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November 5, 2024

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Discussion Continues on ISO-NE Capacity Market Changes

New England stakeholders continued discussion on potential changes to ISO-NE’s forward capacity market (FCM), debating the merits of moving to a prompt and seasonal capacity market at the NEPOOL Markets Committee (MC) on Monday.

ISO-NE declined to endorse any specific market changes, but solicited feedback and furthered the discussion on market alternatives initiated at the June Participants Committee meeting (See ISO-NE Considers Major Capacity Market Changes.) The RTO is facing a deadline to figure out how to proceed for the 2028/29 Capacity Commitment Period, the auction for which is scheduled for February 2025.

“By September 2023, ahead of the pre-auction process for FCA [Forward Capacity Auction] 19, the ISO must decide on the timing and scope for CCP19,” Tongxin Zheng, ISO-NE director of advanced technology solutions, told the MC.

For FCA 19, the RTO laid out the options of proceeding with the auction business-as-usual, delaying the auction until 2026 to incorporate the ongoing Resource Capacity Accreditation (RCA) project or delaying the auction until early 2028 while moving to a prompt and seasonal auction.

Looking at the long-term outlook for the region’s capacity market, ISO-NE presented some potential pros and cons of adopting prompt and seasonal market changes. For a prompt market, ISO-NE said the benefits would include improving the accuracy of forecasts, requiring projects to be operational to enter the auction and eliminating several “challenging elements of auction administration,” such as non-commercial financial assurance and annual reconfiguration auctions.

“A prompt construct can improve the accuracy by which we estimate resource adequacy (demand) and resource accreditation (supply) relative to the current forward construct,” ISO-NE said. “However, the potential improvements are a function of what ‘prompt’ means in practice.”

Meanwhile, ISO-NE said it anticipates some drawbacks inherent to moving to a prompt market. These include making auction results less important for the long-term entry and exit decisions of generators, increasing capacity price volatility and giving less time for the RTO and market participants to react to the auction’s outcomes.

Pete Fuller of Autumn Lane Energy Consulting told RTO Insider that new changes must consider impacts on new resources, especially within the context of the clean energy transition.

“In the current debate about a prompt capacity market, we should think very carefully about whether a prompt market will support the level and kinds of new entry that will be needed for the decarbonization transition as state-backed contracting is phased out,” Fuller said, noting that the current FCM was designed to help provide new entrants with some degree of price certainty several years out.

“While current practice in the region relies much more heavily on state-backed contracts for entry decisions (particularly for offshore wind projects) than on the markets, that may not always be the case, as suggested by Massachusetts’ recent work to explore the Forward Clean Energy Market concept,” Fuller added (See New England Stakeholders Discuss Clean Energy Market Mechanisms.)

Some stakeholders, however, view the lack of a years-in-advance capacity commitment requirement as a benefit for developing new projects.

“The uncertain development timeframes for a growing share of new resources, including offshore wind, causes the FCM to create inefficient financial risk for new resources that may become an economic barrier for new investment,” said Pallas LeeVanSchaick of Potomac Economics.

LeeVanSchaick also said the current FCM structure can push some existing units to retire earlier than they should.

For older, existing units, “unexpected issues such as significant equipment failure can compel them to buy back their capacity supply obligation at great cost and this risk may cause some resources to retire prematurely,” LeeVanSchaick said. “A prompt market facilitates more efficient retirement decisions because the uncertainty regarding the condition and availability of older units is much lower at the time of the auction.”

Under the current system, many older resources will simply run until something breaks, instead of scheduling the retirement in an orderly fashion, said Brett Kruse of Calpine.

“Some owners will operate the generator only during very high-priced periods until the unit or a major component has a major maintenance issue, and then they’ll decide that it does not make financial sense to allocate sufficient capital to repair the plant,” Kruse said. “They’ll just retire it, and that’s likely to be the way that most of the older plants eventually exit the market.”

ISO-NE has put forward a prompt market and a seasonal market as complimentary, but has not ruled out any options, including implementing just one of the two major changes.

Contemplating the benefits of a seasonal market, ISO-NE said a seasonal market could help the RTO do a better job modeling resource constraints and would allow suppliers to make offers reflecting their differing seasonal capabilities.

“A seasonal construct would allow for a more precise delineation of resource adequacy and resource accreditation values within a given annual delivery period,” ISO-NE said.

The RTO also asked stakeholders for input on whether it would be best to run seasonal auctions sequentially or concurrently. Kruse said that holding an integrated annual seasonal auction would help generators ensure adequate annual revenue.

“It’s important that the seasons, whether it is two or four, together provide sufficient annual capacity revenue to generators regardless of their seasonal value,” Kruse said. “Plant staffs, maintenance expenses and so forth are annual costs, so the totality of the seasons need to total up much like today’s annual market does, and having an integrated, annual view once a year for all seasons makes sense.”

DASI approval

The MC also recommended the approval of ISO-NE’s Day-Ahead Ancillary Services Initiative, which is intended to fill any energy gaps between the supply procured in ISO-NE’s day-ahead market and the RTO’s forecast real-time load (See ISO-NE Plans 2025 Launch for Day-Ahead Ancillary Services Initiative.) The initiative will go to the NEPOOL Participants Committee for a vote on Aug. 3.

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NYISO Discovers Market Problem, Opens Confidential Investigation

NYISO has identified a software issue that potentially constitutes a market problem and will investigate the impact, according to an email the ISO sent to market participants Tuesday night.

In the email, which was obtained by RTO Insider, NYISO said it “is conducting a confidential investigation into the issue” and that it “will inform market participants as soon as practicable after resolution of the underlying issue.”

Shaun Johnson, NYISO director of market mitigation and analysis, addressed stakeholder questions about the notice during a Wednesday meeting of the ISO’s Business Issues Committee.

Johnson said the ISO will label the investigation as “confidential” but does not expect it to be a “long-term” one.

The “expectation is that this issue will be addressed soon, and we will provide more information to the marketplace as soon as possible,” he said. He referred anyone interested in learning more about the procedures for reporting market problems to Section 3.5.1 of NYISO’s market services tariff.

Johnson said he was reluctant to divulge too much information for fear of any parties “gaming or creating harmful outcomes to the NYISO markets,” but sought to answer questions from those curious about the nature, timing and impact of the problem.

In response to a question from Mark Younger, president of Hudson Energy Economics, Johnson said the problem was identified in NYISO’s day-ahead and real-time ancillary services markets.

Andrew Antinori, a director at the New York Power Authority, asked how NYISO determines when an issue is graduated to a potential market problem.

“There’s no bright line or financial threshold, but in order to move from a potential market problem to a market problem, there needs to be a significant impact to market outcomes,” Johnson said.

“We are still in the stages of identifying the exact issue,” he added, “but at this point, it is a potential market problem, and we do not have our arms around the size, scope and impact at this point.”

Bruce Bleiweis, director of market affairs at DC Energy, asked how long the problem has been potentially impacting NYISO markets, and whether it was a “one-day, one-week, one-month or three-year problem.”

Johnson was hesitant to give an exact timeframe but said “it’s certainly been longer than one week and has been a somewhat significant period of time but does not go back several years.” He added later that “as of this morning, the problem has not been resolved.”

Marc Montalvo, CEO of Daymark Energy Advisors, sought clarification on the nature and magnitude of the issue.

Johnson was careful in his response. “There is a definitive issue with NYISO software,” but staff are still unsure “about the extent that issue had on NYISO market systems or will have on those systems,” he said.

However, Johnson made clear that if NYISO finds the issue to be a legitimate problem, then subsequent impact analyses “will glean the extent of the problem and if this was just a defect with little to no impact.”

Antinori and Doreen Saia, an attorney with Greenberg Traurig, asked about NYISO’s interaction with FERC and what, if any, tariff filings may be necessary.

Johnson responded that no tariff waivers or filings are currently necessary but that NYISO staff have been in contact with the commission to keep it appraised of the problem and get its “thoughts and guidance.”

“At this point, we do not expect there to be any need for additional market rules changes or exigent filing with FERC, and the expectation is that this will be resolved with updates to software,” he added.

NYISO must return with an update and more information within 30 days of initial notice, and Johnson said staff plan to return to the Market Issues Working Group meeting either Aug. 3 or 9.

June Market Performance

Also during the BIC meeting, NYISO Senior Vice President Rana Mukerji presented June’s market performance, highlighting how lower fuel prices and cooler temperatures significantly reduced energy prices compared with last year. The month’s locational based marginal pricing was roughly 60% lower than in the same month a year ago.

Mukerji said “fuel prices are at historically low levels” and “natural gas prices are 79% down year-over-year.”

DER Manual Updates

Also, stakeholders unanimously approved multiple distributed energy resource manual updates presented during the BIC meeting.

These updated manuals include revisions that have been discussed over the past year and are part of NYISO’s ongoing work to comply with FERC Order 2222, which required operators to enable DER aggregation market participation and deployment.

The manuals are now moved to the July 20 Operating Committee for approval, and NYISO anticipates the revisions will become effective on the same date as the launch of other tariff and participation models.

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Batteries Multiply in CAISO, Soak up Solar

Batteries connected to CAISO’s grid exceeded a record 5,000 MW this spring, absorbing a significant portion of the abundant solar energy California generates during the day and supporting grid stability on hot summer evenings, the ISO’s Department of Market Monitoring (DMM) said in a Special Report on Battery Storage posted Monday.

Following the blackouts of August 2020, battery storage in CAISO grew rapidly from 500 MW in 2020 to 5,000 MW in May, the report said. (In a separate news release, CAISO said total battery capacity had reached 5,600 on July 1.)

“Battery storage is the fastest-growing type of resource in the CAISO market,” the report said. “As of May 1 … batteries make up 7.6% of CAISO’s nameplate capacity.”

Reaching 5,000 MW means California is about one-tenth of the way toward having the 50 GW of battery storage it needs to reach its 100% clean energy goal by 2045, the DMM noted.

Battery charging accounted for 5% of load during peak solar hours in the middle of the day last year, the Market Monitor said.

“During these hours, batteries help reduce the need to curtail or export surplus solar energy at very low prices,” it said.

The batteries “provided valuable net peak capacity and energy” during a September 2022 heat wave that set demand records across the West and brought CAISO to the brink of ordering rolling blackouts, DMM said. (See California Runs on Fumes but Avoids Blackouts.)

Batteries provided 2.4% of output in CAISO from 5 to 9 p.m. from Aug. 31 to Sept. 9 last year during the extended heat wave, the report said.

On Sept. 6, the day when CAISO nearly ordered rolling blackouts, some batteries discharged earlier than expected because of prices that exceeded $1,000/MWh before the evening net peak, after solar drops offline. But generally, “a minimum state-of-charge constraint was used by operators to ensure the availability of batteries in peak net demand hours on most days during the 2022 summer heat wave,” DMM said.

CAISO adopted its minimum state-of-charge requirement as part of its summer 2021 readiness measures to ensure batteries would be available to discharge during hot summer evenings when the grid was most stressed.

In addition, DMM said batteries were frequently issued manual or exceptional dispatches through the 2022 heat wave.

“Most of these exceptional dispatches were to hold charge in anticipation of net peak demand hours,” the report said. “Exceptional dispatches to charge were used largely in response to a software issue that prevented storage resources from bidding to charge at a higher price than $150/MWh, which resulted in those resources not being able to charge even when in merit.”

Battery Fast Facts

The report provided a snapshot of CAISO’s battery fleet as of May:

    • Many of the batteries in CAISO are paired with solar or wind generation and participate in CAISO either as hybrid resources or under a co-located model in which they share an interconnection point. Of the 5,000 MW of batteries connected, 2,200 MW were stand-alone resources, 2,000 MW were co-located, 700 MW were part of hybrid resources and 100 MW were part of co-located hybrids.
    • The size of active batteries ranges from 1 to 260 MW, with most in the lower-to-mid ranges. They typically can discharge for up to four hours.
    • A majority of the projects in CAISO’s interconnection queue also have a proposed battery component.
    • CAISO’s interstate Western Energy Imbalance Market has also been adding storage. As of May 1, 20 non-CAISO battery storage resources were participating in the WEIM, with roughly 1,000 MW of discharge capacity. “In comparison, WEIM battery capacity totaled 286 MW in December 2022,” the report said.
    • Batteries now provide over half of CAISO’s regulation up and down requirements.
    • Net revenue for batteries rose from about $73/kW-year in 2021 to $103/kW-year in 2022, driven largely by higher peak energy prices.
    • Bid cost recovery (BCR) payments for batteries increased significantly in 2022, accounting for 10% of BCR paid to all resources, while batteries made up just 5% of total capacity. The payments represented 7.6% of all battery revenues last year, although the DMM expects a portion to be rescinded because of a market rule change made last November.
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DeSantis Rejects $346 Million in IRA Energy Efficiency Funds

Florida Gov. Ron DeSantis (R) looks to be ramping up his 2024 presidential campaign by rejecting a growing list of federal and state clean energy initiatives.

Last month, the governor used a line-item veto to turn down a $5 million federal grant that would have allowed Florida to hire and train staff to administer $346 million from the Inflation Reduction Act. The money would have provided rebates to consumers for a range of energy-efficient home upgrades, according to a report from Bloomberg News.

The line-item veto was part of a package of funding cuts DeSantis made in the state budget on June 15. In letters sent to the U.S. Department of Energy on June 19, Brooks Rumenik, executive director of the Florida Department of Agriculture and Consumer Services’ Office of Energy, said the state was “respectfully” withdrawing its applications for the grants, as reported by The Capitolist, a website covering Florida news and politics.

Earlier this month, DeSantis vetoed a bill (SB 284) that would have triggered widespread electrification of vehicles owned by state and local government agencies. The bill, which passed both houses in the Florida Legislature with overwhelming bipartisan support, would have required state and local governments to base vehicle purchases on overall cost of ownership rather than fuel efficiency, as reported by the Orlando Sentinel.

While electric vehicles are more expensive to purchase, their costs for fuel and maintenance are lower than gas-powered cars. Savings from electrifying state and local government fleets were projected to be $277 million, according to estimates from Advanced Energy United.

DeSantis’ critics framed both actions as purely political, criticizing the governor for putting his presidential ambitions ahead of the state’s consumers, who are currently under an extreme heat watch.

The rejected energy efficiency funding would “directly benefit homeowners and renters, and these rebates mean that people in Florida would get lower utility [bills] and healthier and more comfortable homes, as well as lower greenhouse gas emissions,” said Lowell Ungar, director of federal policy for the American Council for an Energy-Efficient Economy.

With the SB 284 veto, DeSantis was playing to Iowa voters, said state Rep. Anna Eskamani (D). “The Iowa caucus voters who are all about ethanol don’t see electric vehicles as something that is economically in their favor,” Eskamani told the Sentinel. “DeSantis is catering to his Iowa voters, not passing policy for Floridians.”

The governor’s veto caught many by surprise because of the wide support the bill had from Republicans and the Florida Natural Gas Association.

“It was a common sense, good governance bill. There is nothing in this bill that any person in America should be against,” former state Sen. Jeff Brandes (R) told the Sentinel. However, no efforts have been made to overturn the veto, the Sentinel reported.

Campaign Narratives

DeSantis’ vetoes could play into President Joe Biden’s current effort to shape the campaign narrative by promoting the economic benefits the IRA has brought to Southern states, whose lawmakers voted against the law.

Visiting South Carolina on July 6, Biden noted that since the passage of the IRA, clean energy companies had brought $11 billion in new investment to the state. Inverter manufacturer Enphase Energy is putting $60 million into two new manufacturing lines in the state, and Redwood Materials, a battery recycling company, is investing $3.5 billion in a new plant to be located near Charleston, Biden said.

A White House fact sheet quoted the state’s Republican lawmakers hailing the new investments in clean energy manufacturing, even though they voted against the IRA.

South Carolina and Georgia have drawn the most new clean energy business, according to the American Clean Power Association (ACP), with solar and battery manufacturers flocking to the states. An ACP map tracking new clean energy investments identifies only two in Florida, both expansions of existing facilities. Jinko Solar is expanding a photovoltaic plant in Jacksonville, and General Electric is investing $20 million to build out a plant where it is manufacturing onshore wind turbines.

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NAESB Wrapping up Gas-electric Harmonization Forum

The North American Energy Standards Board (NAESB) is to vote on recommendations to improve coordination between the electric and natural gas industries this week, with plans to send them on to FERC and NERC by the end of the month, a co-chair of the effort said Tuesday.

The NAESB Gas-Electric Harmonization Forum is close to wrapping up the effort, which started in the aftermath of the February 2021 winter storm that left millions without power in Texas for days, forum co-chair Robert Gee said at a press briefing held by the United States Energy Association. (See NAESB Confirms Gas-electric Forum in the Works.)

“We’re coming out with a set of recommendations we’re going to give to NERC and FERC at the end of this month,” said Gee, who runs consulting firm Gee Strategies Group. “Some of them will result in the creation of business standards by NAESB. Others will be policy calls that we’re going to ask FERC and NERC to weigh in on, particularly FERC.”

Then it will be up to the commission, with input from stakeholders in both industries, to carry them out. If they “fail to move the needle” enough, then it might be time for Congress to step in, Gee said, but FERC should be able to make changes that improve coordination between the two increasingly interdependent industries.

Gee and his co-chairs have released a set of strawman recommendations, and other stakeholders have filed comments on those ahead of a conference call set for Thursday. Voting on the recommendations will follow that call before the final package is submitted at the end of the month.

The strawman recommendations include many aimed at improving the two industries’ awareness of what is happening on their respective systems, especially when they are stressed by high demand. They say states with competitive markets should work to ensure that natural gas markets are fully functioning 24/7 in preparation for events when demand is expected to rise sharply for both power and gas. FERC rules already require interstate pipelines to schedule and operate 24/7 to support the wholesale gas market, but the commission would have to step in when state authorities lack the ability to make gas available at all hours during high-demand events.

The recommendations also call on ISO/RTOs to move up the day-ahead scheduling process to better align with the natural gas day and, if not already under consideration, to launch stakeholder processes to consider multiday-ahead scheduling.

FERC and state regulators who oversee competitive energy markets should consider whether market mechanisms are enough to ensure that generators have the needed arrangements to secure firm gas, storage or other ways to mitigate supply shortfalls during cold snaps. If not, then they should consider nonmarket solutions to ensure fuel availability, including funding mechanisms borne or shared by consumers, the recommendations say.

Though even with a firm contract, generators during cold weather events have found that they cannot access natural gas, Gee said.

“We need to revise the system so that the power generators are able to access gas on a contractual basis going into a long weekend — let’s say a three-day weekend, where we’ve had most of these acute shortages occur primarily in the winter — to allow them to access gas when it’s liquid, under terms and conditions which are economically acceptable to them,” Gee said.

Such long weekends exacerbate the guesswork generators do when it comes to buying gas: They might wind up with less than needed, or have to take more, facing costs either way, he added.

“We need to figure out a way to rationalize that process where we can synchronize also and harmonize what’s called the gas day and the electric day, and the contracting practices so that it elevates the power generators’ ability to access fuel during critical peak periods, without having to undertake an unreasonable economic risk in contracting for gas,” Gee said.

FERC has had such gas-electric coordination issues on its plate for years, but it has been able to get by without making major reforms of the industries for more than a decade, he added.

One cooperative in Virginia had signed up for firm natural gas deliveries, but during the December winter storm last year, it did not receive any and was unable to produce power when electric demand was spiking, said National Rural Electric Cooperative Association CEO Jim Matheson.

“There’s not the most obvious answer of where you balance those risks, but it does create more pressure on the electric sector because, at the end of the day, the electric sector is the one supposed to keep the lights on all the time,” Matheson said. “And you’ve got these competing dynamics that don’t always match up as well as you’d like. And particularly in the extreme storm events, that’s where it gets so much more complicated.”

Efforts to better harmonize the two industries and their scheduling practices are definitely needed to improve their performance in the future, he added.

The Electric Power Supply Association weighed in on the strawman proposal, agreeing that demand for electricity and natural gas will continue to rise, especially during cold weather events. Better coordination is important going forward, and the trade group supports using markets to accomplish that.

“Resolving the pain points that have emerged between the gas and electric sectors as they have moved much closer together in securing supply and accessing delivery infrastructure has been and will only grow more essential to meet our nation’s power needs,” CEO Todd Snitchler said in a statement. “EPSA and our members have been deeply engaged in ongoing efforts to address gas-electric coordination, improve reliability and help ensure that consumers and our critical services have access to cost-effective, reliable power at all times. We are optimistic that improvements will be made and hope our recommendations will provide constructive insight to develop durable solutions to this urgent issue.”

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Critical Minerals Sector Meeting Sharply Higher Demand

Demand for minerals critical to solar, battery and other clean energy technologies has doubled in the past five years to reach a value of $320 billion, the International Energy Agency reports.

And the mineral development industry is expanding to meet the increased demand, with a 50% increase in investment in lithium in 2022 alone and large increases in cobalt, copper and nickel mining.

The IEA on Tuesday issued the first of what it plans to be an annual review of the energy transition minerals sector — “Critical Minerals Market Report 2023” — and said the developments behind the data are an important factor in the speed and affordability of clean energy transitions underway around the world.

“We are encouraged by the rapid growth in the market for critical minerals, which are crucial for the world to achieve its energy and climate goals,” IEA Executive Director Fatih Birol said in a news release. “Even so, major challenges remain. Much more needs to be done to ensure supply chains for critical minerals are secure and sustainable.”

IEA analysis indicates that if all critical mineral projects are carried out as planned, supply could meet the demand projected under the myriad climate pledges announced by governments worldwide.

But the risk of project delays and technology-specific shortfalls persists, IEA said, and the demand for materials would increase under certain climate-protection scenarios.

Other supply-side challenges include matching supply to demand, diversifying supply sources and maintaining supply in a clean and responsible manner.

Beyond exploration and production capacity, other metrics are a mixed bag in the report:

    • Supplier diversity is not improving — the market share held in 2022 by the top three critical mineral producers is unchanged or even larger than three years earlier.
    • There is uneven progress on ESG practices.
    • Community investment, worker safety and gender balance are improving.
    • Greenhouse gas emissions during production are high and not decreasing.
    • Water use nearly doubled from 2018 to 2021.
    • Delays and cost overruns have been common on past projects.
    • Thin inventory levels limit the ability to cushion supply-chain disruptions.
    • Recent commodity price decreases could cool investment interest in new projects, with strong medium-term implications for the sector.

Also new on the IEA website is an interactive data explorer for 37 critical minerals from arsenic to zirconium that shows the projected demand for them through 2050 under multiple clean energy transition models.

The agency said it would continue to work to drive progress in the critical minerals space, including by bringing stakeholders together at its Critical Minerals and Clean Energy Summit in September.

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Youngkin Announces Grant Program for Offshore Wind Supply Chain

Virginia Gov. Glenn Youngkin (R) on Tuesday announced the launch of the Virginia Offshore Wind Supplier Development Grant, which is designed to give incentives to existing manufacturers in the commonwealth to enter into production that supports offshore wind.

The program was approved in legislation adopted last year and is administered by the Virginia Economic Development Partnership (VEDP). It offers competitive grants to assist manufacturers that want to enter the field by offsetting capital expenditures in equipment used for offshore wind.

“With a central East Coast location, one of the highest concentrations of skilled maritime talent, world-class port infrastructure and a competitive cost of doing business, Virginia has emerged as a leader in the U.S. offshore wind supply chain,” Youngkin said. “This new grant will strengthen the industry ecosystem in the commonwealth while driving economic development and job growth and is a strategic investment that supports our plan to guarantee abundant, clean energy for Virginia’s future.”

Legislators approved $2.5 million from the general fund for the grant program, which runs for three years starting this month. Funds will be disbursed as reimbursements for purchased equipment and grant awards will range from $20,000 to $250,000. Purchases made before July 1, 2023, are not eligible.

The grants can defray the cost of investments in real property and/or tangible personal property but cannot be used for maintenance or repair of existing equipment. The grants can be applied to replace old equipment if that leads to an increase in production.

The grants are limited to companies that make investments of at least $40,000 in the next 36 months. Applicants must have fewer than 250 full-time employees and be registered as a vendor in the Virginia Offshore Wind Supply Chain Partnership Directory at the time of application.

Applicants will have to maintain their local employment levels, as verified by the commonwealth, at the awarded location through the life of the grant. They must have a legal presence within Virginia for at least a year and be in good standing with the State Corporation Commission before applying.

VEDP will review the applications and conduct due diligence, while the Virginia Offshore Wind Supplier Development Grant Review Committee will meet every three months to review those applications and authorize grants.

“The Virginia Offshore Wind Supplier Development Grant will leverage the commonwealth’s existing offshore wind leadership position and advance our competitive advantage in emerging supply chains and technologies,” said Secretary of Commerce and Trade Caren Merrick. “This program invites Virginia manufacturers to diversify their portfolio to supply the industry, ultimately advancing our goal for the commonwealth to become the market leader in offshore wind technology, development and deployment.”

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Natural Gas Power Generation Expected to Set Record

The U.S. Energy Information Administration on Tuesday forecast record-high amounts of electricity would be generated by burning natural gas this summer.

High demand for power was cited as a cause, along with low gas prices and power industry trends.

EIA said extensive use of air conditioning during hot weather is expected to raise demand for electricity.

Fuel prices are another driver, EIA said in its July Short-Term Energy Outlook, issued Tuesday. Electric utilities’ cost for coal was 9% higher in the second quarter of 2023 than in the same period in 2022, while natural gas was 66% lower. This gave them a nearly equal cost per million BTU.

As a result, EIA predicts 4% more electrical generation from natural gas in July and August 2023 than in the same two months of 2022.

EIA also predicts a 6% year-over-year increase in July and August in power generated by renewable sources, which are seeing rapid growth in installed capacity.

“This is an interesting time to monitor the United States’ electricity mix,” EIA Administrator Joe DeCarolis said in the news release. “As coal provides less and less power to the grid, we expect the contributions of natural gas and renewables in particular to increase.”

EIA said about 6,000 MW of new combined cycle natural gas turbine capacity and nearly 15,000 MW of wind and solar capacity have come online so far in 2023.

Other details from the July Short-Term Energy Outlook:

    • Natural gas is expected to account for 41% of U.S. power generation in 2023 and 40% in 2024, compared with 37% in 2021.
    • Coal is projected to drop from 23% in 2021 to 15% in 2024.
    • Renewables are expected to rise from 20% in 2021 to 25% in 2024.
    • As a result, U.S. carbon dioxide emissions are expected to decline from 4,964 billion metric tons last year to 4,789 this year and to 4,774 next year.
    • Nuclear holds steady around 19% to 20% in the four years of actual and projected data.
    • Wind power generation far exceeds solar, with installed wind capacity expected to reach 148.7 GW nationwide this year vs. 98.8 GW for solar.
    • Installed solar capacity is expanding much more quickly than wind: Year-over-year increases of 17.2%, 38.2% and 32.2% are recorded or projected for solar in 2022, 2023 and 2024, compared with 6.2%, 5.6% and 4.1% for wind.
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EV Charging Efforts Ramp up on West Coast

California, Oregon and Washington have jointly applied for federal grant money to build a public charging network for electric trucks across the three states.

The proposed West Coast Truck Charging and Fueling Corridor Project would include 34 truck charging stations and five hydrogen fueling stations. The stations would be primarily along Interstate 5, with some locations on “key connecting corridors,” such as I-710 in the Los Angeles area.

Departments of transportation from California, Oregon and Washington, together with the California Energy Commission (CEC), applied for charging network funding last month from the U.S. DOT’s Charging and Fueling Infrastructure competitive grant program.

The plan was discussed during a joint CEC and California Department of Transportation (Caltrans) workshop. Caltrans declined to reveal the amount of grant funding requested, saying the proposal is under confidential review by the Federal Highway Administration.

The workshop also provided an update on California’s deployment plan for the National Electric Vehicle Infrastructure (NEVI) formula program.

‘Wild West’ of Connector Types

The goal of the $5 billion NEVI program is to establish a nationwide network of public EV chargers along designated alternative fuel corridors. California’s expected share of the funds is $384 million over five years.

One question that kept cropping up during the workshop was how California plans to handle the move toward North American Charging Standard (NACS) charging connectors.

Automakers including Ford, General Motors, Rivian and Volvo announced recently that they would adopt Tesla’s NACS connector as Tesla begins opening its Supercharger network to non-Tesla vehicles.

But federal NEVI guidance requires charging stations to be equipped with the rival combined charging system (CCS) connectors. Each station must have at least four CCS connectors that combined allow four vehicles to charge simultaneously.

That still leaves room for NACS connectors at ports that have more than one connector, according to Energy Commission Specialist Brian Fauble.

“As long as one of those connectors [is] CCS, the other connector can be any other connector, be it NACS, or CHAdeMO, or anything else,” Fauble said. “These other connectors can still be done, as long as you’re still meeting the port requirement of one CCS per port.”

Kentucky has added a requirement that charging stations funded through NEVI include NACS connectors in addition to CCS plugs, Reuters reported last week. Texas and Washington state might do the same.

California isn’t ready to follow suit, officials said during the workshop.

“It’s a little bit of a Wild West scenario right now with things changing so rapidly,” said Jim McKinney in CEC’s Fuels and Transportation Division. “We’re monitoring this and trying to decide how to proceed.”

McKinney said the NACS situation will not impact CEC’s initial NEVI solicitation, which is expected to go out during the third quarter of this year.

California divided its roughly 6,600 miles of alternative fuel corridors into segments that were then gathered into “corridor groups” and ranked by priority. (See Calif. Lays Groundwork for NEVI Solicitations.)

The state’s first NEVI solicitation will cover six corridor groups with 28 new stations and 291 ports.

Complementary Programs

The West Coast Truck Charging and Fueling Corridor Project would be “very complementary” to NEVI, Jimmy O’Dea, Caltrans’ assistant deputy director for transportation electrification, said during the workshop.

O’Dea said there are now only four publicly accessible truck charging stations across the West Coast.

“This would be a significant addition to the industry that we know is growing so rapidly,” he said.

Charging stations included in the project would each have at least five 350-kW dual-port chargers. Stations along I-710 would each have 10 chargers to serve drayage trucks working at the California seaports.

The stations would also support a megawatt charging system upgrade.

Each of the five hydrogen fueling stations would host two dispensers and have a 10,000-kg-per-day capacity.

Some commenters urged CEC to use a portion of NEVI funding for medium- and heavy-duty truck charging.

Sean Waters, vice president of compliance and regulatory affairs for Daimler Truck North America, said some of the NEVI-funded stations should be configured with a pull-through charging lane that could accommodate cars or large trucks.

While recharging at depots is common for trucks today, more fleets could be looking for public charging in the future due to high costs and infrastructure constraints of “behind-the-fence” charging equipment, Waters said in written comments to the CEC.

“Light-duty vehicles can utilize sites designed for medium- and heavy-duty vehicles, but the opposite is not possible,” Waters noted.

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Newsom Expresses ‘Sense of Urgency’ on Energy Buildout

California Gov. Gavin Newsom (D) on Monday signed a $311 billion state budget and infrastructure bills aimed at building generation and transmission to ensure reliability as the state transitions to 100% clean energy.

The fiscal year 2023/24 budget retains 95% of last year’s $54 billion, five-year annual commitment for climate initiatives, including roughly $10 billion for electric vehicle infrastructure and incentives.

In his budget plan released in January, Newsom had proposed slashing $6 billion from climate commitment because of this year’s tax revenue shortfall, but he agreed with lawmakers to cut only $2.9 billion.

Negotiations with lawmakers also produced the five-bill infrastructure package that Newsom signed Monday.

The bills included Senate Bill 149, which will streamline judicial review of clean energy and transportation projects by requiring that challenges to the projects under the California Environmental Quality Act (CEQA) be resolved by the courts within 270 days, including appeals. (See Newsom Stresses Role of Permitting in Calif. Energy Transition.)

Another bill, SB 147, will allow the incidental taking of fully protected species under the state’s Endangered Species Act during the construction of infrastructure projects. It also declassifies the peregrine falcon, brown pelican and thicktail chub, a small fish, as protected species.

Environmental groups and some Democratic lawmakers opposed the measures, but Newsom said keeping the lights on and building out clean energy and transmission ought to take precedence over lengthy environmental reviews.

“We’ve got to move to build those projects, and we’ve got to remove some hurdles,” Newsom said. “I know there’s a purity of thinking … that we can live with rules and regulations that require nine years of processes to deliver the reliability that the people of the state deserve, but I just don’t see that from the prism of where I’m operating from.”

The last three summers, when the state struggled with blackouts and near misses, were “challenging,” he said.

Avoiding future repeats will require adding thousands of new megawatts annually, CAISO and the California Public Utilities Commission have said. In May, the CAISO Board of Governors passed its 2022/23 transmission plan, which calls for 45 projects totaling $7.3 billion to add 70 GW of new resources over the next 10 years.

“That’s exactly why this infrastructure package was so important,” Newsom said, thumping his lectern. “I want you to know that I have short-term confidence but long-term anxiety if we do not deliver on these large-scale utility” projects.

Newsom said he feels “a deep sense of urgency” about building out energy capacity. California needs to build faster, including to compete for billions of dollars in federal funding from the Inflation Reduction Act and programs.

“I don’t want to just come up here and lament about extreme heat, extreme droughts, extreme weather,” he said. “I want to actually deliver, not just on goals and ambition, but on projects. And so, I’m in a different mindset, sort of a hardheaded pragmatism. You know, let’s get moving.”