The California Public Utilities Commission on Thursday established the first program of its kind in the nation by adopting a submetering protocol to allow electric vehicle owners to be billed separately for charging at lower rates than the rest of their electricity use.
“Submetering makes EV charging cheaper and will help spur the growth of electric vehicles throughout the state,” Commissioner Clifford Rechtschaffen said in statement following the unanimous vote. “It’s a practical solution to one of the important barriers to widespread EV adoption.”
The program uses submeters embedded in charging equipment as a way to avoid having to install costly second utility meters in homes and locations where electric trucks and buses charge. The submeters can transmit electric-use data via Wi-Fi or cellular networks.
The CPUC’s decision affects customers of the state’s three large investor-owned utilities — Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric — all of which offer special rates for EV charging.
The IOUs have run submetering pilot programs since 2014 at the CPUC’s direction. The pilot programs addressed issues such as the reliability and accuracy of submetering and how to store and transfer the raw meter data.
The decision excludes net energy metering (NEM) customers with rooftop solar because the utilities said they have no way to tell if their energy consumption, recorded by a submeter, comes from the distribution grid, local renewable generation or battery storage. The CPUC ordered additional study to find ways of allowing NEM customers to participate in submetering.
The commission adopted a two-year timeline for the IOUs to incorporate submetering into their billing systems.
“The submetering protocol is a fundamentally important means of accelerating the growth of electric vehicles,” the decision said. “The protocol reduces the cost of electric vehicle charging; consumers can avoid having to install a separate utility meter and can instead use the technology to have their electric vehicle charging measured and billed separately from their primary utility meter. Submetering thus promotes the adoption of electric vehicles, the deployment of vehicle-grid integration, and the realization of the corresponding electric grid benefits.”
California is by far the nation’s leader in EVs with more than 1 million on the road, roughly half those in the U.S. Rechtschaffen said that more than 16% of new vehicles sold in-state are now EVs.
Gov. Gavin Newsom issued an executive order in September 2020 requiring all new passenger vehicles sold in the state to be zero-emission vehicles by 2035 and included $10 billion in recent budgets to accelerate the transition.
The CPUC has authorized the IOUs to spend more than $1.5 billion on EV charging and to create menus of special rates for it so that charging it is less expensive than buying gas or diesel fuel.
A federal judge has rejected two resource plans from Bureau of Land Management field offices in Montana and Wyoming, saying the agency didn’t disclose the health impacts of burning fossil fuels extracted from the planning zones.
BLM also didn’t consider alternatives that limited or eliminated coal leasing when it analyzed environmental impacts from the resource management plans, U.S. District Court Judge Brian Morris said in an order issued Wednesday. The resource plans were from the Miles City Field Office in Montana and the Buffalo Field Office in Wyoming.
The judge’s order gave BLM up to a year to conduct new coal screening and environmental review of the two resource management plans.
Conservation groups called the judge’s decision a victory.
“That a federal judge ordered the Bureau to consider a no-leasing alternative and disclose to the public how many people will be sickened and die as a result of the combustion of federal coal is groundbreaking,” Melissa Hornbein, a senior attorney at the Western Environmental Law Center, said in a statement.
Hornbein was one of the attorneys representing plaintiffs in the case, which included the Western Organization of Resource Councils, Montana Environmental Information Center, Powder River Basin Resource Council, Northern Plains Resource Council, Center for Biological Diversity, Wildearth Guardians and the Sierra Club.
Coal Producing Region
The Miles City and Buffalo field offices are within the Powder River Basin, which encompasses more than 13 million acres across Montana and Wyoming.
The basin produces about 40% of the coal in the U.S., along with oil and gas, the plaintiffs said in their complaint.
Under all alternatives considered for the Miles City resource plan, 775 million tons of coal from 9,730 acres would be strip-mined over 20 years, the complaint said. Alternatives analyzed for the Buffalo resource plan included strip-mining of 4.9 billion tons of coal from 36,620 acres.
BLM revised land management plans in 10 Western states in 2015 — including the Miles City and Buffalo plans — to add protections for sage grouse, according to Morris’ order. Conservation groups challenged the resource plans in 2016, saying they didn’t comply with the National Environmental Policy Act (NEPA).
The court sided with the plaintiffs and sent the resource plans back to BLM to correct deficiencies. In particular, the court asked BLM to evaluate alternatives that would reduce the amount of available coal and analyze the “downstream” environmental impacts of combustion of coal, oil and gas open to development under the plans.
Additional Analysis
In response, BLM performed additional analysis and approved resource management plan amendments and supplemental environmental impact statements for the plans.
But the conservation groups still weren’t satisfied and sued again in August 2020 in U.S. District Court in Montana.
In its new analysis, BLM looked at alternatives for the two field offices that allotted different amounts of land for coal leasing.
But the amount of coal production expected under each alternative was the same, and so BLM didn’t adequately consider a reasonable range of alternatives, Morris said in his order.
“BLM failed to consider any alternatives that would limit the expansion of existing mines,” Morris wrote.
In response to the previous court order to analyze the impacts of fossil fuel combustion, BLM looked at the effects of greenhouse gas emissions from burning coal derived from the planning areas. But the conservation groups said the analysis should have included other types of pollution, such as sulfur dioxide, nitrogen oxides, particulate matter, mercury and lead.
Morris said NEPA requires an environmental impact statement to consider indirect as well as direct impacts of a proposed action.
“BLM’s failure to consider the downstream impacts proves arbitrary and capricious, especially in light of the court’s prior order,” the judge wrote.
Electric vehicle drivers seeking a West Coast odyssey along Interstate 5 should soon feel less range anxiety thanks to funding provided by the federal Infrastructure Investment and Jobs Act (IIJA).
But those looking to take Highway 101 will have to wait longer to be assured of convenient charging along that more scenic route along the coast.
Plans filed this week by California, Oregon and Washington to obtain funding from the Federal Highway Administration’s (FHWA) National Electric Vehicle Infrastructure (NEVI) program show all three states using their initial round money to prioritize the buildout of fast chargers along the I-5 corridor.
For California, that will entail deploying new chargers or upgrading existing ones at a number of I-5 interchanges with other east-west highways that the state is already working to make travel-ready for EVs. Oregon and Washington will seek to fill gaps along I-5, while setting the stage to cover the vast interior sections of their states.
Administered by the FHWA and U.S. Department of Energy through the Joint Office of Energy and Transportation (JOET), the NEVI program intends to build out a national network of 500,000 DC fast chargers (DCFCs) using $5 billion in IIJA formula funding granted to the states over the next five years. NEVI guidelines require states to install DCFCs of at least 150 kW along designated Alternative Fuel Corridors (AFCs) at distances no greater than 50 miles apart and within 1 mile of a highway exit.
All 50 states, plus D.C. and Puerto Rico, submitted plans to receive their share of funding by the Aug. 1 deadline, according to the FHWA. The agency now has until Sept. 30 to approve the plans. (See related story, States File Plans on Deadline for Federal EV Charging Funds.)
Oregon
While the goal of the NEVI program is to facilitate interstate travel for EVs, state plans are primarily focusing on local needs around charging in order to encourage adoption of clean transportation.
Oregon and Washington face similar challenges in deploying chargers in ways that overcome range anxiety. Both states contain heavily urbanized areas along the I-5 corridor west of the Cascade Range, where EV adoption rates are relatively high compared with national averages. In the sparsely populated areas east of the Cascades, where population centers are dispersed, residents are more skeptical of the practicality of electrifying transportation, given daily travel distances.
The Oregon Department of Transportation’s (ODOT) plan said the agency will use the state’s $52 million in NEVI funds to develop and upgrade 65 DCFC stations across Oregon, resulting at least 260 DCFC ports statewide and doubling the state’s fast-charging capacity.
According to the plan, just one corridor in Oregon is NEVI-compliant, a section of I-5 from Portland to Eugene. ODOT expects to make the rest of the state’s I-5 corridor, a major interstate freight route, NEVI compliant later this year with the initial round of funding. The state will also this year build out chargers along U.S. Route 97, a north-south highway stretching the length of Central Oregon from the Columbia River to the California border. The high-traffic I-205 corridor in the Portland metro area, adjacent to many disadvantaged communities (DACs), would also be upgraded this year.
Fiscal Year 2023 funding will focus on the east-west I-84, I-82 and U.S. 20 corridors. “U.S. 20 is a route of strategic statewide importance and a freight corridor that will provide additional rural EV charging coverage across the central part of Oregon,” ODOT’s filing states.
FY 2024 will focus on U.S. 26, U.S. 101 and I-405. “U.S. 26 will add additional coverage to Central Oregon, and completion of U.S. 101 will bolster the existing DC fast charging infrastructure along Oregon’s coast. Completion of I-405 will support the high traffic volumes and DAC populations it serves in the Portland metropolitan area,” the filing says.
ODOT said it will use the NEVI program to build on the stakeholder engagement pursued in last year’s Transportation Electrification Needs Analysis (TEINA) process, which worked to identify the state’s highest-need charging locations with an eye to serving urban dwellers in multifamily housing, rural areas and disadvantaged communities. (See Oregon Study Charts Explosive Growth of EV Chargers.)
ODOT says it will also not own, install or maintain any charging stations, but will instead partner with private sector companies after issuing “corridor-specific” competitive requests for proposals.
Washington
Washington will also partner with the private sector to build EV infrastructure, under the oversight of the state’s Department of Transportation (WSDOT).
“Funds made available under the NEVI formula program will be used to contract with third-party entities for the acquisition, installation, and operation and maintenance of publicly accessible EV charging infrastructure to ensure maximal efficient use of federal funding,” the WSDOT filing states.
Washington, which expects to receive $71 million in NEVI funds over the next five years, recently ranked as the third largest U.S. market for battery-electric vehicles. The state’s EV registrations increased from 57,338 in December 2019 to 96,961 in April 2022.
Washington’s plan contains no hard figures for charger deployments, instead noting the state will rely on its Zero-Emission Vehicle Mapping and Forecasting Tool (ZEV-MFT) — which is still under development — to site chargers with the guidance of the state’s Interagency Electric Vehicle Coordinating Council (IEVCC).
Chargers on portions of the state’s corridors already meet NEVI standards, including areas of I-5, U.S. 101 on the Olympic Peninsula and the east-west I-90 connecting the Seattle area to the eastern part of the state.
“The priority deployments [of EV chargers] will include completing the state’s north/south and east/west interstates, I-5 and I-90, respectively, to the federally defined built-out standards,” the filing says. “Secondary priorities for investments include completing the I-82/I-182 and U.S. 395 Alternative Fuel Corridors, followed by U.S. 101 and U.S. 195. State funding of DC fast chargers will supplement corridors that may not receive federal funding in the initial years of NEVI funding.”
WSDOT says it will reprioritize projects based on annual updates of the Washington State Plan for Electric Vehicle Infrastructure Deployment, as informed by ZEV-MFT and advised by the IEVCC.
California
With nearly 565,000 EVs registered in the state, California is by far the U.S. leader in EV adoption. As of February, the state had 71,236 Level 2 chargers and 7,158 fast chargers installed, according to figures provided by the office of Gov. Gavin Newsom. But only a small fraction of the state’s fast chargers are NEVI compliant, the state’s plan shows.
In its draft filing for the FWHA, the California Department of Transportation (Caltrans) said its deployment plan for the $384 million in funding slated for the state will focus on continued investments in light-duty vehicle charging infrastructure, while also considering projects that can accommodate medium- and heavy-duty vehicles.
California has nominated 20 new corridors (in orange) as national Alternative Fuel Corridors, emphasizing routes in rural, disadvantaged and tribal area. | Caltrans
According to the filing, the California Energy Commission and Caltrans will jointly develop a competitive grant-funding opportunity (GFO) to solicit applications to install DCFCs along the state’s AFCs.
California has this year nominated 20 new corridors to become designated AFCs, emphasizing routes in rural, disadvantaged and tribal areas. Most of the new corridors would intersect I-5, and one further facilitates interstate travel by linking I-5 to U.S. 97 leading into Oregon.
“California will invite applicants to submit proposals for segments based on an analysis of gaps in the current network, future charger needs and geography. Specific sites for stations will not be identified,” Caltrans said in its plan.
Applicants are instead invited to submit proposals that meet minimum standards for DCFC power levels, number of chargers and maximum distance between chargers. Standards for corridor segments may also exceed NEVI standards, depending on location, traffic and existing electric utility infrastructure, the plan said.
Applicants can also propose to upgrade existing charging facilities to meet NEVI requirements, Caltrans said.
“To ensure efficient and effective deployment that aligns with broader goals, segments will be ranked according to funding priority. California expects to provide funding for projects in rank order until funding is exhausted. Each update of the deployment plan will assess completed solicitations and re-evaluate priorities,” the agency said.
Taken together, the three state plans should help realize the vision of the West Coast Electric Highway, a partnership among agencies and organizations in the states and the Canadian province of British Columbia to install fast-charging stations every 25 to 50 miles along I-5 and other major roadways in the region.
“The Electric Highway gives electric vehicle drivers ‘range confidence’ that recharging is available should they want to travel between communities or make long-distance road trips,” the collaborative says on its website. “Knowing that charging is easy and convenient helps encourage residents and businesses to buy and drive plug-in electric vehicles.”
Federal and private-sector funding totaling $36 million will support new offshore wind workforce development initiatives in Rhode Island, Maryland, Virginia and North Carolina.
GWO Training
Representatives of offshore wind developers Ørsted and Eversource Energy (NYSE:ES) joined Rhode Island Gov. Dan McKee Wednesday to announce the companies will dedicate $1 million for a partnership to establish an OSW training certificate program. Ørsted and Eversource are jointly developing the 704-MW Revolution Wind project off the coast of Rhode Island. In 2019, they committed $4.5 million to support offshore wind education and supply chain development in the state.
The new funding announcement, which is part of that $4.5 million, will help build a Global Wind Organization (GWO) safety training program at the Community College of Rhode Island (CCRI) in cooperation with the Rhode Island Department of Labor and Training, Rhode Island Commerce, the Rhode Island Building and Construction Trades Council, and Building Futures. GWO is a nonprofit organization founded by wind developers, including Ørsted, that has been publishing wind training standards since 2012.
CCRI expects to begin enrollment for the training program early next year, and the certification will be valid for two years.
ARPA Funding
The Maryland Department of Labor received $23 million in American Rescue Plan Act funding to establish an OSW workforce training system dubbed Maryland Works for Wind (MWW). U.S. Secretary of Commerce Gina Raimondo announced the award Wednesday along with 31 other grant winners under the APRA Good Jobs Challenge.
Ørsted, which is developing the 966-MW Skipjack Wind project off the coast of Maryland, applauded the Department of Commerce award.
MWW “positions the state to build a pipeline of skilled talent to support Skipjack Wind’s development and other projects in the U.S. and globally,” David Hardy, CEO of Ørsted Offshore North America, said in a statement.
Ørsted and US Wind have agreed to be hiring partners for the MWW program, according to the labor department’s application for the ARPA challenge. US Wind is developing the 300-MW MarWin and 808-MW Momentum Wind projects off the coast of Maryland.
The labor department expects to implement the program over three phases, which will cover program development through the end of this year, design from January to June 2023, and implementation from July 2023 to June 2025.
Program implementation will feature Tier 1 and 2 training options for welding, construction and logistics along with in-house union training for apprentices. The implementation phase will represent the final two years of the program, and the department expects it to coincide with the start of hiring by Ørsted and US Wind.
Virginia and North Carolina will receive an $11-million Good Jobs Challenge grant to the Hampton Roads Workforce Council in Norfolk for maritime training program development. The council, which covers the Hampton Roads region in Southeastern Virginia and Northeastern North Carolina, expects the program to train 950 maritime professionals for OSW-related jobs.
Other ARPA Awards
The Department of Commerce awarded an additional $70.2 million in ARPA challenge funds for clean energy workforce development. Those awards are:
$23.7 to the North Carolina Agricultural and Technical State University in Greensboro to establish the STEPs4Growth clean energy workforce training program;
$23.5 to the Washington Student Achievement Council in Olympia to establish a multi-sector workforce training program covering energy, healthcare, information technology, financial services, manufacturing and construction; and
$23 million to the Economic Development and Industrial Corporation of Boston to establish the Greater Boston Region Workforce Training System for energy and resilience, healthcare and childcare.
The Biden administration announced this week that it will make $26 million available for projects to demonstrate that renewable energy and distributed energy resources (DER) can reliably power the U.S. electric grid.
The investment is part of the Department of Energy’s Solar and Wind Grid Services and Reliability Demonstration Program, created under the bipartisan Infrastructure Investment and Jobs Act that President Biden signed into law last November. (See Biden Signs $1.2 Trillion Infrastructure Bill.)
According to a press release Tuesday, the program is intended to “show how clean energy resources can address key reliability challenges facing the grid [with] tools and plant functions that allow the grid to stay online amid disturbances and restart if it goes down.”
“Americans do not have to choose between a clean grid and a reliable one as we move forward towards our goals of a net-zero economy by 2050,” Energy Secretary Jennifer Granholm said in the release. “Thanks to funding from [the] infrastructure law, DOE is proving that transitioning to solar, wind and other renewable energy sources can keep the lights on without service interruptions while creating good paying jobs.”
First is design, implementation and demonstration of wind and solar grid services, with $3 million to $6 million each earmarked for three to five recipients. For this category, the program will seek projects that produce at least 10 MW with solar, wind and storage and conduct long-duration demonstrations at existing facilities of their ability to provide grid services at scale. Organizers encouraged applicants to “develop centralized and/or autonomous local controls that demonstrate” the facilities’ ability to react to “operational commands and schedules in the existing … grid.”
The second topic is protection of bulk power systems with high contributions from inverter-based resources (IBR), planned for three or four projects at $2 million to $3 million each. This category is intended to promote large-scale studies of transmission protection systems with large amounts of IBRs, focusing on their response to faults. Recipients should be able to demonstrate protection modeling and simulation capabilities, along with technologies and strategies for maintaining reliability with “any level of inverter-based generation.”
Applicants are expected to include a range of BPS stakeholders, such as utilities, laboratories, universities, vendors of hardware and software, and engineering firms, with preference given to applications from teams of multiple institutions rather than a single organization. The department also encouraged teams to cultivate diverse backgrounds, for instance by partnering with historically Black colleges and universities or other organizations focused on minorities. SETO and WETO will provide a forum for interested parties to connect with each other.
An informational webinar on the initiative is planned for Aug. 17. Concept papers are due by 5 p.m. ET on Sept. 1.
OGE Energy’s (NYSE:OGE) exit from a midstream gas joint venture continues to pay dividends for the Oklahoma City-based utility.
CEO Sean Trauschke said Thursday that OGE has shed 77% of its limited partner units in Enable Midstream Partners for an $813 million return at an average price of $11.09/unit. Trauschke said that’s a 33% premium from where the units were when OGE and CenterPoint Energy completed Enable’s $7.2 billion sale to Energy Transfer Partners in December. (See OGE, CenterPoint Complete Enable’s Disposal.)
“Interestingly, we’ve already received more net proceeds than the value of our investment when the transaction closed,” Trauschke told financial analysts during the company’s quarterly earnings call. “We’re pleased with the pace of our progress and the value that we’ve captured for our shareholders.”
OGE also received $750 million worth of securitization bonds in July stemming from the February 2021 winter storm. The company has also filed a request with Arkansas regulators to recover $80 million in storm costs over 10 years.
CFO Bryan Buckler said the revenues will be deployed so that OGE will not have to issue equity with its five-year, $475 billion capital investment plan. Much of that plan is customer-focused transmission and distribution assets.
OGE reported earnings of $73.1 million ($0.36/diluted share) during the quarter, as compared to $112.9 million ($0.56/diluted share) for the same period a year ago. It said earnings were primarily driven by more favorable weather and recovery of capital investments.
A partial reversal of a first-quarter interim period consolidating tax benefit related to mark-to-market activity and the gain from Energy Transfer unit sales resulted in a 5-cents/diluted share hit.
Trauschke said its Oklahoma Gas & Electric subsidiary’s grid has performed well during the summer, which has seen 18 days above 100 degrees Fahrenheit since June 1.
“The grid has not been strained; we’ve not cautioned the public about potential blackouts or asked for conservation,” he said. “I’m proud of the performance of our system and employees.”
OGE’s share price lost 54 cents during a down day for the Dow Jones Industrial Average, closing at $40.13.
Duke Energy (NYSE:DUK) put a “for sale” sign on its 3.5-GW commercial renewable business Thursday, saying it wants to focus its capital on regulated spending.
The company has about 5.1 GW of wind and solar in operation, with net ownership of 3.5 GW and a book value estimated at $4 billion. That puts Duke among the top 10 wind and solar operators in the U.S. and has helped it gain experience in renewable energy development and operations that it will rely on in the future.
But the unit represents less than 5% of the company’s profits, generating $46 million in adjusted earnings for the second quarter.
Competition for Capital
“As we look forward to the remainder of this decade and beyond, we have line of sight to significant renewable grid and other investment opportunities within our faster growing regulated operations,” CEO Lynn Good said during the company’s second-quarter earnings call. “We believe this is the right time to step back and really look at the strategic fit of the commercial business, because there’s going to be competition for capital at Duke.”
The company is projecting an adjusted per-share growth rate of 5 to 7% through 2026.
The renewable business includes a pipeline of 1 to 1.5 GW “that could be quite valuable in 2024-2025, in addition to what we had planned for 2023,” Good said.
The company expects to conclude its review by the end of 2022 or early 2023. Sale proceeds would be used to avoid debt and postpone the need for raising equity, Good said.
NC Carbon Plan
The company will need capital, in part, to fund the new solar, battery storage, onshore wind and “hydrogen-capable” natural gas the company wants to add as part of the proposed carbon plan it filed with the North Carolina Utilities Commission on May 16. The plan also seeks permission to begin early development of long lead-time resources needed in the early 2030s, including offshore wind, pumped storage and small modular nuclear reactors (SMRs).
Good said Duke is working on SMRs “in an advisory capacity” by lending its operating expertise. The company operates the largest regulated nuclear fleet in the U.S., producing about half of its power in the Carolinas.
“We do not have an intention of being Version 1 of anything,” she said. “We would like to see a broader adoption of the technologies, a broader understanding of not only operating characteristics, but the commercial attributes — a price — and the ability to construct them within a time frame that we’re comfortable with. And so we see the decade of the 2020s as an important one to continue that work. And if it progresses, as we all hope it does, we would be in a position to potentially invest in one to come into service in the early 2030s.”
Good indicated that neither supply chain problems in the solar industry nor rising natural gas prices have led the company to rethink its coal retirement plans. “Frankly … the logistics of getting coal from point A to point B are also a challenge,” she said, citing labor shortages in railroads and mining companies.
Inflation Reduction Act, Load Trends
Good said the U.S. Senate’s proposed Inflation Reduction Act would benefit the commercial renewables business and save customers money through the nuclear production tax credit. “We will be impacted by the [15%] corporate minimum tax, but we will also benefit from the credits which will pass to our customers,” Good said.
Duke said it expects its 2022 load growth to be above its initial projection of 1.5%. But CFO Steve Young said the company is continuing to project minimal load growth over its five-year planning horizon as it balances the impact of electrification against energy efficiency.
Good said that while the company is basing its spending on assumptions of little additional load growth, migration trends in the Southeast give it “some tailwinds on growth that I think we’ll enjoy for a period of time.”
“But we continue to believe that flat to 0.5% is the best way to manage the business and always hope to be surprised to the upside,” she added.
Q2 Results
Duke reported GAAP second-quarter earnings of $893 million ($1.14/share) versus $751 million ($0.96/share) in 2021. Adjusted earnings were identical to GAAP results for 2022, a drop from $898 million ($1.15/share) for 2021.
Lower 2022 adjusted earnings resulted from higher operations and maintenance expenses from plant outage timing, higher interest costs and the impact of Singapore-based GIC’s 2021 purchase of 11.05% of Duke Energy Indiana.
New England state energy officials are urging ISO-NE to share confidential data about fuel supply and grid reliability with FERC ahead of the upcoming winter.
In a letter to ISO-NE this week, the New England States Committee on Electricity (NESCOE) said it would accept the RTO’s decision not to move forward with a winter reliability or inventoried energy program this year. (See ISO-NE Says No Extra Winter Programs Make Sense this Year.)
But the group said that it is “very concerned that the long-known, significant structural issues contributing to winter reliability challenges remain unresolved.”
To that end, it urged ISO-NE to share with FERC the confidential data that drove the decision not to create a winter program this year before the commission holds a forum in Vermont next month to discuss reliability issues in New England. That could include information about “fuel supplies, resource availability, historical resource performance and overall system conditions” to which the public does not have access.
“We understand that your recommendation for this winter rests in part on your confidence in your assumptions about oil and LNG availability over the coming months, which are based on both economic expectations grounded in historical actions and information not available to us or other stakeholders,” the letter says. “Sharing your analysis and the confidential information behind your fuel supply assumptions and recommendation with FERC would be helpful and appropriate given FERC’s regulatory role, ability to receive and protect confidential information, and expressed interest in discussing New England’s winter 2022/2023 outlook.”
The letter comes a few days after the states’ governors wrote to the Biden administration urging it to consider several actions before this winter, including a waiver of the Jones Act for LNG deliveries to the region. (See New England Governors Ask Feds for Help with Winter Reliability.)
The California Energy Commission released an updated draft report this week that would greatly increase the state’s offshore wind goals to 25 GW by 2045, potentially doubling anticipated long-term capacity in response to urging by stakeholders and Gov. Gavin Newsom.
The draft report proposing the targets stemmed from last year’s Assembly Bill 525, which required the CEC to “evaluate and quantify the maximum feasible capacity of offshore wind … [and to] establish megawatt offshore wind planning goals for 2030 and 2045.” The effort is intended to contribute to the state’s goal under Senate Bill 100 to supply all retail customers with 100% clean energy by 2045.
A prior draft of the report in May proposed goals of 3 GW by 2030 and 10 to 15 GW by 2045, but critics contended those goals were too conservative, and the CEC re-evaluated its estimates.
In its latest draft report published Aug. 1, the commission considered stakeholder comments and a July 22 letter from Newsom to the chair of the California Air Resources Board in which he urged “bolder action” to address the urgency of climate change.
“In the letter, among other requested actions, the governor asks the CEC to establish an offshore wind planning goal of at least 20 GW by 2045 and to work with the state’s federal partners to accelerate the deployment of offshore wind, noting that California is home to one of the best offshore wind resources in the world and that offshore wind can serve as a clean, domestic source of electricity that can play an important role in meeting the state’s growing need for clean energy,” the draft report said. “The Energy Commission factored this climate urgency and the call for at least a 20-GW goal into these proposed revisions.”
Soon after the CEC released its first draft report in May, the federal Bureau of Ocean Energy Management issued a proposed sale notice for five lease areas off the California coast, a major step toward BOEM auctions expected this fall and the eventual development of the first offshore wind farms on the West Coast.
Two of the proposed lease areas in the proposed sale notice are in the Humboldt Wind Energy Area off the coast of Northern California, near the city of Eureka. Three are in the Morro Bay Wind Energy Area off Central California, about halfway between Los Angeles and San Francisco. Together, the wind energy areas (WEAs) cover 583 square miles and have the potential to generate at least 4.5 GW of electricity, enough to power 1.5 million homes.
In raising its 2030 offshore wind goals to 3 to 5 GW, the CEC said the “upper end of this range could come from a full build-out of the Morro Bay Wind Energy Area or a combination of a partial build-out of the Morro Bay WEA and Humboldt WEA,” which will require development of a wind port in Humboldt Bay.
“The lower end of that range reflects an understanding that achieving a 2030 online date for any proposed offshore wind project will take a significant mobilization of effort and resources, and timely infrastructure investments, among other factors,” it said. “The CEC will work with state and federal partners to identify process steps and milestones that could allow for a 2030 online date for California’s first offshore wind projects.”
The higher 2045 targets “are designed to be potentially achievable but aspirational and are established at levels that can contribute significantly to achieving California’s climate goals,” the report said.
“These preliminary planning goals may be refined as part of completing the strategic plan as more information becomes available from the analysis of suitable sea space and potential impacts on coastal resources, fisheries, Native American and Indigenous people, and national defense, as well as other strategic plan topics,” it said.
The CEC is scheduled to vote on the revised goals in its business meeting on Aug. 10.
Proponents praised the higher targets.
“These goals set an ambitious course and show California is very serious about ‘going big’ on floating offshore wind to strengthen and diversify its clean power portfolio,” Adam Stern, executive director of trade group Offshore Wind California, said in a statement. “We’re determined as an industry to work closely with state and federal agencies and other stakeholders to ensure the high end of these goals becomes a reality.”
Exelon (NASDAQ:EXC) said Wednesday that the proposed 15% minimum corporate income tax included in the Democrats’ energy and climate bill could impinge its cash flow and slow infrastructure investments, while PPL (NYSE:PPL) said the change would not affect it significantly.
The companies commented on the proposed Inflation Reduction Act of 2022 during their respective second-quarter earnings calls.
Exelon CEO Chris Crane praised the bill’s extended tax benefits for solar and wind and its new ones for nuclear and hydrogen, as well as its measures to support energy efficiency and electrification.
But he said the incentives could be undermined by the new minimum tax and “slow the investment needed to make this [low-carbon] transformation.”
“As currently drafted, we could see an impact of … approximately $300 million per year starting in 2023. Higher taxes would ultimately limit our ability to invest in infrastructure needed to accommodate the clean energy our customers want,” Crane said, adding that the company and its trade group, the Edison Electric Institute, is lobbying for “language that better aligns incentives to achieve” decarbonization.
CFO Joseph Nigro declined to say whether the alternative minimum tax (AMT) would increase the company’s equity needs, saying the company would determine a response during its end-of-year planning. “It’s unclear at this point how these taxes will flow through to our customers,” Nigro said.
The company reiterated its previously announced plans to raise $1 billion in equity by 2025, half of it this year, in part to pay down short-term debt from the Feb. 2 spinoff of Constellation Energy (NASDAQ GS:CEG), its former generation unit.
Crane said the company could resort to cost cutting and adjusting project schedules to maintain its capital spending plans and earnings metrics despite the tax.
“There’s a few balls in the air that we’ll have to … juggle. But we’d rather have the fix to the bill so we’re not having to juggle this,” Crane said. “We’ll see how we prevail as an industry as we go forward.”
No Unity
The industry does not appear united on the minimum tax, however.
At PPL’s earnings call later Wednesday, company officials said they did not expect the AMT to have a material impact.
“As you know, we are now a federal cash taxpayer,” CEO Vincent Sorgi said in response to an analyst’s question. “So, we’re not anticipating the 15% AMT provision to have a significant impact on our business. … No real headwind there.”
CFO Joe Bergstein said the company’s effective tax rate is currently about 15%.
PPL CEO Vincent Sorgi | PPL
Sorgi said the IRA is a net positive for PPL, particularly as it looks to replace 1,000 MW of coal-fired generation in Kentucky by 2028 and meet Rhode Island’s newly enacted 2033 target for 100% renewable energy. In a solicitation that closes in mid-August, PPL’s Kentucky utilities said they would consider replacing the coal generation with renewables, battery storage, and peaking or baseload natural gas. PPL completed the acquisition of Rhode Island Energy in May.
“The ability to elect the production tax credit instead of the [investment tax credit] for solar will improve the economics of our self-build options as we look at renewables as a potential source of replacement generation in Kentucky,” Sorgi said. “In addition, the extension of the renewable tax credits should lower the cost of renewables overall. …
“The transferability provisions around tax credits also makes it more likely that renewables will be built,” he added. “And that’ll also be good in general for the industry and for accelerating our clean energy transition. It simplifies the structure of the deals significantly.”
EEI told RTO Insider on Wednesday that it welcomed the bill’s “robust clean energy tax package.”
But Eric Grey, EEI’s vice president of government relations, did not directly respond when asked whether the group was seeking changes to the AMT.
“As always, EEI continues to be a resource for policymakers seeking feedback on how provisions in this legislation would impact electric companies and their customers during implementation,” Grey said in a statement.
PPL said EPA’s proposed “good neighbor” rule, expected to take effect late 2022 or early 2023, could require shifting the retirement of an additional 500 MW of coal generation from a planned 2034 shutdown to the “2026 to 2028 time frame.”
The rule would require EPA and states to address interstate transport of air pollution that affects downwind states’ ability to attain National Ambient Air Quality Standards. Based on the final rule, PPL will determine whether to retire the plant or invest in “back-end technology” to keep it operating until 2034, Sorgi said.
Earnings Results
Exelon reported GAAP net income from continuing operations of $962 million ($0.47/share) for the second quarter, up from $808 million ($0.33/share) a year earlier. Adjusted (non-GAAP) operating earnings were $935 million ($0.44/share), up from $842 million ($0.36/share).
Nigro said 2021’s second quarter reflects a 9-cents/share impact for corporate overhead costs that were previously allocated to the company’s generation segment and were required by accounting rules to be presented as part of Exelon’s continuing operations. “These costs were paid for by generation and are not indicative of our corporate overhead post-separation,” he said.
PPL’s second-quarter GAAP earnings were $119 million ($0.16/share) versus $19 million ($0.03/share) in 2021. Non-GAAP earnings from continuing operations were $222 million ($0.30/share), compared with $147 million ($0.19/share) the year before.
