers at the working group meeting.

Making a road usage charge a longer-term strategy would give the state more time to analyze the costs and benefits of such a system, while allowing other states to forge ahead first, “taking on the first-mover risks,” the consultant’s report to the working group said.

AB413 specifically asked the working group to analyze a road usage charge model proposed by the Natural Resources Defense Council (NRDC).

Under the NRDC model, an annual fee would be assessed on EVs based on the miles-per-gallon-equivalent rating of the model, the gas tax and the number of miles driven each year.

In a second part of the system, the gas tax would be indexed to inflation and total fuel consumption. The idea behind the two-part system is to address the erosion of transportation funding while not slapping EV owners with “unjustifiable high fees” that discourage EV ownership, NRDC explained in a blog post.

AB413 also asked the working group to look at the road usage charge program adopted in Utah.

Utah charges an alternative fuel vehicle fee for electric cars each year on top of the annual registration fee. But under the road usage charge program, drivers can opt out of the flat fee and instead pay 1.52 cents per mile. The mileage-based fee is capped at the amount of the flat fee, which is $123 this year for an EV.

Other Proposals

The working group supported several additional revenue proposals for further analysis. Those include increasing the base vehicle licensing fee or raising the governmental services tax that is assessed on vehicles based on their value.

Increases to the state fuel excise tax rate are also being eyed, including increases indexed to inflation.

Another possibility is a carbon tax, which would assess a fee on each ton of CO2 emitted. The fee could be charged to refineries and factories, to fuel distributors or to drivers. No state currently has a carbon tax, according to the consultant’s report, but several states have a cap-and-trade system.

The advisory working group’s next meeting is scheduled for April 12. More information is available on the Nevada Sustainable Transportation Funding website.