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November 1, 2024

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Draft Plan Outlines California Vision for Offshore Wind

The California Energy Commission on Jan. 19 released a draft plan for offshore wind development, adding to the rapidly growing body of work identifying wind power as crucial to achieving state and national clean energy goals.

The plan was developed in accordance with AB 525, the 2022 bill that directed the commission to develop the strategic plan in collaboration with several other state agencies and established a goal of deploying 2 to 5 GW of offshore wind by 2030 and 25 GW by 2045 in California — powering 25 million homes and providing about 13% of the state’s supply. The draft plan also says the U.S. is on the path to deploy 110 GW by 2050.

“On the floating offshore wind side, there is no plan in the country — maybe the world — as comprehensive as this one,” Adam Stern, executive director of Offshore Wind California, told NetZero Insider.

Development of offshore wind infrastructure will occur primarily in federal waters under the jurisdiction of the Department of the Interior’s Bureau of Ocean Energy Management (BOEM). The agency held its first auction for wind power commercial leases in December 2022, which resulted in lease awards to five developers for parcels off California’s North and Central coasts. The winning bids for the lease areas total more than $757 million and include a commitment of more than $50 million to support communities and ocean users through community benefit agreements. (See First West Coast Offshore Wind Auction Fetches $757M.)

Challenges

But amid the progress, challenges remain. Waters off the coast of California are deeper than those in the Atlantic, requiring the installation of floating wind turbines rather than the more common fixed structures, which are suitable for waters about 200 or fewer feet deep. Floating platforms require more infrastructure, including suspended electrical cables linking the turbines, mooring cables and anchors attaching the turbines to the sea floor, with an electrical cable to transport the energy to a substation.

California’s coast is also less populated than the East and will require development and upgrades to ports and waterfront facilities to support offshore wind power, the report says, including construction of floating platforms, manufacturing and storage of components, and long-term operations and maintenance.

“Existing California port infrastructure is unable to support an offshore wind industry in the state,” the plan says. “As it will take a decade to make the needed port improvements that can support the full offshore wind supply chain, the state may need to import components from other parts of the world to meet the state’s 2030 offshore wind planning goals.”

New transmission also will be needed.

“The electric system on the North Coast is relatively isolated from the larger California grid and serves primarily local communities, so additional transmission infrastructure will be needed in this region. Existing transmission on the South-Central Coast is robust; however, there is still a need for long-term planning,” the plan says.

Stacey Shepard, senior information officer at CEC, told NetZero Insider in an email that permitting among local, state and federal agencies is perhaps the largest challenge offshore wind deployment faces.

“Coordination will be critical, but California has successfully coordinated multiple local, state and federal agencies to deploy clean and renewable energy facilities on state lands,” Shepard said.

Benefits

The plan cites several studies that estimate high potential economic and workforce benefits from offshore wind. For example, a Catalyst Environmental Solutions study estimated that a $124 million investment at the Port of Humboldt, a $20 million training center and workforce development, would create 500 annual short-term jobs by 2030 and 14,000 annual long-term jobs by 2045. The study projects that offshore development would generate upward of $5 billion in state-level gross domestic product by 2045, in addition to $1.2 billion in labor income and $385 million in fiscal revenue.

Another study by the Natural Resources Defense Council and Environmental Entrepreneurs estimated that 10 GW of offshore wind development in the Morro Bay and Humboldt areas could create more than 169,000 jobs and more than $45 billion in short-term economic benefits to the state.

Impacts

To better understand the potential impacts associated with offshore wind, the CEC conducted outreach to neighboring communities and tribal nations.

“While permitting agencies and developers have extensive experience with development and operation of various types of onshore and nearshore facilities, including deep water oil and gas platforms, there is a great deal of uncertainty about the impacts from large-scale floating offshore wind facilities anchored more than 20 miles off California’s coast,” the report states.

The plan lays out a detailed analysis of potential impacts associated with the Morro Bay and Humboldt lease areas, which could include habitat displacement of marine animals and birds and entanglement of species in underwater gear. To address some of these challenges, the CEC suggests burying underwater cables, avoiding important habitat and conducting regular monitoring.

AB 525 also directed the CEC to create a strategic plan identifying impacts to Indigenous groups and offering potential solutions. Tribes consulted were concerned with several potential issues associated with offshore wind development, including the perpetuation of resource extraction in their traditional territories that lack benefits to their communities, potential violence associated with the influx of non-local workers, the impact on sacred and historical sites, and more. Suggested strategies included exploring public safety measures to reduce violent crime and sexual and gender-based violence against California tribes and other vulnerable populations, and collaborating on avoidance, mitigation and co-management opportunities.

A framework for identifying suitable sea space was also outlined in the plan, which involves spatial mapping in federal waters from about three miles offshore to the 200-mile federal boundary. So far, the CEC has identified six locations for further screening — five off the North coast and one off the South-Central coast.

The draft strategic plan will be presented at a future public workshop.

“The CEC and collaborating state agencies are proud of the progress to date but appreciates there is much more work to be done,” Shepard said.

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DOE Adopts Modest Upgrade in Stove Efficiency Standards

The U.S. Department of Energy has finalized new efficiency standards for residential cooking appliances, ushering in modest increases that will take effect in January 2028. 

In its announcement Jan. 29, DOE said the changes will save consumers $1.6 billion on their utility bills over 30 years. 

But DOE also said the improvements it’s ordering are modest and will pertain to only a small percentage of cooktops and stoves manufactured. It said 97% of gas models and 77% of smooth-top electric stove models now on the market already meet the new standards. 

The cooking equipment standards are part of a larger push by the Biden administration for energy efficiency standards it estimates will yield nearly $1 trillion in consumer savings over 30 years. 

Partisan and corporate priorities would make any such package of changes contentious, but the proposed new rules on cooking equipment published by DOE in February 2023 became a cause celebre, with conservative firebrands pouncing on a supposed gas stove ban. 

The blowback was such that DOE in May 2023 published a knockdown piece that read in part: “Claims that the federal government is banning gas stoves are absurd.” 

The lingering effects of that kerfuffle can be seen in the wording of the announcement, in which DOE emphasizes that the new standards were mandated by Congress and drawn up in negotiations with stakeholders including utilities, states and advocates for consumers, appliance makers and the environment. 

DOE also points out the new rules will not bar features desired by consumers such as continuous cast iron grates, high-input-rate burners and other specialty burners. 

The efficiency standards for gas cooktops were watered down significantly during negotiations. DOE first proposed a limit of 1.2 million BTUs per year, but the final rule sets a limit of 1.77 million BTUs. 

Spread over 30 years across the 143 million existing U.S. housing units, the $1.6 billion in projected savings works out to about 37 cents a year. 

The Association of Home Appliance Manufacturers was one of the stakeholders that helped negotiate the new rule. It said Jan. 29: “This standard is a win for consumers and energy savings. Manufacturers will have the flexibility they need to continue offering the features and performance that consumers value in gas and electric cooking products.”  

Another of the stakeholders, the Appliance Standards Awareness Project, said the value of the negotiated recommendations is not so much for cooking appliances but in the entire package of appliance standards that was negotiated, including washers, dryers, dishwashers, refrigerators, freezers and beverage coolers. Executive Director Andrew deLaski said the effect of the announcement will be seen primarily in electric cooking equipment. 

“The main thing this does is ensure new smooth-top electric stoves don’t waste energy when they’re not even operating,” he said in a news release. “It’s a modest money saver for consumers, with changes that would be challenging to even notice. There was disagreement over this stoves rule last year, but then the stakeholders came together and resolved it.” 

He added: “It’s the whole suite of dozens of updated product standards the department is working on that will deliver the big impact, reducing people’s costs and protecting the climate.” 

DOE in late December adopted new residential refrigeration standards that will take effect in 2029 and 2030, with $36.4 billion in consumer savings over 30 years. Proposed commercial refrigeration standards would save businesses $56 billion over 30 years. 

U.S. Secretary of Energy Jennifer Granholm said her agency is continuing the initiative: “DOE is dedicated to working together with our industry partners and stakeholders throughout 2024 to continue strengthening appliance standards, addressing a backlog of congressionally mandated energy efficiency actions that is delaying a projected $1 trillion in consumer savings from reaching the American people.”  

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FERC Approves NYISO Waiver on Interconnection Study Requirements

FERC on Jan. 25 granted NYISO a waiver allowing a temporary suspension of tariff rules for its interconnection study processes to assist developers and facilitate a smoother transition to the procedures prescribed by Order 2023 (ER24-342).

NYISO has been working to implement the commission’s order, which seeks to unclog the nation’s interconnection queues. It submitted a partial compliance filing in November and was granted an extension to April 3 to submit its full proposal. (See NYISO Stakeholders Question Proposed Interconnection Timelines, Deposit Rules.) In the meantime, developers under the ISO’s current tariff rules face mandatory feasibility and system impact studies for their queued projects at their own expense.

To address this, NYISO proposed in its waiver request to establish a set of limited interim rules for its large facility interconnection procedures (LFIP) that would allow developers to choose between completing ongoing studies, opting for limited studies, withdrawing without penalty or not starting studies at all. The ISO argued that these proposed rules would “minimize the expense, time and resources” needed to advance studies in the interconnection queue.

NYISO’s current LFIP require developers to undergo three successive studies: an optional feasibility study that evaluates a project’s configuration and local system impacts; a system impact study that evaluates a project’s impact on transfer capability and system reliability; and a class year facilities study that evaluates the cumulative impact of a group of projects.

Now developers can either remain in the interconnection queue or withdraw their requests, thereby avoiding unnecessary costs until the new procedures take effect. However, they must make their decision within 30 calendar days following FERC’s order.

The commission said the waiver was “limited in scope,” remedies a “concrete problem” and would not “have undesirable consequences.”

NYISO has nearly 530 projects in its interconnection queue, and nearly all of them are renewable projects, according to an S&P Global analysis.

The waiver is effective beginning retroactively from Nov. 30 until FERC rules on the ISO’s partial compliance filing. The commission noted that it made “no findings as to the merits of NYISO’s partial compliance filing at this time.”

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PJM: Grid Performed Well During January Winter Storm

PJM last week said the grid maintained reliability through nearly a week of harsh winter conditions during the winter storm that blanketed much of the nation during mid-January. 

Dave Souder, PJM executive director of system operations, told the Jan. 24 meeting of the Markets and Reliability Committee that the grid was at its most strained Jan. 17, which saw a peak load of 134,777 MW and some emergency procedures implemented to mitigate transmission constraints. Cold weather alerts were in place from Jan. 14-17 and Jan. 19-22. 

Comparisons to December 2022’s Winter Storm Elliott dominated the discussion, with PJM making the case that several market and operational improvements bolstered performance. Souder said the RTO drew on its experience with generation performance during cold weather to take more action before the storm arrived. Dispatchers manually committed thousands of additional megawatts through the day-ahead market to give long-lead units time to come online and combustion turbines that have had trouble procuring gas in the past additional notice to firm up their fuel. 

Conservative operations were in place between Jan. 13 and 17 to provide dispatchers with greater flexibility to keep long-lead resources online when they’d otherwise be released on economics. 

“We took a risk-based unit commitment approach,” Souder said. 

PJM’s Brian Chmielewski said transmission congestion also peaked on Jan. 17, with 19 constraints reaching the $2,000/MWh transmission constraint penalty factor (TCPF). Heavy load interchange and congestion drove system marginal prices to the $500/MWh range Jan. 17 and 18. 

Vitol Vice President of Regulatory Affairs Jason Barker questioned if price spikes on the mornings of Jan. 16, 17 and 18 were driven by PJM load or exports to neighboring regions, saying that the timing appears to align with the MISO morning peak. PJM representatives were unable to confirm the observation, but agreed to examine event data.

Souder said additional information will be presented at next month’s Market Implementation and Operating committee meetings, scheduled for Feb. 7 and 8, respectively. 

The rate of generation outages was around a third of the peak during Elliott at 16,119 MW offline Jan. 16 versus 46,124 MW on forced outage Dec. 24, 2022. Souder said the gas fleet’s performance in particular was much stronger this month; though pipeline capacity restrictions were in place throughout the storm, there were few compressor station or gas well failures, and pipeline operators coordinated with PJM to improve forecasting. 

Generators that did experience disruptions impacting their output also made use of PJM’s newly implemented temporary exception process to report their diminished output. One of the challenges PJM highlighted following Elliott was a significant number of generators not reporting issues to the RTO until dispatchers attempted to bring them online. 

Independent Market Monitor Joe Bowring told RTO Insider that PJM took a “very conservative” approach to the storm and relied on a forecast that turned out to be much more accurate than that for Elliott. While he applauded the performance of PJM operators in keeping the grid online through their actions, he said that a stronger market design would commit generators based on economics. 

“The operators made the system work, and we’re happy they did, but when we think of the bigger picture, markets were not relied on,” he said. 

He argued that the need to manually commit resources during the storm highlighted the need for ongoing stakeholder discussions over the reserve market design to focus on how to include market parameters that reflect a need for short-term reserves. He contrasted the need for reserves that can operate through a storm lasting a few days to the decision to increase the synchronized reserve requirement by 30% last May. (See “Stakeholders Reject PJM Synch Reserve Manual Change; RTO Overrides,” PJM MRC/MC Briefs: May 31, 2023.) 

“You don’t need more reserves year-round; you needed them for a couple days last week,” he said. 

Several stakeholders questioned the cost of $28 million in uplift payments to generators committed under conservative operations, arguing that costs should be built into the market, while others said the current market structure provides dispatchers with flexibility to commit units as they may be needed in real time. 

Gregory Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), said that both uplift payments and exports during strained conditions are worrying, but in this instance PJM’s actions appear to be warranted because of the concern that generators wouldn’t be able to perform during a holiday weekend winter storm — the same scenario PJM found itself in during Elliott. In this case, the holiday was Martin Luther King Jr. Day, instead of Christmas in 2022. 

The storm brought a new record-high peak load of 34,524 MW in the Tennessee Valley Authority region Jan. 17, and other PJM neighbors also saw high loads, leading the RTO to export 12,131 MW, the equivalent of nearly 10% of its own load. 

Gregory Carmean, executive director of the Organization of PJM States Inc. (OPSI), questioned whether the large amount of exports signal that other regions are leaning on the RTO for reliability at the same time that it has been recommending reducing projected reliability benefit of imports reflected in the capacity benefit of ties (CBOT) value. The package of market changes PJM proposed in the Critical Issue Fast Path process last year would have set the CBOT to zero, but the Board of Managers did not include that component in its proposal now pending before FERC. (See PJM Board Releases Outline of Capacity Market Changes.) 

Noting that the drop in temperatures was most severe in the ComEd zone, AEP Energy Director of RTO Operations Brock Ondayko said more detailed analysis on generation outages by zone could provide more information about any incremental improvements made in generator performance in subzero temperatures. 

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New York PSC Seeks Rehearing of RTO Adder for Offshore Tx Project

The New York Public Service Commission on Jan. 25 requested a rehearing of FERC’s December order granting a 50-basis-point RTO participation adder for the Propel NY Energy transmission project (ER24-232).

Propel — a $2.7 billion, 345-kV joint venture between New York Transco and the New York Power Authority — was selected from NYISO’s public policy transmission needs (PPTN) assessment to deliver at least 3,000 MW from offshore wind farms near the Long Island coast.

NY Transco petitioned FERC for transmission incentives, including a cost-containment mechanism, a base return on equity of 10.7% with a 150-basis-point risk adder, 100% coverage for abandoned plant and construction work in progress, and a 50-basis-point RTO participation adder. The commission approved these requests, but it reduced the risk incentive to 75 basis points and suspended the proposed base ROE pending hearing and settlement judge procedures. (See FERC Approves Incentives for NY OSW Transmission.)

However, the PSC said in its protest that the RTO adder is “neither necessary nor warranted” and “harms New York consumers” who will be “required to overpay to encourage a voluntary conduct on the part of the developer where the conduct sought to be incentivized is already required.”

FERC granted the adder with the condition that the developer continue its “membership in NYISO and transfer … operational control of the project to NYISO once it has been placed in service.”

But the PSC argued that the adder, typically used to incentivize voluntary participation, is redundant for Propel NY, as NY Transco’s involvement with NYISO is a regulatory requirement, not a discretionary choice. The adder “gives the developer an unjustified windfall while unnecessarily increasing costs to New Yorkers,” it said.

To support its position, the PSC cited FERC’s ruling last month that Pacific Gas and Electric was not eligible for an RTO adder in CAISO (ER24-96). (See Citing California Law, FERC Rejects PG&E Request for RTO Adder.) It said the two cases “are analogous.”

The PSC, along with New York City and Multiple Intervenors, had opposed NY Transco’s requested ROE and incentives. They complained that the 10.7% ROE was inflated and argued that NY Transco failed to demonstrate any special project risks.

The first settlement conference over the ROE is scheduled for Jan. 31.

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Virginia State Corporation Commission Finally Gets All Seats Filled

The Virginia State Corporation Commission (SCC) has a full complement of commissioners after the Virginia General Assembly approved two new members last week.

The legislature picked Kelsey Bagot, a former staffer of FERC Commissioner Mark Christie who was working at NextEra Energy, and Sam Towell, who is associate general counsel for Smithfield Foods and previously worked for the state attorney general.

“Kelsey is an excellent choice by the Virginia General Assembly for the State Corporation Commission,” Christie said in an interview Jan. 26. “As a former commissioner on the State Corporation Commission, I know that Kelsey brings exactly the qualities and the dedication to serving the public that the Virginia Commission needs and that the people of Virginia deserve.”

The two new members join Jehmal Hudson, who has been the only member of the state regulator since former Chair Judith Jagdmann stepped down in 2022.

The issues with staffing the SCC go back to when Jimmy Dimitri stepped down in 2018 and the legislature failed to find a long-term replacement for him. Dimitri has, however, been able to come back and help move needed business with Hudson in recent months because the body requires two votes for a quorum. The general assembly, which has seen its chambers flip between Republicans and Democrats multiple times in recent years, likewise had been unable to find a long-term replacement for Christie, who served on the SCC for nearly 17 years before joining FERC in 2020.

“I’m very, very happy that finally, after three years, all three seats are filled with permanent appointments, permanent elections, and they’re all three quality people,” Christie said. “The State Corporation Commission of Virginia is the most important state agency in Virginia that most people have never heard of.”

The SCC oversees energy, as well as large swaths of the state economy, including all insurance (it helps set up the state marketplace for health insurance under Obamacare), banking, securities, retail franchises and railroads. It also is the state’s central filing office for corporations, limited partnerships and LLCs.

“I think it’s the outstanding regulatory agency in America at the state level, based on the history and based on the broad jurisdiction,” Christie said.

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CAISO Considers Replacement of RA Incentive Program

CAISO staff and stakeholders are looking to re-evaluate the ISO’s Resource Adequacy Availability Incentive Mechanism (RAAIM) and explore whether it should be replaced with a new program relying on an unforced capacity (UCAP) construct to ensure sufficient RA capacity.  

Moderating a Jan. 16 meeting of the ISO’s Resource Adequacy Design and Modeling Working Group, Jeff McDonald, vice president at Concentric Energy Advisors, said the potential ineffectiveness of RAAIM was a prominent topic in past RA meetings of the group and in submitted comments.  

A UCAP construct, which seeks to procure the most reliable resources by factoring their historical lack of availability into their capacity value, has been offered as an alternative to RAAIM, although stakeholders questioned if the two programs were similar enough to replace one another or if they could operate in tandem.  

“My view is that these two issues can be conceptually separated,” said Alva Svoboda, principal of market design integration at Pacific Gas and Electric. “RAAIM is an issue of how one deals with failures operationally to deliver what has been promised and UCAP can be considered simply as an improved approach to calculating what resources should be eligible to contribute in the RA plan.”  

Implemented in 2016, RAAIM is a bid-based mechanism designed to incentivize resources providing RA capacity to meet their must-offer obligations (MOO) and provide substitute capacity should they go on forced outage. Resources are penalized for not meeting their MOO and rewarded when they do.  

Stakeholders raised concerns about RAAIM shortly after its implementation. In January 2018, CAISO submitted a tariff amendment to FERC requesting modification of the program after identifying a series of issues and problematic outcomes related to it. The ISO found the methodology overweighted the availability of flexible RA capacity compared with generic RA because it treated each availability assessment hour (AAH) as equal, despite differences in RA types.  

The ISO also found that RAAIM was designed in such a way that resources could be led to designate a minimal flex RA megawatt amount with a maximum hourly amount to minimize penalties, reducing incentives to provide capacity at other times. As a result, staff modified the program to treat each megawatt equally within each AAH and to evaluate generic and flex RA separately, among other modifications.  

While FERC approved the modifications, stakeholders still raised concerns about the effectiveness of RAAIM and whether it could be replaced with UCAP.  

RAAIM, UCAP — or Both?

At the Jan. 16 meeting, Lauren Carr, senior market policy analyst at CalCCA, disagreed with Svoboda that the two programs were conceptually distinct.  

“If we have UCAP in place, it is a replacement for RAAIM, and it wouldn’t make sense to have both,” Carr said. “The purpose of RAAIM is to incent substitution when resources aren’t available to follow their must-offer obligation, and if you’re accounting for forced outages up front through UCAP, it wouldn’t make sense to have substitution rules for forced outages.”  

Doug Boccignone, a principal at Flynn Resource Consultants, added that he thought RAAIM was redundant and feared having both programs could lead to double counting of resource contributions for both awards and penalties.  

“I’m questioning whether you’d need additional incentives beyond the long-term UCAP incentive and the short-term incentive to bid your resources and get compensated for them in the market,” Boccignone said. “If you are taking into account reasonable expectation for the resource … you’ve already taken into account forced outages. And if a unit goes on outage, it would be a double penalty to make them go get replacement capacity for that resource you were [already] counting.”  

Svoboda disagreed, saying that having both programs would not lead to double counting because they operate under different time frames and decision processes.  

“The risk of double payment or over-penalizing is better addressed by getting the prices right and requirements right than by throwing the sticks on the table and trying to redesign from scratch,” he said.  

But meeting participants largely agreed that the ISO should reevaluate RAAIM before deciding about UCAP.  

“I think the re-evaluation of RAAIM is one of those low-hanging fruits that will be easy for the ISO to potentially change some of the layouts of the RA construct and the incentivization to show resources,” Nick Burki, senior integrated resource planner with City of Anaheim Public Utilities, said.  

The RA Working Group’s next meeting is set for Feb. 13.  

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Ørsted Cancels Skipjack Wind Agreement with Maryland

Ørsted has canceled its Skipjack Wind agreement with Maryland but will continue preparations to build the 966-MW offshore wind farm in hopes of securing a better deal. 

In its announcement Jan. 25, the company cited the same factors that have caused so much pain for the U.S. offshore sector since late 2022: inflation, interest rates and supply chain constraints. 

Ørsted said the offshore renewable energy credit (OREC) price that it previously negotiated with Maryland is too low now to be commercially viable.  

Even as a global leader in the offshore wind industry, the Danish firm has been hit hard by the sector’s growing pains in the United States, reporting billions of dollars in cost impairments on project delays and cost escalation. 

Other developers have canceled OREC contracts and power purchase agreements along the Northeast U.S. coast in the past year, but none went as far as Ørsted did in October, when it outright canceled the 2.24-GW Ocean Wind 1 and 2 projects off the New Jersey coast. 

But Ørsted is moving forward elsewhere.  

It and Eversource are nearing completion of South Fork Wind and preparing to start construction of Revolution Wind. 

In New York last week, the partners canceled their OREC contract for Sunrise Wind and promptly re-bid the project into the latest solicitation, presumably at significantly higher cost — which essentially is what Ørsted wants to do with Skipjack. 

The company said as it looks for that opportunity it will continue to move Skipjack through the development and permitting process and submit an updated construction and operations plan to the U.S. Bureau of Ocean Energy Management.  

“As we explore the best path forward for Skipjack Wind, we anticipate several opportunities and will evaluate each as it becomes available,” Ørsted Americas CEO David Hardy said in a news release. “We’ll continue to advance Skipjack Wind’s development milestones, including its construction and operations plan.” 

Skipjack would stand off the Delaware coast, but it would feed into the Maryland grid. It has been part of Maryland’s emissions-reduction strategy and would equal 11% of the state’s 8.5-GW 2031 offshore wind target. 

Democratic Gov. Wes Moore’s office summed up the situation in a prepared statement:  

“Governor Moore is disappointed by the news of Ørsted’s repositioning of the Skipjack Wind project, an effort that has the capacity to impact the lives of so many Marylanders. However, he will continue to work with legislators, Maryland’s federal partners, offshore wind developers and advocates that see Maryland’s potential in order to build a system to help Maryland reach the state’s goal of 100% clean energy by 2035.”  

Maryland Public Service Commission Chair Frederick Hoover offered a similar response Friday: “Yesterday’s news from Ørsted is disappointing — the Skipjack project was an important component in advancing Maryland’s clean energy goals. However, the Commission remains optimistic about the future of the offshore wind industry in Maryland, and would note that the US Wind project continues to move through the federal approval process.” 

Maryland awarded ORECs to US Wind for its MarWin and Momentum Wind projects, which total approximately 1,100 MW and are progressing through federal review. (See Draft Environmental Statement Prepared for Maryland OSW.) Additional portions of US Wind’s lease area off the Delaware/Maryland coast are designated for potential future development. 

There are some constraints on offshore wind development near the DelMarVa peninsula, however, due to extensive military and space launch activity in the region. (See BOEM to Auction Wind Energy Areas in Central Atlantic.) 

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Feds Issue Strategy to Protect Right Whale Amid OSW Push

Federal regulators have finalized their strategy to protect a critically endangered whale species as they expedite development of coastal waters for wind energy generation.

The “North Atlantic Right Whale and Offshore Wind Strategy” provides guidance to federal agencies and their partners on how best to promote recovery of the species and other marine life.

The Bureau of Ocean Energy Management and the National Oceanic and Atmospheric Administration’s National Marine Fisheries Service released the strategy Jan. 25.

It follows three main tracks: support tools for mitigation and decision making; research and monitoring; and collaboration, communication and outreach.

Immediate steps include avoiding leasing that may impact whale habitat and issuing guidance to developers on how best to ensure noise does not reach potentially harmful levels.

BOEM and NOAA Fisheries also are directing nearly $100 million of Inflation Reduction Act funds toward conservation of the North Atlantic Right Whale (NARW), which is near extinction. The NARW population is estimated at only 360, with fewer than 70 females of reproductive age.

These efforts seek to untangle a chain of causes and effects: Fossil-fired power generation is blamed for climate change; climate change is blamed for the NARW’s decline; emissions-free offshore wind power is intended to help replace fossil fuel and ease climate change; construction and operation of offshore wind turbines could further harm the NARW.

“Right whales are endangered and climate change is impacting every aspect of their survival — from changing ocean habitat [and] prey availability … [to] migratory patterns — making the transition to cleaner, renewable energy critically important,” NOAA Fisheries Assistant Administrator Janet Coit said in a news release. “Working together on this strategy leverages the best available scientific information to inform offshore wind management decisions while conserving and recovering the species.”

The strategy is a nonbinding advisory document, rather than a directive or rule. It is intended to be updated as more information becomes available.

Save the Whales

Whales have become a center of attention in the offshore wind development debate because an unusual mortality event for the NARW, minke whale and humpback whale along the Atlantic coast has coincided with increasing offshore wind testing and construction activity there.

Officials blame fishing gear entanglement and vessel strikes for most of these whale deaths, but opponents have seized on the timing to blame offshore wind.

A smoking gun for some opponents has been NOAA Fisheries’ use of the word “take” in the Incidental Harassment Authorizations it issues for wind projects.

In that usage, “take” means to harass — to disturb or slightly injure.

But in other contexts — such as NOAA Fisheries’ “Atlantic Large Whale Take Reduction Plan” — the word “take” can mean to seriously injure or kill.

The Marine Mammal Protection Act specifies two types of harassment: Level A has the potential to cause nonserious injury, and Level B has the potential to disrupt behavioral patterns but not directly cause injury.

Serious injury or death of any species listed in a harassment authorization is explicitly not authorized.

But in a lengthy document, that distinction can be missed by those who want to protect whales or ignored by those who want to thwart offshore wind.

This can lead to accusations that a project is officially allowed to kill a specific number of whales.

In one recent example, NOAA Fisheries on Nov. 20 issued a 42-page letter of authorization for incidental take of marine mammals through acoustic disturbance during construction of Revolution Wind off the Rhode Island coast.

This included a Level B take of up to 44 NARWs in any one year and up to 56 NARWs over a five-year period. No Level A take is authorized.

The authorized Level B take is lower for three other whales — 18 sei, seven sperm and three blue whales per year — but much higher for other creatures: 304 minke whales, 2,303 gray seals and 8,084 common dolphins.

Limited Level A harassment is authorized for certain whale species: 21 minke, nine humpback, five sei and four fin.

The letter of authorization also spells out protective measures. Active visual and passive acoustic monitoring for any NARW presence must be maintained during pile driving, for example, and work must be halted immediately if a NARW is detected, unless a shutdown would create imminent risk to human safety or project integrity.

The newly published strategy includes a map indicating that Revolution and several other planned wind farms south of the Massachusetts-Rhode Island coast stand near the densest concentration of NARW activity observed from 2010 to 2019.

Revolution’s harassment authorization reflects this.

By comparison, the NARW is a less frequent visitor to the area off the New Jersey coast where the now-canceled Ocean Wind 1 would have been built.

Ocean Wind 1 would have been up to 50% larger than Revolution Wind.

But NOAA Fisheries authorized a Level B take of only seven NARWs per year for Ocean Wind 1, compared with 44 for Revolution Wind.

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CPUC Fines PG&E $45M for 2021 Dixie Fire

California regulators approved a $45 million penalty against Pacific Gas and Electric on Jan. 25 for the utility’s role in the 2021 Dixie Fire, the second-largest wildfire in state history.

The California Public Utilities Commission voted 3-2 to approve the penalty as part of a settlement negotiated between PG&E and the commission’s Safety and Enforcement Division (SED).

The penalty includes a $2.5 million fine that will be paid to the state’s general fund. PG&E will pay another $2.5 million to tribes whose land was impacted by the fire.

In addition, the utility agreed to spend $40 million to transition to electronic recordkeeping for inspections of overhead and underground distribution equipment. PG&E has agreed to not seek recovery of the $40 million through customer rates.

As part of the settlement, PG&E denied any fault in connection with the Dixie Fire, which was sparked by a tree falling on one of the utility’s distribution lines in the Sierra Nevada foothills.

5-county Blaze

The Dixie Fire started July 13, 2021, when a Douglas fir tree fell onto PG&E distribution lines, a Cal Fire investigation determined. The fire spread across 963,309 acres in five Northern California counties and destroyed about 1,300 structures.

The proposed settlement went to the commission for a vote Nov. 30. But two commissioners — Darcie Houck and Genevieve Shiroma — said they needed more information, and the vote was postponed.

Following the Nov. 30 meeting, SED provided written responses to the commissioners’ questions.

But during the Jan. 25 meeting, Houck and Shiroma said they weren’t satisfied with the answers. They voted against approving the settlement agreement.

Houck questioned whether the relief provided by the settlement was enough given the magnitude of the fire.

“In light of the enormous impact this fire had on the state of California and the five counties impacted, the relief that is being proposed here, based on the information and reports we have today, I still believe is inadequate,” Houck said.

Houck also said she was worried about the impact of the agreement in a future cost-recovery proceeding. Under terms of the agreement, PG&E retains the right to pursue recovery of costs associated with the Dixie Fire.

“There’s still a concern about how the information and the fact that the settlement was there with no admission of fault would be looked at when we’re looking at things like cost recovery,” she said.

Role of Recordkeeping

Several of Houck’s questions during the Nov. 30 meeting were related to the $40 million for electronic inspection records. She asked for more specifics on what information would be digitized and how that would improve safety.

In its written response, SED said digitization “is important for speed and efficiency at the commission and across other agencies responsible for wildfire safety.”

“The continued and accelerated improvement of inspection processes by PG&E pursuant to the [agreement] will support public safety and facilitate commission oversight,” SED wrote.

Commissioner John Reynolds, who voted in favor of the $45 million settlement, emphasized the importance of digitizing records during the Jan. 25 meeting.

“Modernizing records related to the condition of PG&E’s assets may not sound exciting to the public,” he said. “But better information about the condition of electrical assets is vital to improving inspection and preventive maintenance procedures, which are bread-and-butter wildfire safety activities.”

Commissioners also noted that PG&E has taken steps to reduce wildfire risk since the Dixie Fire.

CPUC President Alice Busching Reynolds said the utility now has a system that shuts down distribution lines when it detects a fault, such as one caused by a tree falling on the line.

In a release issued after the vote, the CPUC said it has “taken many actions to hold PG&E accountable for safely serving its customers.”

Those include a $150 million penalty for the 2020 Zogg Fire, a $1 million penalty for the 2019 Easy Fire and a $125 million penalty for the 2019 Kincade Fire.