DTE Energy executives promised a more aggressive clean energy transition during their third-quarter earnings call Thursday.
Pointing to the Inflation Reduction Act, the utility’s leadership told financial analysts to expect a speedier resource changeover when it files a new integrated resource plan with the Michigan Public Service Commission in early November. CEO Jerry Norcia said the plan will detail how DTE plans to accelerate its decarbonization efforts.
DTE earned $311 million ($1.60/share) for the quarter, $21 million higher in a year-over-year comparison because of deferred tax amortization and lower operations and maintenance expenses.
Norcia said “climate change remains our generation’s defining public policy issue.” He said the utility is committed to investing in clean energy and grid modernization to ensure reliability against extreme weather and to accommodate new load from electric vehicles.
“We are focusing on updating and improving our aging infrastructure for this additional demand while continuing to provide safe, reliable and affordable energy,” Norcia said. “Two important factors affecting our grid are climate change and emerging electrification technologies. We need to build the grid of the future to ensure we can continue to provide clean, safe, reliable and affordable energy.”
Norcia promised a “shift towards renewables and natural gas and away from coal generation.”
CFO Dave Ruud said the IRA will help accelerate DTE’s clean energy transition and keep customer costs in check. Norcia said the legislation’s passage will have “a very positive impact” on the company’s IRP, lower the cost of renewable investments and improve the affordability of carbon-capture and storage technologies.
“We have now the opportunity to invest greater amounts in our renewables build-out, so very positive impact overall,” Norcia said.
He also said DTE’s voluntary renewables program, MIGreenPower, continues to show “substantial growth” with a new 400-MW customer joining this week, bringing the program’s subscription to 2.1 GW.
DTE Energy has a goal to achieve net-zero carbon emissions by 2050.
Last month, the Ann Arbor City Council voted 10-1 to fund a $500,000 feasibility study on breaking away from DTE Energy. City officials have said their existing clean energy plans are an obstacle to meeting the city’s goal to achieve carbon-neutrality by 2030.
Activist group Ann Arbor for Public Power said DTE “fails to provide reliable electricity, charges residents more than the national average and gets more than 50% of its power from coal.”
The earnings call came as DTE and Consumers Energy face an audit from the Michigan PSC over compliance with outage and safety regulations. Last summer, storms left Michigan ratepayers on extended outages, leading to inquiries from state regulators. (See Mich. PSC Issues Emergency Order Following Devastating Storms.)
Norcia said he thinks the audit will ultimately strengthen DTE’s relationship with the commission and better align their views on the utility’s investments. He said current discussions with PSC staff are “really collaborative.”
Norcia said DTE’s grid averages 99.9% availability and its best-in-class utility performance is about 99.97%. He said all of DTE’s capital investment plans are “pointed at how do we get to that 99.97% availability for our grid.”
“So, I feel that this process with the Commission will create stronger alignment,” Norcia said, adding that DTE has systems that must be “replaced, modernized and automated.”
The New Jersey Board of Public Utilities voted unanimously Wednesday to spend $1.07 billion on transmission upgrades to deliver 6,400 MW of offshore wind generation to the PJM grid, saying the projects would minimize costs, environmental impacts and permitting risks (Docket No. QO20100630).
The BPU made its selection from among 80 proposals submitted by 13 developers in response to a solicitation issued by PJM at the BPU’s request under FERC Order 1000’s State Agreement Approach.
The solicitation asked for four categories of transmission upgrade proposals, including Option 2 for new offshore transmission connection facilities — extending the PJM grid into the ocean — and Option 3 for new offshore transmission network facilities. (See PJM Sees Wide Range of Costs in NJ OSW Tx Proposals.)
Andrea Hart, N.J. Board of Public Utilities | NJ BPU
But Andrea Hart, BPU’s senior program manager for offshore wind, said BPU staff and consultants Brattle Group rejected those options as too costly, narrowing its selection to Option 1b proposals for new onshore transmission connection facilities and Option 1a proposals for upgrades to resolve reliability criteria violations resulting from the generation injections.
Hart said most of the Option 2 proposals connected only a single project to each offshore substation, resulting in no reduction in the number of export cables compared with a baseline scenario without coordinated procurement. In addition, transmission-only projects would not qualify for the 30% federal investment tax credit available to generation projects, foregoing as much as $2.2 billion in subsidies. The Option 3 proposals, which were contingent on Option 2, were also rejected. “Staff remains optimistic that the costs of a coordinated transmission will continue to decrease, which could open the door for procurement of option two facilities through a future SAA solicitation,” she said.
In addition to $575 million in necessary Option 1a upgrades, staff selected what it called the Larrabee Tri-Collector Solution, which includes parts of FirstEnergy’s Jersey Central Power and Light’s 1b proposal (NYSE:FE) and pieces of Mid-Atlantic Offshore Development’s Option 2 proposal.
The Mid-Atlantic Offshore Development proposal will provide routes to three points of interconnection on Jersey Central Power and Light’s transmission system: the 230-kV Larrabee substation, two 500-kV transmission lines to the Smithburg substation, and one 230-kV line to the Atlantic substation. | Mid-Atlantic Offshore Development
The centerpiece of the $504 million project will be a new substation adjacent to JCP&L’s existing Larrabee substation. Mid-Atlantic Offshore Development, a joint venture of Shell New Energies US (NYSE:SHEL) and EDF Renewables North America (OTCMKTS:ECIFY), will build the AC portion of the new Larrabee Collector Station to accommodate three future HVDC circuits. The project will include sufficient land for the installation of up to four DC converter stations. “This will ensure robust competition is maintained — upholding open-access transmission principles — throughout future OSW solicitations,” the board said.
The collector station will use existing JCP&L rights of way to distribute up to 4,890 MW to three points of interconnection (POI): the Smithburg 500-kV, the Larrabee 230-kV substation and the Atlantic 230-kV.
Although the BPU’s order does not provide a shore crossing solution under the SAA, its order noted that the MAOD proposal identified the National Guard Training Center at Sea Girt as the preferred crossing point.
The board said the Larrabee collector is “an innovative transmission solution, creating a single onshore POI while leveraging existing rights of ways, an outcome that would not have been possible without coordinated planning and a competitive solicitation.”
“The awarded projects also position the state to seek direct federal funding for future expansions of the OSW transmission grid, including the potential to award a full OSW backbone in connection with the board’s future OSW solicitations, and preserves preferable interconnection locations and transmission corridors for future use,” the board said.
Although the MAOD-JCP&L Option 1b solution was intended to connect three 1,200-MW HVDC systems, PJM said the equipment in the AC substation can handle up to 4,530 MW of future injections from DC converter stations.
“PJM’s analysis suggests that this provides an excellent platform for accessing additional headroom on the PJM system with modest additional upgrades in the future,” the BPU said.
The Missing Link
The SAA solicitation was intended to provide sufficient transmission to provide 6,400 MW of OSW capacity, helping the state meet its original goal of 7,500 MW of OSW by 2035. Ocean Wind I, which was awarded offshore wind renewable energy certificates for 1,100 MW in the state’s first OSW solicitation, is not eligible to use the capacity resulting from the SAA.
The BPU acknowledged that the transmission projects it selected under the SAA would not prevent future OSW generators from proposing different landing points or different routes from their landing points to the Larrabee collector.
BPU Chair Joseph Fiordaliso | NJ BPU
As a result, the board said it will require a successful bidder in its third OSW solicitation, scheduled for the first quarter of 2023, to “prebuild” a single corridor from the shore crossing to the Larrabee collector, ensuring a single onshore transmission corridor.
In September, Gov. Phil Murphy increased the state’s OSW goal to 11,000 MW by 2040. The board’s order directs staff to begin a second round of coordinated transmission planning to meet the increased goal, potentially including a new SAA solicitation.
Pending approval of the PJM board, the RTO will include the projects selected by the BPU in its Regional Transmission Expansion Plan as baseline public policy projects.
In addition to the Larrabee collector, the BPU approved $575 million in upgrades to existing onshore transmission identified by PJM as necessary to support the OSW injections, including:
PSE&G’s proposed Brunswick to Deans and Deans subprojects and Windsor to Clarksville subproject: $40.3 million;
LS Power’s additional Hope Creek-Silver Run 230-kV submarine cable plus upgrade: $61.2 million;
Atlantic City Electric’s proposal to reconductor the Richmond-Waneeta 230-kV line: $16.9 million;
Transource’s North Delta A proposal: $109.68 million;
PPL to reconductor the Gilbert-Springfield 230-kV: $380,000;
PECO to replace four Peach Bottom 500-kV breakers: $5.6 million; and
BGE to upgrade one Conastone 230-kV breaker: $1.3 million.
Because the State Agreement Approach requires New Jersey to assume 100% of the costs of the $1.07 billion in spending, the bills of average residential customers will increase by $1.03/month, the BPU said.
The BPU said its selections would save $900 million over the baseline scenario, evidence of the board’s “prudent and careful” approach, BPU Chair Joseph Fiordaliso said.
BPU Commissioner Dianne Solomon | NJ BPU
But Commissioner Dianne Solomon said she was concerned about the costs of this and future transmission expansions. “I’m sure my fellow commissioners agree we must work with others in our region to oversee and share the costs of the build out of offshore wind,” she said.
The BPU’s order said “it may be beneficial, prior to initiation of the second SAA, to review with other states, both inside and outside the PJM region, the potential for jointly undertaking an offshore wind planning process and incorporating those larger needs into this future SAA. While such a multistate process may present additional complexities, it is also likely to reduce costs to ratepayers by identifying even more robust regional solutions by considering a wider range of public policy needs, and by enabling the sharing of costs with other states who participate in the SAA process.”
Comments
MAOD did not respond to a request for comment. FirstEnergy spokesperson Chris Hoenig called the award “a landmark development opportunity in new, regulated transmission assets.”
PJM CEO Manu Asthana called the BPU’s action “an important milestone in the development of offshore wind in the U.S.”
“We see the State Agreement Approach as a model for how states can leverage PJM’s processes to advance their policy goals,” he added.
The ERO Enterprise’s work preparing the bulk electric system for extreme winter weather is far from over despite the completion of the initial effort to update reliability standards in response to last year’s winter storms, members of NERC’s Board of Trustees said Wednesday.
Meeting virtually, the board voted unanimously to adopt the new standards EOP-012-1 (Extreme cold weather preparedness and operations) and EOP-011-3 (Emergency operations), along with their implementation plan. Both standards were produced as part of Project 2021-07, begun by NERC last year in response to its joint inquiry with FERC into the February 2021 winter storm that forced thousands of megawatts of generating capacity offline in Texas and led to several days of forced outages across the state. (See FERC, NERC Release Final Texas Storm Report.)
With the acceptance of the board, the new standards will now be submitted to FERC for approval.
NERC CEO Jim Robb | NERC
At Wednesday’s meeting, NERC CEO Jim Robb described the new standards as the fulfillment of a promise that he and FERC Chairman Richard Glick made at the height of last February’s crisis.
“I remember being on the phone with Chairman Glick … and the one thing that the chairman and I committed at that point — to each other and effectively to all the citizens of North America — was that we weren’t going to let the lessons of this event go unheeded,” Robb said. “And we reiterated that commitment in several forums … that enough was enough and that we were really going to move forward to make sure that whatever we learned out of this event would inform all of our actions around extreme weather and cold weather preparedness.”
The joint inquiry recommended that NERC implement significant changes to its standards, and Project 2021-07 was intended as the first part of a three-phase response to the report. Four of FERC’s recommendations are addressed by the new standards:
to require generator owners (GOs) that experience outages or other issues because of freezing to create a corrective action plan (CAP) for the affected equipment and determine whether to revise its cold-weather preparedness plan to account for the CAP;
to require GOs and generator operators to conduct annual unit-specific cold-weather preparedness plan training;
to require GOs to retrofit existing generating units and design new units to operate to a specified ambient temperature and weather conditions; and
to require transmission owners and operators, and distribution providers, to separate circuits used for manual load shed from circuits used for underfrequency load shed and undervoltage load shed, or serving critical loads.
Howard Gugel, NERC’s vice president of engineering and standards, told trustees that these four recommendations were chosen for the focus of the first phase because the joint report suggested they be completed before the winter of 2022-23. The remaining six recommendations are intended to be addressed in the second phase, to be completed before winter of next year.
Trustees Support Standards, with Reservations
While board members supported the new standards in general terms, their comments made clear that this week’s vote is not the end of the conversation. Trustee Sue Kelly called Project 2021-07 merely “a down payment” on the work needed to properly address the grid’s vulnerability to severe weather, specifically saying that “this version of EOP-012 should [not] be the end of the discussion on winterization of generating units.”
She noted that the standard, as written, allows GOs to essentially opt out of implementing freeze protection measures by giving them the authority to define the “technical, commercial or operational constraints” that would “preclude the ability” to install these measures. She warned that this concession to GOs would “leave their reliability coordinators with a reduced set of generation resources to work with during the winter season.”
Howard Gugel, NERC | NERC
Observing that EOP-012-1 requires GOs to document “fuel supply and inventory concerns” in their cold weather preparedness plans, Trustee Jim Piro asked Gugel whether generators “have the ability to cause the upstream system” — specifically natural gas pipelines that feed generators — “to also winterize their systems.”
Gugel acknowledged that the standard does not give GOs that power. He suggested that such a requirement “could be placed within their fuel contracts” and added that the joint report does recommend separately that the gas industry do something to address winter preparedness in its own system.
Piro also asked whether the standard gives NERC any visibility into GOs that do opt out of the freeze protection measures, so that their potential unavailability can be factored into the organization’s winter reliability assessments. Gugel said NERC does have several means of gathering that data, from requesting it as part of the normal information gathering for the reliability assessments, to issuing alerts to compel utilities to report whether they have opted out.
While calling the new standards “a major step forward,” Trustee Roy Thilly reminded attendees that winter preparedness is “a very complex issue” that “is going to impose some pretty significant costs” on utilities. He made clear that although he sympathizes with the financial concerns of the industry, NERC cannot let this issue influence its decisions about changes that may be needed to ensure reliability.
“NERC has been, and needs always to be, concerned with and understand the cost it’s imposing on industry through reliability standards. We do that by looking at cost-benefit analysis, and we rely very heavily on industry … [which] is really in the best position to inform that analysis,” Thilly said. “But the issue of the ability to recover through rates and market tariffs is outside of NERC’s jurisdiction and … our control.”
“It’s very important that NERC urge FERC, RTOs, municipal and co-op boards and councils, and states, to take the steps necessary to enable recovery by industry participants of reasonable costs incurred to comply with mandatory NERC reliability requirements,” he added. “But it’s beyond our scope to get there, and we can’t not adopt a needed reliability standard because of concerns [about] cost recovery.”
FirstEnergy on Wednesday reported third-quarter earnings of $334 million (58 cents/share) on revenues of $3.5 billion, down from $463 million (85 cents/share) on revenue of $3.1 billion a year earlier.
Excluding special charges or credits, the company’s operating earnings were 79 cents/share, at the top of analysts’ guidance range. That compares to operating earnings 82 cents/share a year ago.
“Our continued solid results, together with the ongoing efforts to strengthen our culture, accelerate improvement in our balance sheet and achieve operational excellence, are creating positive momentum at FirstEnergy and positioning us to capitalize on significant opportunities for growth through long-term, customer-focused investments,” John W. Somerhalder II, board chair and interim CEO, said in a statement accompanying the results. “I’m confident our leadership team and committed employees will continue to drive these strategies to transform the company into a best-in-class utility.”
The company updated its full-year forecast for adjusted earnings to a range of $1.145 billion to $1.260 billion ($2.01- $2.21/share) based on 571 million shares outstanding.
The company reported that power deliveries for the third quarter were flat, with a 2% uptick in industrial demand offsetting a decline in residential and commercial demand.
The company’s regulated transmission business showed improved results, primarily from the company’s ongoing capital investment program, which yields guaranteed income.
In its quarterly report filed with the Securities and Exchange Commission, the company said it had recalculated transmission and distribution expenses as demanded by a FERC audit issued earlier this year.
“FirstEnergy completed an analysis during the third quarter of 2022 of these costs and how it impacted certain FERC-jurisdictional wholesale transmission customer rates for the audit period of 2015 through 2021,” the company said.
“As a result of this analysis, FirstEnergy recorded in the third quarter of 2022 approximately $45 million ($34 million after-tax) in expected customer refunds, plus interest, due to its wholesale transmission customers and reclassified approximately $195 million of certain transmission capital assets to operating expenses for the audit period, of which $90 million ($67 million after-tax) are not expected to be recoverable and impacted FirstEnergy’s earnings since they relate to costs capitalized during stated transmission rate time periods. …
“These reclassifications also resulted in a reduction to the Regulated Transmission segment’s rate base by approximately $160 million, which is not expected to materially impact FirstEnergy or the segment’s future earnings.”
SEATTLE — EPA on Wednesday announced it is distributing nearly $1 billion in grants to 389 school districts across the U.S. to buy cleaner buses, most of them electric.
Made available by the Infrastructure Investment and Jobs Act, the funding targets school districts in all 50 states, D.C. and U.S. territories, with a focus on assisting low-income, rural and tribal areas. Wednesday’s awards are the first in a five-year, $5 billion program created by the law.
The initial grants will help support the purchase of more than 2,400 clean school buses to “accelerate the transition to zero emission vehicles and produce cleaner air in and around schools and communities,” EPA said in a press release.
Vice President Kamala Harris joined EPA Administrator Michael Regan and Washington Gov. Jay Inslee at Lumen Field, home to the NFL’s Seattle Seahawks, to announce the funding. Harris pointed out that 25 million U.S. children take buses to school each day, but that “95% of our school buses are fueled with diesel fuel, which contributes to very serious conditions that are about health and about the ability to learn.”
Harris said the new buses would reduce incidences of childhood ailments such as asthma. She also cited reducing greenhouse gases and the economic boost to local industries involved in building the buses as additional reasons for the appropriations.
“Our electric school bus program really does represent an intersection of all these points, on top of the importance of investing in domestic manufacturing,” the vice president said. “We all know when, during the height of the pandemic, we saw what it means when we don’t have domestic manufacturing around things we need every day; it slows us down.”
“Not only does this stop climate change, but its stops asthma in our kids because they don’t have to breathe in diesel smoke,” Washington Gov. Jay Inslee told the audience.
EPA originally allocated $500 million for the 2022 grants, but it received so many applications that it almost doubled the pool of money available, Regan said. Ultimately, EPA distributed $913 million to 389 districts to purchase 2,463 buses, he said.
In Washington state, four school districts received a total of about $2.7 million. Each of them — Easton, Pomeroy, South Whidbey Island and Toppenish — are rural areas.
And while rural school districts dominated the national list of recipients, some large metropolitan ones, such as Atlanta and New York City, won among the largest rewards of about $9.9 million each.
“Those school districts who received an award can now proceed with purchasing new buses and eligible infrastructure,” EPA said in its announcement. The agency said it is partnering with the U.S. departments of Energy and Transportation to provide recipients “with robust technical assistance to ensure effective implementation.”
In a statement, Sue Gander, director of the Electric School Bus Initiative at the World Resources Institute, said the EPA program “marks a huge step forward in efforts to equitably electrify the nation’s school bus fleet. We are excited that school districts from coast to coast, large and small, urban and rural, will be receiving one or more electric school buses, including in twelve states and Washington, D.C, that previously had none on the way.”
Gander also had advice for bus makers. “For any manufacturers who are wondering about where to focus their investments, today’s announcement demonstrates loud and clear that the future is electric. It is time to step up and scale up production and job training for an inclusive transition.”
“Today’s announcement is the result of years of advocacy by families, students and community members seeking federal funding to facilitate their local school districts investing in a clean ride for kids,” Carolina Chacon, coalition manager for the Alliance for Electric School Buses, said in a press release. “These new electric buses will eliminate dangerous toxins in the air our children and communities breathe and reduce climate-harming pollution. For students and drivers, this means quieter rides, better health and fewer missed days of school or work due to preventable respiratory illnesses.”
Regan said EPA will soon establish a $1 billion pool to take another round of applications for clean bus grants. “Improving lives of young children around the country is near and dear to the EPA’s mission,” he said.
Global use of fossil fuels will peak by 2030, but to reach a worldwide net-zero economy by 2050 — and keep the increase in the global average temperature to 1.5 degrees Celsius — clean energy investments must double to $4 trillion per year at the same time, according to the International Energy Agency’s World Energy Outlook 2022.
The current worldwide energy crisis, triggered by Russia’s invasion of Ukraine, has become “a turning point in the history of energy by accelerating clean energy transitions,” Fatih Birol, IEA’s executive director, said during an online launch event for the report Thursday. “We are seeing an unprecedented increase in different clean energy options — solar PV, wind, batteries, heat pumps, nuclear power, energy efficiency — in all of them.”
Further, Birol said, “the biggest driver of renewable energy in many parts of the world is energy security, not necessarily climate commitments as it was before.” Climate commitments are still important, he said, but another key factor is that “many governments want to be part of the new industrial era based on clean energy manufacturing.”
Just taking into account current stated policies, IEA projects, the world’s energy supply will depend increasingly on renewables, mostly wind and solar, by 2030. | IEA
Birol pointed to the passage of the Inflation Reduction Act in the U.S.; the EU’s REPowerEU initiative to cut the region’s dependence on Russian fossil fuels by 2030; and Japan’s Green Transformation as evidence of a historic pivot in clean energy policy and investment.
Those policies and investments will trigger a series of turning points in the coming decade, said Laura Cozzi, IEA’s chief energy modeler. “What’s happening is very clear: Clean energy technologies, solar in particular, are becoming very cheap. Supporting policies like the IRA are really helping to make solar even cheaper.
“The expectation is that in the next five years, [global] solar installed capacity will surpass that of coal to become the No. 1 capacity installed for electricity generation,” she said.
Overall, clean energy technologies, including nuclear, will surpass electricity generation from all fossil fuels by the end of the decade, Cozzi said. “We will see a peak in electricity sector emissions very soon, and emissions will start to decline,” she said.
Laura Cozzi, IEA | IEA
The report does see a near-term increase in fossil fuel use and emissions as countries around the world scramble to provide secure, affordable energy for their citizens, and Russia loses its dominance as the top exporter of fossil fuels. Worldwide inflation also means that an estimated 75 million people who recently gained access to electricity will not be able to afford that power, raising the number of people living without electricity for the first time since IEA started tracking those numbers, the report said.
“With energy markets remaining extremely vulnerable, today’s energy shock is a reminder of the fragility and unsustainability of our current energy system,” the report says. “Today’s energy crisis has underscored that, in practice, the future of energy markets is likely to be disjointed, subject to geopolitical friction and prone to regular market imbalances” — in other words, messy.
Synchronizing Change
The report lays out three scenarios for the pace and scale of the global energy transition between now and 2050, based on current stated energy policies (STEPS), the announced pledges countries made at or after the 2021 U.N. Climate Conference in Glasgow (APS) and a net-zero energy goal (NZE).
The STEPS scenario results in a 2.5-degree Celsius temperature increase by 2050 versus an increase of 1.7 degrees in the APS scenario. The NZE scenario hits 1.5 degrees in 2050 and edges down to 1.4 degrees by 2100, the report says.
Ramping up clean energy investment, especially in emerging and developing economies, will be critical for closing those gaps, Birol said.
Emerging market and developing economies, other than China, account for two-thirds of the global population, but their share of clean energy investment is both low and declining, IEA says. | IEA
Looking toward the upcoming 27th U.N. Climate Conference of the Parties (COP27) in Sharm El Sheikh, Egypt, next month, he said, “It is time for advanced economics, so-called ‘rich’ countries, to show that they are serious about climate change by providing support for the clean energy investment in developing countries, especially in Africa. … I would like to see strong support of advanced economies for African or in general developing countries’ energy transitions, and having empathy for the political, economic and social priorities of the countries in Africa and beyond.”
The report also offers a list of recommendations for minimizing some of the bumps and turmoil of the coming years, beginning with a close synchronization of changing investments in clean energy and fossil fuels.
Tim Gould, IEA | IEA
“For the next few decades, at least, we will be drawing down a system based on fossil fuels and building one up based on clean energy,“ said Tim Gould, IEA’s chief energy economist. “But we need both parts to function well for the duration of that transformation. … The speed and security of the transition depends on synchronizing changes across the different parts of the energy system.”
At present, for every dollar spent on fossil fuels, $1.50 is spent on clean energy, Gould said. Getting to net zero does not necessarily mean no further investments in fossil fuels, he said, but rather a very different ratio, with clean energy getting $9 in investment for every $1 in fossil fuels.
“Under those circumstances we have choices about how we choose to guard against the possibility of future volatility,” he said.
Flexibility Quadrupled
Still another core element in the transition will be the role of governments in providing “strategic direction” for markets, the report says, noting that current markets “may not be configured to deliver net zero at lowest cost to consumers.
“One early task for governments is to eliminate distortions and barriers that actively hinder energy transitions, such as lengthy permitting procedures, unnecessary trade barriers, inefficient fossil fuel subsidies and outdated market arrangements that favor incumbent producers and technologies,” the report said.
A price on carbon is one solution. “Governments have to take the lead in ensuring secure energy transitions, but they can be significantly assisted by well functioning markets and market mechanisms that reflect the costs of pollution, by bringing in private capital and allocating it efficiently,” the report says.
Other recommendations in the report include:
prioritizing energy efficiency and demand management. Efficiency is critical now and going forward as houses, cars and other infrastructure built today will still be in use by 2050, the report says. Beyond lowering household electricity bills, efficiency “also brings energy security benefits, especially at a time when the world is moving towards a decarbonized energy system, by reducing strains on fuel markets and the need for costly and uncertain investments in new supply.”
investing in flexibility. Increasing electrification and electricity demand, coupled with increasing amounts of variable renewable energy on the grid, will require a quadrupling of flexibility by midcentury, the report says. Batteries and demand management are expected to provide a quarter or more of the needed flexibility.
fostering climate resilience of energy infrastructure. The increasing frequency and intensity of extreme weather events means that “governments need to act to ensure that the system has the ability to anticipate, absorb, accommodate and recover from adverse impacts,” the report says. Noting that both natural gas plants and solar panels are less efficient at high temperatures, the report says, “making reliable climate and weather data publicly available could help energy suppliers better understand potential climate risks and impacts.”
Pacific Gas and Electric said Thursday it would incur $100 million in costs from this year’s Mosquito Fire, two days after regulators proposed fining the company $155 million for 2020’s deadly Zogg Fire.
The potential losses from the Mosquito Fire were reported in PG&E’s third-quarter earnings report to the Securities and Exchange Commission and discussed in an earnings call Thursday.
The Mosquito Fire began Sept. 6 in the Sierra Nevada foothills about 50 miles northeast of Sacramento. It burned through nearly 77,000 acres, mainly in the El Dorado and Tahoe national forests, and destroyed 78 structures.
The U.S. Forest Service launched a criminal investigation of PG&E for its role in starting the fire and seized utility equipment near the ignition point, including a PG&E transmission pole. PG&E previously told the California Public Utilities Commission (CPUC) that it had recorded “electrical activity” on the suspect line when the fire started.
PG&E CEO Patti Poppe said Thursday the wildfire costs would be covered by insurance.
“We added the Mosquito Fire to our CPUC reportable ignitions greater than or equal to 100 acres,” Poppe said. “Though the investigation is not complete, we can see that the fire started near the base of our 60-kV steel pole … [and] we booked a liability for the Mosquito Fire of $100 million, which is well within our range of insurance.”
On Tuesday, the CPUC proposed fining PG&E $155.4 million for the Zogg Fire, which killed four people including a mother and her young daughter who were overtaken by flames while fleeing the blaze.
The fire started Sept. 27, 2020, when a gray pine tree fell onto a PG&E distribution line in rural Shasta County, the California Department of Forestry and Fire Protection found. It burned 56,000 acres and destroyed more than 200 structures.
A contractor working for PG&E had failed to remove the pine tree even though it was leaning dangerously toward the power line and had shallow roots, a federal judge overseeing PG&E’s criminal probation said in a February 2021 hearing. The line that the tree struck had remained energized even though PG&E had ordered widespread public safety power shutoffs in the surrounding area because of high winds, the judge learned.
“I think it was reckless, maybe criminally reckless, for PG&E to have left that tree, that gray pine looming,” Judge William Alsup said in the hearing. “It was leaning at a 60-degree angle over that line. Gray pines … have a shallow root system. That tree had also been burned earlier. That tree was a clear and present danger to the line, and whoever made the decision to leave that tree up should be looked at very carefully. And PG&E did leave it up.”
The CPUC said in its proposed order Tuesday that the utility had failed “to remove two trees [including the gray pine] previously flagged for removal due to a combination of poor recordkeeping, poor communication, and lack of caution. Juxtaposing PG&E’s failure to remove the trees with [an arborist’s report] — showing that the tree was clearly likely to fall — demonstrates a high degree of culpability in PG&E’s conduct.”
After the CPUC finalizes its order, PG&E will have 30 days to request a hearing or to agree to pay the penalty and submit a corrective action plan. The plan must show that PG&E has a system in place to keep track of trees slated for removal.
The actions against PG&E for the Zogg and Mosquito fires are the latest in a series of financial penalties, criminal convictions and payments to wildfire victims related to catastrophic fires started by PG&E equipment in the past five years.
The wildfires included the Northern California wine country fires of October 2017; the Camp Fire, which killed at least 84 people and leveled the town of Paradise, in November 2018; the Kincade Fire, which tore through Sonoma County in October 2019; and the nearly 1-million-acre Dixie Fire, the state’s second largest wildland blaze, which raged for months in 2021.
The company filed for bankruptcy protection in January 2019 following the Camp Fire and emerged from Chapter 11 proceedings in June 2019, after agreeing to pay a total of $25.5 billion to fire victims, insurance companies and local governments for the wine country fires and the Camp Fire.
PG&E reported third-quarter earnings of $456 million (21 cents/share), compared with losses of $1.09 billion (.055 cents/share) in Q3 2021. Its stock closed at $15.60 on Thursday.
New Jersey’s Board of Public Utilities (BPU) on Wednesday approved a $16.15 million allocation of funds from the Regional Greenhouse Gas Initiative to create the state’s first program designed to promote the installation of fast chargers for medium- and heavy-duty (MHD) electric vehicles.
The program, which includes an emphasis on smaller owner-operator trucking companies located in overburdened communities, will provide incentives of up to $225,000 for the purchase and installation of up to six direct current fast chargers (DCFCs).
With a two-pronged focus, the program aims to stimulate the development of community charging stations — those in locations where they could serve several trucking companies — and private fleet chargers, to incentivize trucking companies to go electric.
Saying that the state until now had no MHD incentive programs, the order creating the program said it “could help remove a key electrification obstacle for businesses” in environmental justice areas.
“A significant portion of MHD vehicles are independently owned and operated, and since investment in charging infrastructure is often cost prohibitive, there is a need to provide publicly accessible MHD charging for those vehicles near their base of operations and along their travel routes,” said the order, which the board approved unanimously.
Growing EV Fleets
The initiative comes as the BPU seeks to reduce transportation emissions, which account for 42% of the state’s emissions, with a particular focus on the trucking sector’s large contribution.
The state’s multipronged effort includes a June 2021 straw proposal to design a program to promote the development of charging sites for MHD electric trucks and ensuring they are distributed across the state in line with the needs of trucks, buses and other users. No final program has yet been released, and the design process is ongoing.
Other initiatives to get more EV trucks on the road include the state Department of Environmental Protection’s adoption in December of EV truck sales targets, and the New Jersey Economic Development Authority’s (EDA) two-year-old NJ Zero-Emission Incentive Program (NJZIP). The program, which the EDA said in July had funded the purchase of more than 150 light- and medium-duty trucks, awards vouchers to help buy an electric truck.
Pamela Frank — CEO of ChargEVC-NJ, an advocacy group that champions electric vehicle policies — said the state “certainly benefits from electrification of the MHD segment, and the linkage with this program and EDA’s ZIP program makes good sense.” Frank has in the past expressed concern that the state is not moving fast enough to promote heavy-duty electric vehicles.
“We need an all-hands-on-deck approach to tackle premium costs for these vehicles, which are declining, especially with respect to the lighter delivery trucks; and the costs associated with responsible grid integration,” she said.
Under the program announced Wednesday, the “BPU will develop new or enhance existing programming enabling low- and moderate-income households, particularly those in environmental justice communities, to participate in and benefit from the state of New Jersey’s efforts to improve access to clean transportation.”
The program will fund up to 100% of the purchase and installation costs of DCFC chargers with a capacity of 150 kWh or greater for community charging stations, to a maximum of $225,000 with no more than six chargers per location. To be eligible, the recipient must be located in or operating in an overburdened community.
New Jersey defines overburdened communities as any census block in which at least 35% of the households qualify as low-income; at least 40% of residents are minorities; or at least 40% of households have limited English proficiency. They account for about 4.7 million people, or slightly more than half the population of the state.
“The goal of the community charging track of this program would be to identify areas with a significant presence of, or interest in growing the operation of, electric MHD vehicles,” the order said. “The optimal locations for community chargers are those that are accessible by several local businesses that have or are interested in acquiring MHD EVs, such as warehouses or depots, with preference given to those that can demonstrate close proximity to businesses that currently own or operate MHD EVs.”
Initiatives under the private fleet charging sector would be eligible for incentives to cover 75% of the purchase and installation of DCFCs to a maximum of $175,000 and a cap of six chargers per location. The chargers in that case would not be required to be accessible to the public. Incentives in the fleet program will only be available to private fleets that have been awarded funding under the state’s NJZIP program and are either in an overburdened community targeted in the first phase of the program or have received an incentive that has been enhanced because of its location in an environmental justice area.
“The optimal locations for community chargers are those that are accessible by several local businesses that have or are interested in acquiring MHD EVs, such as warehouses or depots,” the order says, adding that there would be “preference given to those that can demonstrate close proximity to businesses that currently own or operate MHD EVs.”
Trucker Reluctance
New Jersey truckers have been slow to embrace EVs, however. Like those around the nation, they cite the lack of heavy-duty charging sites as a key obstacle to greater use of electric trucks. Other barriers cited by truckers in the past include the limited number of truck models available, the short range of existing electric trucks — which for larger trucks is about up to 250 miles — and the high cost of the vehicles.
The EDA, in line with the New Jersey Energy Master Plan, is seeking to transition 75% of the state’s medium-duty trucks and half of its heavy-duty trucks to EVs by 2050.
The NJZIP program, which is now in its third year, initially awarded purchase vouchers only for the purchase of light and medium trucks located or to be used in Newark or Camden, both of which are overburdened communities, or within 10 miles of the two cities. Newark is also next to the Port of New York and New Jersey, into which thousands of trucks drive each day.
The program was later expanded to include New Brunswick, in Central New Jersey, and to include communities in and around the Jersey Shore. The EDA allocated funds of $24.25 million to award vouchers of between $25,000 and $100,000 for the purchase of trucks of size Class 2B through Class 6. But the EDA in July expanded the program, adding $46.6 million in funds and for the first time awarding incentives of up Class 7 and Class 8, the largest in use, and a maximum incentive of $175,000. (See NJ Adds $46.6 Million to Electric Truck Incentives.)
Public Service Enterprise Group (NYSE:PEG) and three trade groups told the New Jersey Board of Public Utilities (BPU) on Friday that utilities should play a greater role in owning and operating storage facilities than the one allowed under a proposal by the agency.
During an over three-hour hearing into the storage plan that attracted 300 participants, PSEG pushed back on the BPU’s plans to limit utility participation in order to encourage private investment and ownership of the new facilities that the state hopes to develop as part of its plan to have 2,000 MW of storage in place by 2030.
The BPU’s proposed Storage Incentive Program (SIP), released on Sept. 29, would go to privately owned and operated storage, consistent with New Jersey’s “restructured competitive market structure.” But “there will also need to be a robust effort by EDCs [electric distribution companies] to ensure that the grid is capable of connecting storage devices at the distribution and transmission levels,” the proposal says.
“Thus, while the New Jersey SIP does not propose to allow for utility ownership or operation of devices, EDCs will play a key role in building the grid infrastructure necessary to enable the effective dispatch of energy storage devices,” it says.
“So it wouldn’t be just ‘OK, the utilities can just install and ratebase’” the development of new storage, explained Paul Heitmann, a BPU staffer who presented the proposal at the hearing.
But a PSEG representative argued that given the “urgency” of reaching the state’s goal, utilities should be able to do more under the plan.
“We believe that the board needs to use every available resource to meet this challenge,” said Kate Smith, managing counsel for PSEG’s state regulatory group. “And we respectfully suggest that the these goals may not be feasible without more participation from the EDCs and that the EDC should be a resource that should be more a part of this New Jersey SIP solution now.”
Smith said the utility believes “that we need to be more of a part of these solutions from a utility deployment standpoint.” She noted that PSEG in 2018 filed a proposal for the utility to develop 35 MW of storage. That plan, in which PSEG proposed to spend $180 million, is still pending, and the utility has agreed to put it on hold while the BPU develops its policy.
“We don’t believe that the goals expressed here, and the plan that’s put forth here, are mutually exclusive to utility investment,” Smith said. “We think that the EDCs can support and complement private investment.”
Storage is ‘Critical’
The hearing, the first of three to be held on the SIP, is part of the BPU’s effort to jumpstart the development of a storage sector after several years of inactivity. The next meetings are on Nov. 4 and 14.
The state Energy Master Plan in 2019 said the state would need 9 GW of storage capacity to manage its clean energy goals, and the state Clean Energy Act, enacted in 2018, said that the BPU should create a process for putting 600 MW of storage in place by 2021 and 2,000 MW in place by 2030. Yet the state today has only about 500 MW in place, much of which is decades old. (See NJ Lagging in Energy Storage Progress.)
The SIP sets a target of building 1,000 MW of four-hour-plus storage by 2030 and is part of a two-pronged approach to reaching the 2,000-MW goal. The remaining 1,000 MW would come from the Competitive Solar Incentive (CSI) program, which is designed to provide incentives for grid-scale solar projects, along with co-located storage. Final rules for the CSI program are expected to be released this year.
Storage is widely seen as a paramount element needed to manage electricity supply without relying on fossil fuel as intermittent renewables increasingly dominate the resource mix.
“Whether it’s the board’s energy [plan], or New Jersey’s Energy Master Plan, or any number of other pathways to 100% clean energy, energy storage is really a critical element in keeping the grid balanced and making sure that we can do the clean energy transition on time and on budget,” Abe Silverman, executive policy counsel for the BPU, told the hearing.
The BPU’s plan would provide incentives for both utility-scale and distributed projects. About 30% of the incentives would be paid to storage projects as fixed annual incentives, with a set value per kilowatt-hour of capacity. The remainder of the incentives would be paid through a “pay for performance” mechanism and tied to the environmental benefits.
Speaking at the hearing, Sarah Steindel of the New Jersey Division of Rate Counsel said the BPU needs to closely monitor the cost of the plan and look beyond ratepayers for funding, such as federal infrastructure money and private research funding.
“We need a plan for how much we’re going to spend on this, including the costs of utility infrastructure, and how much measurable non-speculative benefits we’re going to get from this,” she said. “The board’s well aware that many ratepayers are already stressed. They’re already paying for solar, offshore wind, nuclear subsidies” and electric vehicles. “And we need to think carefully about the money we’re spending and how we’re spending it.”
Seeking an Additional Utility Role
Other speakers also said they were not convinced that allowing solely private investment in storage would enable the state to reach its storage targets, and they advocated for utilities to be able to participate more.
“Given the magnitude of the state’s storage goals — in addition to efforts for electric vehicles, energy efficiency, peak demand reduction, renewable targets, and the need to ensure reliability and resiliency — EDC ownership should remain a viable option because of the expertise and knowledge the EDCs have about their unique systems,” said Christopher Wehr, staff analyst for FirstEnergy (NYSE:FE), parent of Jersey Central Power & Light. “And they’re kind of best suited to identify the areas where these strategic investments will provide the benefits to customers.”
That view was echoed by trade groups including the New Jersey Utilities Association, the New Jersey Alliance for Action and New Jersey Energy Coalition. Allison McLeod, public policy director for the New Jersey League of Conservation Voters, encouraged the BPU to look for an additional role for the utilities, saying that “their participation could be a valuable resource to the board and to the overall efforts to electrify.”
Too Little Support Early on
Other speakers focused on the allocation of incentives in the proposal.
Scott Elias, director of Mid-Atlantic state affairs for the Solar Energy Industries Association (SEIA), questioned the impact of what the SIP proposal describes as a “declining block structure” for allocating incentives. The program would set capacity blocks at a certain incentive, and once the BPU has allocated a block of incentives to storage projects, a new block would open at a lower incentive rate. BPU officials say the system would enable the agency to assess the demand for incentive’s to build storage capacity at certain rates and adjust it if there are too few applications at particular levels.
Elias said that SEIA is concerned at the “size and cadence of the capacity blocks.”
“Backloading most of the capacity to later years and later blocks means that a single grid supply project, for instance, could eat up the entire capacity” for a year, he said.
Lyle Rawlings, president of the Mid-Atlantic Solar and Storage Industries Association, said he also believes that there needs to be more incentives in the first two years of the program. In addition, his organization is concerned by the SIP’s plan to allocate incentives to develop three times as much storage from grid projects as from distributed energy projects. Given that the BPU plans to secure half of its storage development from solar-tied storage in the CSI program, which would also come from grid-scale projects, the state is giving too little focus on the distributed energy sector, Rawling said.
“There should be a much greater emphasis on distributed” energy storage, he said. With “distributed generation, there’s a lot of pent-up demand ready to go. So this can quickly be deployed to meet the goals.”
WASHINGTON — Decarbonizing the hardest-to-decarbonize industries will likely involve some failures, said Geraldine Richmond, the Department of Energy’s undersecretary for science and innovation.
“We have to accept that some things are going to fail, that things are not going to go out as fast as we want. But that’s because we’re moving hard and we’re trying to do the best we can,” Richmond said at Resources for the Future’s Net Zero Economy Summit on Thursday. “But if you don’t take those risks, you’re not going to get anywhere. … So, we’re just going to have to suck it up and keep going. It can’t stop us.”
Tackling industrial decarbonization is now widely recognized as essential to U.S. and global efforts to cut greenhouse gas emissions to net zero by 2050, and it has become a regular part of the agenda for any clean energy conference. At RFF’s event, discussions ranged from steel and cement to international aviation.
During an industrial decarbonization panel, both Richmond and Alan Krupnick, industry and fuels program director at RFF, argued for the value of the lessons learned from failure. Krupnick pointed to the Petra Nova carbon capture project, a much hailed project at a coal plant in Texas, which received about $190 million in DOE funds and closed down in 2020.
Referring to funding for carbon capture in both the Infrastructure Investment and Jobs Act and the Inflation Reduction Act, Krupnick said, “Even failures can provide us learnings. … What we have to do … going forward, we have to expect failure. We have to learn from it and then move forward.”
The DOE’s Earthshots initiative is aimed at solving some of the core challenges of industrial decarbonization, such as the Hydrogen Shot’s goal of cutting the price of green hydrogen to $1/kg within the decade and the Industrial Heat Shot’s effort to reduce emissions from industrial heat processes by 85% by 2035.
The goal, Richmond said, is “to take everything from a discovery science all the way to the applied science and demonstration, so they can pass them off to deployment.”
Each of the shots has a goal, she said, that has “in mind a cost, has in mind efficiency, has in mind stumbling blocks that we have to get over in order to make progress. In the past the Department of Energy hasn’t been as coordinated as it is right now with regards connecting the discovery science to the applied science. … Now we’ve gotten tight; we’re rolling so that we can make sure that the discoveries get all the way to deployment.”
‘A New DOE’
With the midterm elections looming, Krupnick said the DOE is creating challenges of its own in its effort to get the IIJA and IRA funds out the door as quickly as possible “before the possible change in control of Congress and before a possible change in the presidency to the Republicans.”
Referring to the DOE’s recent funding announcement for hydrogen hubs, he said, “we’ve taken the discipline of the market in making decisions across technologies, and we’ve moved it basically to DOE, [which] has to pick winners out of let’s say there might be 30 or 25 hydrogen hub proposals, and only a fraction of that will get go/no-go decisions for the next round. … It puts a lot of responsibility on DOE to make correct choices.” (See DOE Opens Solicitation for $7B in Hydrogen Hubs Funding.)
Still another factor in the funding process is President Biden’s Justice 40 initiative, which requires that 40% of the benefits from federal funding go to low-income and disadvantaged communities.
“It’s important for us to make sure that we are putting these facilities in places that have had their factories shut down,” Richmond said. “So, we’re really paying a lot of attention to that, whether it means we’re thinking about putting a nuclear plant where there was a coal mine so that it provides jobs for workers in that place.
“It’s a new DOE,” she said. All basic science programs at labs and universities that apply for funding “must put [in] a plan on how you’re going to be inclusive in your operation. … That means the students that you’re going to train for the future, those that have been marginalized, those that have been left out in the past because they couldn’t afford to, for example, go to graduate school, you have to show what you are going to do to get those students into the workforce.”
Cement
Sean O’Neill, senior vice president of government affairs for the Portland Cement Association, an industry trade group, talked up his organization’s roadmap to make the cement and concrete industry net zero by 2050. The processes involved in making cement require high temperatures, generally provided by coal and carbon capture utilization and storage which “is a critical part” of the PCA’s roadmap, O’Neill said. “We cannot reach our goals without CCUS,” he said, while also noting that the industry is experimenting with other, lower-carbon fuels, such as biomass and natural gas.
But the one thing O’Neill says his members are not talking about is cutting back on production, particularly in light of the need for cement and concrete for infrastructure projects funded by the IIJA. “It’s not a conversation we’re having,” he said. “The conversation that we’re having is how can we continue to meet infrastructure needs in this country, in the world, while also looking to decarbonize the process.”
One example, he said, is Portland limestone cement, which has a higher limestone content and lower carbon intensity than traditional cements. But the industry is still struggling to get it included in project specifications, O’Neill said. Instead of “prescriptive specifications” for big infrastructure projects, he called for “performance-based specifications … [that] will drive the market for our low-carbon cement and concrete.” (See Challenges Loom for Decarbonizing Concrete.)
Looking ahead, O’Neill said the industry is focusing on “what can we do to ensure there is a market for these materials. A lot of it has to go to standards and specifications. … At the end of the day, a contractor or owner who’s going to be constructing an asset, they want to have the confidence that the lower-carbon concrete that they’re using to build whatever they’re building will perform.”
Aviation
International aviation is notoriously hard to decarbonize “because lightweight liquid transportation fuel is pretty tough to beat when it comes to the challenge of lifting a heavy aircraft off the ground,” said Annie Petsonk, assistant secretary for aviation and international affairs at the U.S. Department of Transportation.
Even most “sustainable” fuels are carbon-based, Petsonk said during an on-stage conversation with Billy Pizer, RFF’s vice president of research and policy. “They, when burned in the engine of the aircraft, emit carbon dioxide. … But what sustainable aviation fuels are better for the environment is on a lifecycle basis from the time that your feedstock was produced to transporting the fuel to the airfield.”
Developing standards for that analysis took the Carbon Offsetting and Reduction Scheme for International Aviation (CORSIA), an international body, seven years, she said.
Another longstanding challenge has been how to allocate emissions from international flights. “If the plane is taking off in one country and landing in a different country, whose emissions are they — the emissions of the country of departure, the country of arrival? The [nationality] of the aircraft or the airline … may be different. How about the people on the plane?”
Earlier this month, the International Civil Aviation Organization, an UN agency, adopted a long-term “aspirational goal” of net-zero emissions for the industry by 2050, “with the [provision] that each country implement it in its own way,” Petsonk said. At the same meeting, CORSIA also set an emissions reduction baseline for international aviation of 85% of 2019 emissions beginning in 2024.
“What this means is that, for the first time, global aviation has both a near- and mid-term goal from now to 2035 … and a long-term goal, which is a really important signal to send, the 2050 goal, since aviation is a long capital stock industry,” she said. “It takes many years to develop [a plane], test it, fly it and [put] it into production and keep it in production for decades.”
The international lifecycle standards are being used as a baseline for the IRA’s tax credits for sustainable aviation fuels, Petsonk said. The tax credit starts at $1.25 per gallon “if the fuel is at least 50% better than fossil fuel on a lifecycle basis.”
It goes up a penny per gallon “for every percentage point improvement in lifecycle [emissions] up to completely carbon neutral,” she said. “We’re already seeing a terrific market response to this. … We’re hearing a lot from investors,” who already want the tax credit extended beyond the IRA’s 10 years, she said.
