Virginia Gov. Glenn Youngkin (R) on Tuesday announced the launch of the Virginia Offshore Wind Supplier Development Grant, which is designed to give incentives to existing manufacturers in the commonwealth to enter into production that supports offshore wind.
The program was approved in legislation adopted last year and is administered by the Virginia Economic Development Partnership (VEDP). It offers competitive grants to assist manufacturers that want to enter the field by offsetting capital expenditures in equipment used for offshore wind.
“With a central East Coast location, one of the highest concentrations of skilled maritime talent, world-class port infrastructure and a competitive cost of doing business, Virginia has emerged as a leader in the U.S. offshore wind supply chain,” Youngkin said.“This new grant will strengthen the industry ecosystem in the commonwealth while driving economic development and job growth and is a strategic investment that supports our plan to guarantee abundant, clean energy for Virginia’s future.”
Legislators approved $2.5 million from the general fund for the grant program, which runs for three years starting this month. Funds will be disbursed as reimbursements for purchased equipment and grant awards will range from $20,000 to $250,000. Purchases made before July 1, 2023, are not eligible.
The grants can defray the cost of investments in real property and/or tangible personal property but cannot be used for maintenance or repair of existing equipment. The grants can be applied to replace old equipment if that leads to an increase in production.
The grants are limited to companies that make investments of at least $40,000 in the next 36 months. Applicants must have fewer than 250 full-time employees and be registered as a vendor in the Virginia Offshore Wind Supply Chain Partnership Directory at the time of application.
Applicants will have to maintain their local employment levels, as verified by the commonwealth, at the awarded location through the life of the grant. They must have a legal presence within Virginia for at least a year and be in good standing with the State Corporation Commission before applying.
VEDP will review the applications and conduct due diligence, while the Virginia Offshore Wind Supplier Development Grant Review Committee will meet every three months to review those applications and authorize grants.
“The Virginia Offshore Wind Supplier Development Grant will leverage the commonwealth’s existing offshore wind leadership position and advance our competitive advantage in emerging supply chains and technologies,” said Secretary of Commerce and Trade Caren Merrick. “This program invites Virginia manufacturers to diversify their portfolio to supply the industry, ultimately advancing our goal for the commonwealth to become the market leader in offshore wind technology, development and deployment.”
The U.S. Energy Information Administration on Tuesday forecast record-high amounts of electricity would be generated by burning natural gas this summer.
High demand for power was cited as a cause, along with low gas prices and power industry trends.
EIA said extensive use of air conditioning during hot weather is expected to raise demand for electricity.
Fuel prices are another driver, EIA said in its July Short-Term Energy Outlook, issued Tuesday. Electric utilities’ cost for coal was 9% higher in the second quarter of 2023 than in the same period in 2022, while natural gas was 66% lower. This gave them a nearly equal cost per million BTU.
As a result, EIA predicts 4% more electrical generation from natural gas in July and August 2023 than in the same two months of 2022.
EIA also predicts a 6% year-over-year increase in July and August in power generated by renewable sources, which are seeing rapid growth in installed capacity.
“This is an interesting time to monitor the United States’ electricity mix,” EIA Administrator Joe DeCarolis said in the news release. “As coal provides less and less power to the grid, we expect the contributions of natural gas and renewables in particular to increase.”
EIA said about 6,000 MW of new combined cycle natural gas turbine capacity and nearly 15,000 MW of wind and solar capacity have come online so far in 2023.
Other details from the July Short-Term Energy Outlook:
Natural gas is expected to account for 41% of U.S. power generation in 2023 and 40% in 2024, compared with 37% in 2021.
Coal is projected to drop from 23% in 2021 to 15% in 2024.
Renewables are expected to rise from 20% in 2021 to 25% in 2024.
As a result, U.S. carbon dioxide emissions are expected to decline from 4,964 billion metric tons last year to 4,789 this year and to 4,774 next year.
Nuclear holds steady around 19% to 20% in the four years of actual and projected data.
Wind power generation far exceeds solar, with installed wind capacity expected to reach 148.7 GW nationwide this year vs. 98.8 GW for solar.
Installed solar capacity is expanding much more quickly than wind: Year-over-year increases of 17.2%, 38.2% and 32.2% are recorded or projected for solar in 2022, 2023 and 2024, compared with 6.2%, 5.6% and 4.1% for wind.
California, Oregon and Washington have jointly applied for federal grant money to build a public charging network for electric trucks across the three states.
The proposed West Coast Truck Charging and Fueling Corridor Project would include 34 truck charging stations and five hydrogen fueling stations. The stations would be primarily along Interstate 5, with some locations on “key connecting corridors,” such as I-710 in the Los Angeles area.
Departments of transportation from California, Oregon and Washington, together with the California Energy Commission (CEC), applied for charging network funding last month from the U.S. DOT’s Charging and Fueling Infrastructure competitive grant program.
The plan was discussed during a joint CEC and California Department of Transportation (Caltrans) workshop. Caltrans declined to reveal the amount of grant funding requested, saying the proposal is under confidential review by the Federal Highway Administration.
The workshop also provided an update on California’s deployment plan for the National Electric Vehicle Infrastructure (NEVI) formula program.
‘Wild West’ of Connector Types
The goal of the $5 billion NEVI program is to establish a nationwide network of public EV chargers along designated alternative fuel corridors. California’s expected share of the funds is $384 million over five years.
One question that kept cropping up during the workshop was how California plans to handle the move toward North American Charging Standard (NACS) charging connectors.
Automakers including Ford, General Motors, Rivian and Volvo announced recently that they would adopt Tesla’s NACS connector as Tesla begins opening its Supercharger network to non-Tesla vehicles.
But federal NEVI guidance requires charging stations to be equipped with the rival combined charging system (CCS) connectors. Each station must have at least four CCS connectors that combined allow four vehicles to charge simultaneously.
That still leaves room for NACS connectors at ports that have more than one connector, according to Energy Commission Specialist Brian Fauble.
“As long as one of those connectors [is] CCS, the other connector can be any other connector, be it NACS, or CHAdeMO, or anything else,” Fauble said. “These other connectors can still be done, as long as you’re still meeting the port requirement of one CCS per port.”
Kentucky has added a requirement that charging stations funded through NEVI include NACS connectors in addition to CCS plugs, Reuters reported last week. Texas and Washington state might do the same.
California isn’t ready to follow suit, officials said during the workshop.
“It’s a little bit of a Wild West scenario right now with things changing so rapidly,” said Jim McKinney in CEC’s Fuels and Transportation Division. “We’re monitoring this and trying to decide how to proceed.”
McKinney said the NACS situation will not impact CEC’s initial NEVI solicitation, which is expected to go out during the third quarter of this year.
California divided its roughly 6,600 miles of alternative fuel corridors into segments that were then gathered into “corridor groups” and ranked by priority. (See Calif. Lays Groundwork for NEVI Solicitations.)
The state’s first NEVI solicitation will cover six corridor groups with 28 new stations and 291 ports.
Complementary Programs
The West Coast Truck Charging and Fueling Corridor Project would be “very complementary” to NEVI, Jimmy O’Dea, Caltrans’ assistant deputy director for transportation electrification, said during the workshop.
O’Dea said there are now only four publicly accessible truck charging stations across the West Coast.
“This would be a significant addition to the industry that we know is growing so rapidly,” he said.
Charging stations included in the project would each have at least five 350-kW dual-port chargers. Stations along I-710 would each have 10 chargers to serve drayage trucks working at the California seaports.
The stations would also support a megawatt charging system upgrade.
Each of the five hydrogen fueling stations would host two dispensers and have a 10,000-kg-per-day capacity.
Some commenters urged CEC to use a portion of NEVI funding for medium- and heavy-duty truck charging.
Sean Waters, vice president of compliance and regulatory affairs for Daimler Truck North America, said some of the NEVI-funded stations should be configured with a pull-through charging lane that could accommodate cars or large trucks.
While recharging at depots is common for trucks today, more fleets could be looking for public charging in the future due to high costs and infrastructure constraints of “behind-the-fence” charging equipment, Waters said in written comments to the CEC.
“Light-duty vehicles can utilize sites designed for medium- and heavy-duty vehicles, but the opposite is not possible,” Waters noted.
California Gov. Gavin Newsom (D) on Monday signed a $311 billion state budget and infrastructure bills aimed at building generation and transmission to ensure reliability as the state transitions to 100% clean energy.
The fiscal year 2023/24 budget retains 95% of last year’s $54 billion, five-year annual commitment for climate initiatives, including roughly $10 billion for electric vehicle infrastructure and incentives.
In his budget plan released in January, Newsom had proposed slashing $6 billion from climate commitment because of this year’s tax revenue shortfall, but he agreed with lawmakers to cut only $2.9 billion.
Negotiations with lawmakers also produced the five-bill infrastructure package that Newsom signed Monday.
The bills included Senate Bill 149, which will streamline judicial review of clean energy and transportation projects by requiring that challenges to the projects under the California Environmental Quality Act (CEQA) be resolved by the courts within 270 days, including appeals. (See Newsom Stresses Role of Permitting in Calif. Energy Transition.)
Another bill, SB 147, will allow the incidental taking of fully protected species under the state’s Endangered Species Act during the construction of infrastructure projects. It also declassifies the peregrine falcon, brown pelican and thicktail chub, a small fish, as protected species.
Environmental groups and some Democratic lawmakers opposed the measures, but Newsom said keeping the lights on and building out clean energy and transmission ought to take precedence over lengthy environmental reviews.
“We’ve got to move to build those projects, and we’ve got to remove some hurdles,” Newsom said. “I know there’s a purity of thinking … that we can live with rules and regulations that require nine years of processes to deliver the reliability that the people of the state deserve, but I just don’t see that from the prism of where I’m operating from.”
The last three summers, when the state struggled with blackouts and near misses, were “challenging,” he said.
Avoiding future repeats will require adding thousands of new megawatts annually, CAISO and the California Public Utilities Commission have said. In May, the CAISO Board of Governors passed its 2022/23 transmission plan, which calls for 45 projects totaling $7.3 billion to add 70 GW of new resources over the next 10 years.
“That’s exactly why this infrastructure package was so important,” Newsom said, thumping his lectern. “I want you to know that I have short-term confidence but long-term anxiety if we do not deliver on these large-scale utility” projects.
Newsom said he feels “a deep sense of urgency” about building out energy capacity. California needs to build faster, including to compete for billions of dollars in federal funding from the Inflation Reduction Act and programs.
“I don’t want to just come up here and lament about extreme heat, extreme droughts, extreme weather,” he said. “I want to actually deliver, not just on goals and ambition, but on projects. And so, I’m in a different mindset, sort of a hardheaded pragmatism. You know, let’s get moving.”
NYISO asked FERC last week to reject protests by state regulators and clean energy groups over the ISO’s proposal for integrating distributed energy resource aggregations into its markets, defending its call for a 10-kW minimum for participation (ER23-2040).
In June, NYISO proposed a 10-kW minimum capability for individual DER participation in aggregations, along with new metering and telemetry requirements for DERs. (See “DER Revisions,” NYISO CEO Delivers ‘State of the Grid’ to Management Committee.)
The ISO said the 10-kW minimum was needed to save staff time reviewing aggregations for interconnection and enabling it to integrate new software and procedures without significant hassle.
But the New York Public Service Commission, Advanced Energy Management Alliance and Advanced Energy United said the ISO’s proposals were unclear and ran afoul of FERC Order 2222 and that more time was needed to evaluate their impact.
In a joint protest, AEMA and AEU took exception to several of NYISO’s proposals, including limiting the ability to use a third-party meter service in homogeneous aggregations, eliminating bid-based and locational-based marginal price-based reference prices, and the transition mechanisms through which transmission operators will upgrade their system to allow DER aggregations.
The two organizations were most concerned about the proposed 10-kW minimum requirement, calling it “fundamentally at odds with FERC’s findings in Order No. 2222.”
“Other wholesale markets, such as ERCOT, have developed rules that allow residential scale participation,” they said. Despite pledging a “goal” to accommodate small DERs, NYISO’s “filing gives no commitment or timeframe to do so,” the groups said.
“Failing to allow such resources to provide wholesale services they are technically capable of providing absent an arbitrary and unjustified minimum capacity requirement is unjust and unreasonable and presents an undue barrier to market participation that will undermine competition and reliability to the detriment of customers,” they added.
The PSC was also concerned about the 10-kW proposal, saying in its protest that the requirement was “unduly restrictive and inconsistent with the directives of Order No. 2222.”
The ISO responded that it “has spent more than 15 months working with its stakeholders to develop the business practice manual provisions that detail how the DER and aggregation participation model will be implemented.”
While saying it was “sympathetic” to stakeholder concerns, the ISO said their proposed remedies would be administratively burdensome and could further delay the introduction of DER aggregations into its markets.
The ISO has requested FERC rule on its proposal by July 31, saying it hopes to implement DER aggregation as early as Aug. 1.
New Jersey Gov. Phil Murphy signed legislation Thursday that will allow the state’s first offshore wind project to benefit from federal tax credits.
Murphy signed the bill, A5651, in a press conference at a new factory built by German manufacturer EEW to build monopiles for use in the foundations of offshore wind turbines. The Senate and the General Assembly passed the bill 21-14 and 46-30, respectively, on June 30 in the last session before the legislature recessed for the summer. The legislature will not return until after the November elections.
Unlike other states, New Jersey doesn’t allow wind developers to receive the benefits of tax credits awarded under federal laws such as the Inflation Reduction Act. Instead, the state receives the benefits for use to help ratepayers.
The new law allows the state’s first OSW project, Ocean Wind 1, to receive the tax credit benefits, but it does not allow other wind projects in the state to get the same benefits. (See NJ Lawmakers Back Ørsted’s Tax Credit Plea.)
Murphy hailed the bill as “absolutely critical to moving our entire offshore wind industry forward and cementing our leadership in this new industry.”
“I cannot emphasize this enough: We have a once-in-a-generation opportunity right now to bring tens of thousands of overwhelmingly union jobs and billions of dollars of investment to our state with offshore wind,” he said at the conference at the Port of Paulsboro, flanked by massive monopiles under preparation for eventual use in the foundations of a wind turbine. He said they were the first ever monopiles built on U.S. soil.
“New Jersey is literally building the foundation for our nation’s entire wind industry, and this bill will allow these projects to expand and create even more jobs,” he said.
The New Jersey Board of Public Utilities approved Ocean Wind 1, from Danish developer Ørsted, in 2019. The BPU also has approved the 1,148-MW Ocean Wind 2 and 1,510-MW Atlantic Shores. The state’s third solicitation, launched by the BPU in March, could result in the award of capacity totaling 4 GW or more. (See NJ Opens Third OSW Solicitation Seeking 4 GW+.)
A think-tank report published June 5 on the state’s rapidly growing OSW sector said the construction of a second phase of the EEW factory was “more than a year behind schedule” because of funding issues, in large part because Ørsted could not access the federal tax credits. Speaking before the legislature’s votes last month, the developer said federal tax credits were intended to advance industry development. The company said it already has invested $160 million in the EEW factory and “is poised to increase this investment.” (See NJ OSW Projects Face Public Funding Scrutiny.)
After the bill was passed, Atlantic Shores CEO Joris Veldhoven said in a statement that the approval “reaffirms the state’s commitment to offshore wind” and called on it to enact an “industry-wide solution, one that stabilizes all current projects including Atlantic Shores … the largest offshore wind project in the state of New Jersey.”
“We need immediate action that also supports the Atlantic Shores project,” he said.
Budget Signed, but Other Bills Remain
The OSW tax credit bill was one of several clean energy-related bills advanced by the legislature on June 30.
Murphy also last week signed a bill, S2024, that enacts a $54.3 billion state budget that includes a $40 million Green Fund that the governor said would “leverage both private capital and federal funds.” The governor announced the fund in February but since has said little about it; nor has the New Jersey Economic Development Authority (EDA), which will administer it. Murphy’s budget book at that time said the fund was designed to “attract up to $280 million in private capital to advance projects to advance the state’s new and bold environmental goals.” (See NJ Launches $80M Clean Energy Loan Fund for Small Business.)
The signed budget also contains an additional $10 million “to support the continued installation of EV charging infrastructure throughout the state,” according to a statement put out by Murphy’s office.
The legislature also sent to Murphy a bill, S3044, that would put in place the funding for the first year of a three-year, $45-million pilot program enacted in 2022 that will be the state’s most aggressive move into replacing diesel buses with electric-powered buses. The bill passed the Assembly with a 49-27 vote and the Senate by 26-9.
The 2022 bill, A1282, required the New Jersey Department of Environmental Protection (DEP) to create a program under which six districts or contractors each year would take students to school with electric buses to assess the reliability and effectiveness of using them in place of diesel-powered vehicles. The performance of the buses would be evaluated on factors such as costs, maintenance, fuel use and speed, and data would be collected and submitted to the DEP. (See Electric School Bus Pilot Awaits NJ Governor’s Signature.)
In a less divisive vote, the Senate on June 30 passed 37-0 a bill, S427, that would provide corporate business tax credits to incentivize building owners to retrofit their warehouses to be solar ready. The bill now is before the Assembly Environment and Solid Waste Committee.
Buildings must be at least 100,000 square feet in size and create a “solar-ready zone” that accounts for at least 40% of the space. The credit, which would be available once solar panels are installed on the roof, would be at maximum the lesser of two options: 50% of the cost incurred in retrofitting the building for solar or $250,000.
The Senate also voted 27-13 to pass a bill, S2185, that would require the BPU to develop a pilot program to provide incentives to developers and others that install energy storage systems, and then create regulations for a permanent program. The program would seek to help develop a range of storage, from customer-sited energy storage systems to larger systems connected to the grid. (See Clean Energy Bills Stack up in NJ Legislature.) The bill now will be heard by the Assembly Appropriations Committee.
The Assembly advanced a bill, A5442, that would direct the BPU to study how best to market and promote large-scale geothermal heat pump systems and look at the feasibility and benefits of mounting such a campaign. After the 76-1 vote, the bill now is before the Senate Environment and Energy Committee.
Ohio lawmakers are raising concerns about how Illinois’ Climate and Equitable Jobs Act (CEJA) will impact their state’s ratepayers after PJM last year found that power plant retirements stemming from the law could require $2 billion in new transmission to maintain reliability.
Ohio House Public Utilities Committee Chair Dick Stein (R) and Senate Energy and Utility Committee Chair Bill Reineke (R), along with 10 other colleagues, sent a letter to PJM’s Board of Managers last month saying that while the RTO’s markets have done well for the state in the past, they were worried that could be changing.
“We are becoming increasingly concerned that the actions of PJM, FERC and other PJM states may jeopardize the successful, competitive market model that Ohio has nurtured,” the letter said. “We appreciate that PJM has brought concerns related to generation retirements and looming reliability challenges to our attention. Needless to say, we are quite concerned about reports that the PJM region is on the precipice of power shortages that could lead to blackouts for our consumers that need electricity.” (See PJM Chief: Retirements Need to Slow down.)
The legislators said those looming reliability issues are exacerbated by CEJA provisions that mandate closure of fossil fuel plants, which requires the phaseout of coal and natural gas units by specified dates starting in 2030, with the last plants to shut down in 2045. The law requires the Illinois government to collaborate with PJM and MISO starting in 2025 to analyze the impact of its provisions on reliability.
PJM has released a “very initial snapshot” of what the retirements could mean, including increased east-to-west power flows and up to $2 billion in transmission upgrades. That analysis did not include any of the new generation that CEJA incentives are expected to bring online. (See Illinois Climate Bill Could Force $2B in Tx Upgrades, PJM Says.)
A table from PJM showing the RTO’s initial estimates of what transmission upgrades might be required to reliably retire the power plants in Illinois impacted by CEJA. | PJM
Stein met with PJM after sending the letter, to which the RTO said in a statement it would formally respond soon.
“The loss of affordable and reliable coal and oil energy generation and the implementation of 100% renewables could potentially put a strain on the energy grid,” Stein said in a statement after the meeting. “Ohioans should not be burdened by cost increases that are caused by the policy choices of other states.”
The $2 billion is very preliminary, and now is the time for PJM, and the experts on the grid that it employs, to look into the issue more formally, former Illinois Commerce Commissioner Erin O’Connell Diaz said in an interview.
“It’s appropriate that the legislators of Ohio are concerned about it because there are a lot of costs that can flow out of different types of legislation,” said O’Connell-Diaz, who now runs consulting company FutureFWD.
While plant retirements generally create some new transmission costs, she said, ratepayers in Illinois and other states with similar clean energy policies are going to be paying to bring on clean energy, which will produce cheap power for the grid that Ohio will benefit from in the form of lower prices. The RTOs can quantify those kinds of benefits going forward as well, she said.
‘Shark-infested Waters’
The Natural Resources Defense Council supported CEJA, as it has similar laws in other states. Tom Rutigliano, of NRDC’s Sustainable FERC Project, argued that the Ohio legislators were mostly concerned about attacking renewables, but he also called for more coordination from the RTO.
“This letter is more focused on partisan, anti-renewable jabs than meaningful transmission or reliability solutions,” Rutigliano said in a statement. “Ohio officials’ efforts would be better directed toward following Illinois’s lead and working on collaborative, forward-looking reliability solutions, rather than attempting to close off their borders to clean, affordable energy. The request for further studies from PJM would be a distraction from what is needed to support a successful energy transition. Ultimately, this letter is a reminder that states need clear leadership, proactive planning and coordination from PJM.”
Former FERC Commissioner Tony Clark, a senior adviser at Wilkinson Barker Knauer, said such disputes among states have regularly come up and are likely to continue, especially in regions like PJM with varying energy policies. It is not ultimately feasible to isolate the impact of one state’s policies in regional markets, whether it is generation or (outside of the State Agreement Approach) transmission, he said.
“FERC has to allocate those costs based on court precedent with cost-causers and cost-payers being ‘roughly commensurate,’” Clark said. He said PJM’s strong minimum offer price rule (MOPR) represented “an attempt to try to isolate some of those costs, but the commission has backed off from that in recent years. It is, I think, taking a path where effectively the capacity markets are likely to wither a bit in terms of their revenue streams, and they seem to be more focused on trying to get more and more out of the energy and ancillary service markets. But even in those, you’re going to have spillover effects from any sort of market [or] public policy intervention in one state; it’s very hard to isolate it from others in an integrated market.”
If FERC had tried to keep the MOPR in place, states with strong clean energy policies would have pulled out of PJM and other markets, which put the federal regulator in a no-win situation in terms of market integrity, he added.
PJM states have been at odds over other issues in the past. A dispute over cost allocation more than a decade ago led to the “roughly commensurate” court precedent Clark cited. O’Connell-Diaz said she hoped for compromise on the dispute because any litigation would take years to resolve, and the industry needs to be focused on the reliable transition to a cleaner grid.
“But again, you put the overlay of the politics on it, and it’s shark-infested waters, isn’t it?” O’Connell-Diaz said. “And so, again, I go back to we really need to kind of wipe that away. You know, utility regulatory bodies should really have to be above all that that pressure. They need to be able to think clearly without any kind of political connotations.”
However, that is not an easy thing to do today, she added.
Former BOEM Director Amanda Lefton will lead RWE’s offshore wind development effort on the East Coast.
RWE announced the appointment Monday. The move will place her in charge of one of the largest projects of its kind in the United States: Community Offshore Wind, a collaboration with National Grid Ventures that has a potential output of over 3 GW.
Lefton was appointed director of the U.S. Bureau of Ocean Energy Management in early 2021, shortly after President Biden’s inauguration. She previously was first assistant secretary for energy and the environment for New York, a role that placed her at the center of that state’s climate protection efforts.
In January 2023, Lefton resigned as BOEM chief to become senior policy director of energy and climate at law firm Foley Hoag. Elizabeth Klein was named BOEM director upon Lefton’s departure.
As measured by installed capacity, RWE is the world’s second-largest offshore wind developer, behind Ørsted. All 19 of the facilities RWE now operates are outside U.S. waters, but it is working to develop wind farms off the east and west coasts of the United States.
In early 2022, RWE and National Grid Ventures successfully bid $1.1 billion for lease area OCS-A 0539, which is south of New York and east of New Jersey in the New York Bight. Expected operation date is 2030 for what the partners now call Community Offshore Wind.
In late 2022, RWE won a BOEM lease 28 miles off the coast of California with a $158 million bid that will allow it to develop up to 1.6 GW of floating wind. It projects completion sometime in the mid-2030s.
Community Offshore Wind is now awaiting word on whether it will be awarded a contract in New York’s 2022 offshore wind solicitation. The partners submitted multiple versions of their plan with a variety of price tags and power output ratings. As specified in the solicitation, they outlined ways they would help New York build an offshore wind industry.
RWE has previously developed onshore wind projects in New York state.
Lefton led BOEM at a critical time for the U.S. offshore wind sector, as President Biden set a 2030 goal of 30 GW of capacity and backed up the vision with policy. Installed capacity in U.S. waters was just 42 MW at that point, however, and there was little onshore infrastructure or domestic supply chain to support a radical expansion.
During her two years at BOEM’s helm, the agency greenlighted the nation’s first two utility-scale offshore wind projects, held three lease auctions, began review of 10 projects and advanced exploration of the Oregon and Central Atlantic coasts, the Gulf of Maine and the Gulf of Mexico for potential offshore wind development.
RWE in a news release Monday lauded Lefton’s stakeholder collaboration and all-of-government approach toward clearing the many obstacles to offshore development. Lefton in turn lauded RWE’s conception-to-completion track record in project development.
When she left BOEM for the private sector in January, the Department of Interior’s chief of staff said: “BOEM is at the epicenter of the Department’s work to create good-paying union jobs in the offshore energy sector, support a reliable domestic supply chain and meet the moment for a clean energy economy. Amanda has been a driving force of this effort, and we are grateful for her vision, commitment and service to this country.”
Sam Eaton, CEO of RWE Offshore Wind Holdings, made a similar point Monday: “Amanda has successfully created significant momentum for the offshore wind industry in the U.S. Her know-how navigating all levels of government has resulted in the approval and now construction of the nation’s first two offshore wind projects.”
The Department of Energy on Thursday announced the latest recipients of federal grant money intended to modernize the U.S. power grid against natural disasters caused by climate change, awarding $207.6 million to nine states and three tribal nations.
The grants are part of the $5 billion allocated to grid-hardening projects under the bipartisan Infrastructure Investment and Jobs Act (IIJA), which passed in 2021. Half of the spending is earmarked for state, territory, and tribal governments, to be distributed over the next five years. (See Bipartisan Infrastructure Bill Offers Funding for Grid, EVs.)
The nine states and three tribes announced on Thursday comprise the third cohort of recipients to be unveiled since the grants began earlier this year. Applications for the 2022 and 2023 fiscal years closed May 31 for state and territory governments; tribal governments have until Aug. 31 to submit their applications for the year.
Among the states included in Thursday’s announcement were California and Texas, the largest beneficiaries under the program so far with $67.5 million and $60.6 million awarded respectively. According to their fact sheets, California’s goals for the funding include reducing the frequency and duration of power outages in the state, advancing California’s clean energy goals and creating clean-energy jobs. Texas plans to use the money to identify gaps in grid resilience and improve weather-related resilience in critical infrastructure facilities.
Other recipients include:
Kansas — $13.3 million;
Kentucky — $11.1 million;
Maine — $4.4 million;
Michigan — $14.9 million;
Minnesota — $11.9 million;
Oregon — $19.9 million; and
Rhode Island — $3.4 million.
In addition, three Native American tribes — the Metlakatla Indian Community and the Native Village of Eagle in Alaska, and the Standing Rock Sioux Tribe of North and South Dakota — will receive a total of $622,000.
In all, the program has chosen 20 states, eight tribes, and the District of Columbia to receive $324 million so far this year. Eligibility is decided based on five factors: population, area, probability of disruptive events, severity of events and expenditure on mitigation efforts.
State and tribal governments must provide a 15% match to the federal allocation; entities receiving sub-awards from the grant recipient generally must provide a 100% match, although smaller utilities may match as little as one-third.
“Renewable energy has helped many parts of the country withstand a crippling heat dome, and the [administration’s] agenda will increase the amount of clean power sources available on the nation’s grid,” said Energy Secretary Jennifer Granholm. “DOE is excited to announce a continued stream of funding aimed at strengthening America’s workforce and preparing the nation for a more resilient, clean energy future. These grants will help modernize the electric grid to reduce impacts of extreme weather and natural disasters while enhancing power sector reliability.”
DOE’s resilience investments form just part of the expenditures planned for the U.S. grid under the IIJA. The Biden administration plans to invest more than $15 billion under its Building a Better Grid initiative launched last year, including the grid resilience program, a $2.5 billion program to upgrade transmission lines, the $10.5 billion Grid Resilience and Innovation Partnerships program to support national resilience projects and the $760 million Transmission Siting and Economic Development Grants program. (See DOE Opens Applications for $6B in Grid Funding.)
FERC on Friday approved a new settlement with BP America over allegations that it manipulated interstate natural gas prices in 2008 after an appeals court found the regulator exceeded its authority in an earlier penalty order (IN13-15).
BP agreed to pay a $10.75 million civil penalty and will not seek the return of an additional $250,295 in disgorgement that it had already paid. Initially, FERC had assessed a civil penalty of $20.16 million, which the firm appealed to the 5th U.S. Circuit Court of Appeals.
The firm already paid that earlier fine, plus interest, under protest, so the deal effectively means FERC will not oppose BP seeking to reclaim $13.6 million through a suit in the U.S. Court of Federal Claims, or any other forum with jurisdiction.
The case involved natural gas prices in the Houston Ship Channel in the days following Hurricane Ike in 2008, when BP allegedly traded next-day, fixed-price natural gas to artificially depress them to benefit positions it held.
The 5th Circuit found in a decision in October that some of the transactions FERC was seeking fines for were intrastate trades, over which the court said it does not have jurisdiction. The new order limits the fines to the 18 transactions the court said were under FERC’s authority to regulate.
FERC affirmed its finding that BP engaged in market manipulation but limited that finding pursuant to the court’s order. The commission had argued that it was able to seek fines on any natural gas transaction, including intrastate gas deals, that affects the prices it regulates under the Natural Gas Act, but the court rejected that claim.
“The commission cannot exercise its jurisdiction merely because a manipulative scheme may affect the prices of interstate natural gas trades,” the court said.
BP stipulated to the facts set forth in the deal and acknowledged that the 5th Circuit upheld FERC’s findings of manipulation when it came to the 18 jurisdictional transactions.
FERC’s Office of Enforcement started investigating BP after Ike during the period of Sept. 18 to Nov. 30, 2008, when it sought to determine whether the firm’s trades were intentionally trying to depress Platts’ Gas Daily index prices at the Houston Ship Channel to benefit bigger, financial spread positions BP held that settled off index prices.
The index positions BP held paid off when Houston Ship Channel natural gas was lower than the Henry Hub prices in Louisiana, which was the case when Ike hit and caused prices to plunge. Then the firm “engaged in a glut of physical sales” at the ship channel to keep the index profits rolling in for weeks after the hurricane hit, the court said.
