New York officials on Wednesday issued the state’s third and largest-ever offshore wind energy solicitation, seeking proposals for up to 4.8 GW in new projects on federal leases in the New York Bight.
The state has already contracted 4.3 GW in OSW projects toward meeting the 2035 goal of 9 GW set in the Climate Leadership and Community Protection Act (CLCPA).
“New York is proud to continue leading the way in offshore wind development while establishing a blueprint for building a locally-based green economy,” Gov. Kathy Hochul said in a statement. “Today we are putting words into action and making it clear that New York state is the national hub of the offshore wind industry.”
The New York State Energy Research and Development Authority (NYSERDA) is seeking proposals by Dec. 22 to award OSW renewable energy certificates (ORECs) next spring of between 2-4.8 GW.
In its call, NYSERDA cited the CLCPA and its final supplemental generic environmental impact statement (SGEIS) issued in September 2020, which concluded that, since the lease areas comprise only 3% of the Bight, effects on fishing and marine life would be minimal.
The solicitation includes the first phase of $500 million planned to be invested in ports, manufacturing and supply chain infrastructure; it introduces a first-of-its-kind “meshed ready” offshore transmission configuration, as required by the Public Service Commission in January. (See NYPSC Mandates Meshed Offshore Tx Grids.)
Officials will award evaluation points for proposals that repurpose downstate fossil-based generation infrastructure or use energy storage to enhance future system reliability.
In accord with the New York Buy American Act, the solicitation sets a minimum U.S. iron and steel purchase requirement for all projects awarded and requires developers to provide opportunities for U.S.-based steel suppliers to participate in the growing OSW industry.
NYSERDA will hold a webinar on August 23 to address eligibility criteria, submission requirements, the proposal evaluation process, contract commitments, and the post-award process and agreement.
FERC said Tuesday MISO can exclude certain transmission projects from competitive bidding eligibility, characterizing the change as a “reasonable adjustment to the MISO competitive transmission process.”
The commission said it was appropriate for MISO to assign projects to incumbent transmission owners when at least 80% of their total cost are upgrades to a TO’s existing facilities (ER22-1955).
The ruling will apply to associated upgrades in the four tranches of MISO’s long-range transmission plan (LRTP). MISO’s Board of Directors approved the first LRTP portfolio on Monday, the same day the order was considered effective. (See MISO Board Approves $10B in Long-range Tx Projects.)
MISO in May filed a request to change its competitive transmission process by skipping over competitive bidding’s “short segments and conductor only” work in its larger grid-expansion efforts.
FERC said the grid operator’s proposal is similar to that already approved for SPP. It said the exclusion will allow MISO to “better balance the expansion of competitive transmission opportunities with administrative efficiency, as well as to reduce uncertainty about which transmission projects are eligible for consideration pursuant to that process.”
MISO’s planning team has said some upgrade-heavy, smaller projects will be necessary to accommodate the long-range projects and are not suited for competition.
Some MISO stakeholders protested at FERC, saying the RTO should separate a project’s upgrade work from new transmission facilities, regardless of cost.
A MISO consumer alliance comprised of the Coalition of MISO Transmission Customers, the Resale Power Group of Iowa, the Wisconsin Industrial Energy Group, the Iowa Office of Consumer Advocate and the Citizens Utility Board of Wisconsin said MISO failed to describe the impact the proposal would have on the LRTP portfolio, the process it plans to use to determine exempted upgrades and the associated cost consequences to consumers by precluding competition. The alliance pointed out that ratepayers tend to save about 15 to 20% in transmission costs when projects are competitively bid.
FERC held that a project upgrading an existing transmission facility doesn’t result in a new transmission facility.
Stakeholders earlier this year expressed displeasure that MISO filed for tariff changes to its competitive transmission rules without first consulting the stakeholder community. However, the commission accepted staff’s explanation that they discovered potential smaller, associated projects late in its LRTP development and filed quickly so as not to hold up the portfolio.
The grid operator’s TOs said the revision is necessary to “enable the efficient, timely processing of needed LRTP projects that MISO has identified and to avoid delays and other inefficiencies that would otherwise result.”
New Jersey’s Economic Development Authority (EDA) last week approved the $24.25 million purchase of 109.5 acres of land to nearly double the size of the state’s planned offshore wind manufacturing facility.
The purchase, from a subsidiary of Public Service Enterprise Group (NYSE:PEG), adds to land already leased from PSEG to develop the New Jersey Wind Port, which is expected to cost $500 million to $550 million and have a footprint of 220 acres. The extra parcel will be used to build additional marshaling and manufacturing facilities and provide employees with a second entrance and exit. The port is under construction in Lower Alloways Creek, in South Jersey, next to three nuclear power plants operated by PSEG.
The EDA also hired consultant McKinsey & Co. to study the feasibility of creating a flagship offshore wind research and development facility. The two approvals July 20 add to the state’s aggressive efforts to position itself as a key player in the regional supply chain serving East Coast offshore wind projects, with a goal of supplying equipment and materials to not only New Jersey’s projects but those of other states as well.
EDA CEO Tim Sullivan said the port expansion will help fill what he said is the “current shortfall in fit-for-purpose port capacity across the region.”
“The ability to marshal two projects at once, with additional space for component manufacturing, will turbocharge job creation, opportunities for small businesses, and all forms of ancillary economic activity both locally and across the state.”
Another key part of the state’s plan is to create a flagship research-and-development center. McKinsey, with a budget of up to $880,000, was picked from five applicants and will conduct market analysis and make recommendations for the center based on the outcome of the analysis.
The work will include a “background review on existing offshore wind research and innovation facilities; market analysis to evaluate potential gaps and needs not currently being fulfilled; evaluation of New Jersey’s competitive advantages to address one or more of these gaps; and development of ranked recommendations for New Jersey to pursue,” according to a memo circulated by Sullivan. McKinsey would then evaluate two of the “recommended strategies” and determine their feasibility.
The EDA also has the option to add a third task to McKinsey’s work: creating an implementation plan for the recommended strategies if the project moves ahead. A key goal of the project is to “propel New Jersey forward as the U.S. East Coast hub for world-renowned offshore wind technology research and innovation,” according to the memo. (See NJ Plans ‘Flagship’ R&D Innovation Center for Wind.)
The consultant also will be expected to help the state “support and foster emerging innovations and solutions to offshore wind market challenges and opportunities” and to “incentivize clustering and anchoring of offshore wind research and innovation investments and activities,” according to the memo. The state also expects the state to “capitalize on New Jersey’s existing expertise and reputation for research and innovation across multiple areas, such as cleantech, information technology and life sciences.”
Creating an Industry Hub
The Wind Port emerged from New Jersey’s plan to generate 7.5 GW of offshore wind power by 2035. The New Jersey Board of Public Utilities (BPU) has to date approved three projects — Ocean Wind 1 and 2, and Atlantic Shores — totaling about half the target amount. The BPU expects to begin another solicitation early next year, with two others to follow. (See NJ Awards Two Offshore Wind Projects.)
The EDA says the Wind Port has the potential to create up to 1,500 manufacturing, assembly and operations jobs, and drive billions of dollars in economic growth back into the New Jersey economy.
Construction on the first phase of the port — a 30-acre marshaling area and wharf infrastructure and dredge channel — began in January and is expected to be completed by the second quarter of 2024, according to Sullivan’s memo. The first phase also will include 60 acres of manufacturing and 5 acres to be used for general services. Danish developer Ørsted, which is developing the two Ocean Wind projects, has signed a letter of intent to lease land in this phase to support the projects.
The second phase of the port, which is currently in the feasibility stage, includes an area onto which the developer can dump dredge material from the first phase, saving the state $56 million to $61 million in future dredge deposit charges, the memo says. Construction on phase 2 is expected to begin in 2024.
Endangered Species
The project’s advance, however, faces opposition from the Delaware Riverkeeper Network, which on Friday said that it had filed a 60-day notice of intent to sue the National Marine Fisheries Service (NMFS) in part because of biological opinions issued by the agency for the U.S. Army Corp of Engineers.
The notice said the NMFS violated the Endangered Species Act (ESA) by underestimating the impact of building the Wind Port in the Delaware River estuary, “which is designated critical habit for the Atlantic sturgeon.”
“In preparing the biological opinions, NMFS failed to use the best scientific and commercial data available, resulting in a dramatic underestimate [of] the existing baseline impact of vessel strikes on the Atlantic sturgeon population and a failure to accurately predict the consequences of vessel strikes” during the operation and construction of the port, the notice said. As a result, the agency’s finding that the project did not jeopardize the sturgeon population and the opinions expressed in support of the permit issuance are “without adequate support in the record.”
The notice argues that if the correct data were used, the corps could conclude that the issuance of permits “would likely jeopardize the continued existence of the Atlantic sturgeon.”
The Riverkeeper also targets the NMFS opinion on the permit application for the Edgemoor Container Port, which allowed the development of a major container terminal at the Port of Wilmington, about 25 miles north of the Wind Port.
“Authorizing projects that will increase shipping traffic into the estuary will only accelerate the sturgeon’s demise,” said Maya van Rossum, leader of the Delaware Riverkeeper Network. “I am shocked and disappointed with NMFS for choosing to overlook the vital provisions the Endangered Species Act provides to protect our Delaware River Atlantic sturgeon.”
Consumer advocates, industrial consumers and municipal utilities asked FERC on Tuesday to force PJM to require incumbent transmission owners to sign designated entity agreements (DEA) on “immediate need” projects, contending the RTO has violated its Operating Agreement by refusing to do so.
The complaint by American Municipal Power, the D.C. Office of the People’s Counsel and the PJM Industrial Customer Coalition came the day before PJM stakeholders were scheduled to vote on whether to open an initiative over the dispute.
The Markets and Reliability Committee was scheduled to have stakeholders vote between an issue charge proposed by consumer advocates and one by TOs after negotiations between the two groups failed to reach an agreement over whether the initiative could consider changes to the rights and responsibilities of PJM and the TOs under the Consolidated Transmission Owners’ Agreement. (See PJM TOs, Consumer Advocates at Odds over DEA Inquiry.)
The MRC agenda also gave notice that PJM “anticipates” making a Federal Power Act Section 206 filing with FERC asserting that the OA is unjust and unreasonable regarding its implementation of DEAs. “The specific course of action depends in part” on how the MRC resolves the issue charge.
After the filing of the stakeholders’ complaint, however, PJM amended the MRC agenda to cancel the vote, saying the issue would be discussed tomorrow at the Members Committee meeting.
PJM also amended the MC agenda to give the committee “notice of consultation” of a potential filing under FPA Section 205 to revise the pro forma DEA in Attachment KK of its tariff.
PJM did not immediately respond to a request for comment on the complaint. In an August 2021 letter responding to questions about the RTO’s adherence to the OA, however, PJM CEO Manu Asthana said the RTO had “determined that the Operating Agreement language could be read in a way that is not fully aligned with PJM’s practice for the last seven years or, in PJM’s view, the rationale behind issuing a DEA in the first instance. That is, the DEA was developed to apply only to projects that are selected through PJM’s Order No. 1000-compliant competitive window process and included in the Regional Transmission Expansion Plan (RTEP) for regional cost allocation purposes.”
2018 Order
The current dispute dates back to at least 2018, when FERC rejected PJM’s request to revise the OA to waive the DEA for RTEP projects that the OA requires PJM to designate to an incumbent (ER18-1647). Such projects include TO upgrades; projects that would alter the TO’s use of its right of way; and those located solely within a TO’s zone that are not cost allocated outside. (See FERC Rejects PJM Exemption for Incumbent TOs.)
In rejecting the TOs’ rehearing request in 2019, FERC said that breaching a DEA is more expensive for nonincumbent TOs, which are subject to meeting construction milestones that may be delayed for reasons beyond their control, while incumbent TOs only risk breaking the terms of a CTOA by missing scheduled in-service dates.
Unlike incumbents, nonincumbents must also “obtain a letter of credit or other financial instrument equal to 3% of the incremental project cost in the event of a breach,” meaning this extra cost must factor in project submissions, making the incumbent TO’s proposal cheaper by default, FERC said. (See Rehearing Denied on PJM Designated Entity Agreements.)
Feb. 2022 Policy Change
In the complaint filed Tuesday — which was not immediately assigned a docket number — the stakeholders alleged that PJM for years had only required execution of a DEA for projects selected through a competitive window under Order 1000 that were regionally planned and subject to regional cost allocation.
In February 2022, the stakeholders said, PJM began requiring DEAs for TO-designated projects selected through the proposal window that were not regionally allocated. “However, PJM persists in only partially complying with Operating Agreement section 1.5.8 because PJM is not requiring execution of a designated entity agreement for all regionally planned projects, including immediate-need reliability projects and those resulting from needs that are not posted in a competitive window,” the complaint says.
The complaint asks FERC to order PJM to execute DEAs for about 494 regionally planned projects that have been approved by the RTO’s Board of Managers and are still under construction. PJM has executed only five DEAs, two with incumbent TOs and three with nonincumbents, the stakeholders said.
The complainants said the DEA, which includes requirements that designated entities adhere to scheduling milestones, is “particularly relevant” for time-sensitive immediate-need reliability projects. It cited a 2021 PJM informational filing that reported about 50 immediate-need projects’ anticipated in-service dates would be after their need-by date.
“If there were designated entity agreements in place for these projects, then PJM would be required to re-evaluate the projects to determine whether a different project is needed,” the complaint said.
The complainants said the DEA can also provide cost transparency. “For example, at an April 2021 PJM Transmission Expansion Advisory Committee meeting, Alleghany Power Systems revised the cost estimate for an immediate-need reliability project assigned to it from $41.4 million to $143.4 million, an increase of $102 million, or 246%. Contrary to the express provisions of the currently effective Operating Agreement, there is no designated entity agreement in place for this project,” it said. “If there was, PJM likely would have [re-evaluated] the project earlier and revised the project at that time and perhaps identified a less costly solution that would not have increased the price tag by $102 million.”
SPP’s Board of Directors on Tuesday sided with staff in approving an increase of the RTO’s planning reserve margin (PRM) to 15%, effective next year.
In doing so, the board sidestepped a recommendation from the Markets and Operations Policy Committee to “stair-step” the increase by adding a percentage point to the PRM over three successive years. (See SPP Board, Regulators to Consider Reserve Margin Increase.)
SPP’s reserve margin requirement, currently 12%, is based on a probabilistic loss-of-load expectation (LOLE) study during summer months that is performed every two years to determine the capacity needed to meet the reliability target of a one-day outage every 10 years (0.1 days/year). LREs unable to meet an obligation that is now increasing three points to 15% can incur financial penalties from the RTO.
Half of the 18-person Members Committee approved the motion in an advisory vote, with five (Golden Spread Electric Cooperative, Oklahoma Gas & Electric, Omaha Public Power District, Xcel Energy and Public Service Company of Oklahoma) opposing and five (Dogwood Energy, Empire District Electric, Oklahoma Municipal Power Authority, Tenaska Power Services and Western Area Power Administration) abstaining.
“In all my years with SPP, I’ve probably not had more individual contact on an issue than this one,” said Board Chair Larry Altenbaumer, a director since 2005. “While I’m hopeful to find ways to mitigate any financial costs that people might face, as Winter Storm Uri demonstrated, those costs to meet reliability will pale in comparison with the costs of forced outages and not meeting load.
“There would be no worse scenario than to delay the 15% implementation and then to have an unusual summer event,” he said. “I don’t want SPP and regulators to be on the other end of calls from governors about why didn’t we get this done.”
The Supply Adequacy Working Group (SAWG) recommended the stair-step approach, saying it would give SPP time to reduce the generator interconnection queue’s backlog, adding certainty to generation forecasts, and allow LREs short of their capacity requirements to cure deficiencies.
SPP COO Lanny Nickell promised members that staff would do everything it could to develop a mitigation plan that works for those LREs short of their requirements.
“That is a critical issue that has to be resolved,” he said. “We have to have adequate resources to keep the lights on, but we also have to help our members who are in a position they didn’t expect to be in … We’ve got to move forward and figure out how to implement [the plan] and help members who are in this position through no fault of their own.”
Nickell said LREs short of their capacity requirements — a dozen, according to SPP — have several options to meet the 15% capacity obligation:
purchase existing excess capacity from other entities;
Still, Nickell said staff will also develop a waiver process to be used by members have not had time to cure their deficiencies with the PRM requirement. They plan to offer that up to MOPC during its October meeting.
The directors also approved a motion to accept SAWG’s performance-based accreditation methodologies in its policy paper. Several stakeholder groups and a task force also approved the methodology.
The paper outlines accreditation for conventional thermal resources based on their performance over a five-year period, with the worst year tossed out. This is the first time SPP has applied this methodology.
“By having more reliable capacity on the system, that means you need less capacity overall,” said Antoine Lucas, SPP’s vice president of engineering. “Performance-based accreditation could actually reduce the reserve margin itself, but more importantly, the reserve adequacy requirement.”
SPP last year filed a revision request at FERC to adopt an effective load-carrying capacity accreditation methodology for wind and solar resources. The commission has twice responded with deficiency letters (ER22-379).
Several members and SPP’s Market Monitoring Unit were among those questioning only using the four best years to arrive at the accreditation. The MMU said the approach should be balanced with an appropriate winter planning reserve margin but said it did not oppose or support the proposal.
The measure passed the Members Committee 13-1, with only OG&E opposing. Advanced Power Alliance, the American Clean Power Association, PSO and Xcel abstained.
The Regional State Committee approved both recommendations unanimously, surprising its chair, North Dakota Public Service Commissioner Randy Christmann.
“I thought it would be very close,” he said. “This process has been inspiring. I saw leadership in these last two months with RSC members, with CAWG members, with member companies’ members, some of whom didn’t get their way necessarily on this. But they provided the information we needed to make what we believe is the best possible choice. They really stepped up on behalf of their companies and used the expertise they have in the subject area.”
Members generally agreed, as they did during the MOPC’s lengthy discussion two weeks ago, that the 15% PRM was appropriate, but not without a “glide path” to the target.
“We’re asking the utilities to make turns that are very difficult,” said Oklahoma Corporation Commissioner Dana Murphy. “It’s like turning the Titanic. Sometimes it takes a little bit more of lead time.”
Both measures will require staff to draft revision requests to be filed at FERC.
The Infrastructure Investment and Jobs Act authorized billions of dollars to upgrade the nation’s roads, bridges, airports and railroads. It also included less-talked-about but enormous funding for transportation fuels, from propane to ethanol to electric drivetrains.
The result, says EPA’s top transportation administrator, is that the stage is set for a “golden age of just amazing technologies and policy choices” that he predicts will “transform transportation.”
Karl Simon, director of the agency’s Transportation and Climate Division, office of transportation and air quality, is optimistic that the competition will quickly lead to real progress, he said during the Congressional Renewable Energy and Energy Efficiency Policy Forum in D.C. on Monday.
Calling the legislation’s funding a “transformational set of investments,” Simon said the $5 billion allocated in the bill to implement “a clean school bus program,” for example, compares to a budget of $11 billion for the entire agency a year earlier.
The mission set out by Congress is the replacement of older buses, he said, “and the technologies can be hydrogen, biofuels, propane, natural gas and electric.”
Noting that the legislation speaks to “environmental justice” as well as air quality, Simon said the agency is “allocating funding in various portions that we think will help address different school districts. There are about 500,000 school buses in use at any one time [in] over 13,000 school districts.”
Noting that there is a “buy American” provision in the bill, Simon said “$5 billion is an awful lot of money,” but it will replace only a portion of the existing fleet.
“When the last federal dollar goes out, we are going to be thinking about designs to have a sustainable market so that the bus cost has come down. And those choices for electric buses, for example, which are very pricey at the moment, are not as hard a decision for school districts to think through.”
Electric drivetrains are expected to become less costly, and one reason is that the technology is going to be developed by automakers, said Genevieve Cullen, president of the Electric Drive Transportation Association.
“In 2010, there were two plug-in cars on the road: the Leaf and Volt. Now there are 70 models that you can buy at different price points. And there are a total, I think, of about 2.7 million cumulative plug-in vehicles.
“At the same time there is a growing investment in the [charging] infrastructure … 49,000 public stations, which translates into about 123,000 charging ports.”
Another panelist, Chris Bliley, senior vice president of regulatory affairs for Growth Energy, an ethanol trade group, noted that ethanol gasoline blends are expanding as gasoline prices have increased.
And Art Guzzetti, vice president of the American Public Transportation Association, said the level of funding for infrastructure is significant.
“There are enough funds to make a difference. We’re just not keeping up with … repair needs. If we make the right choices, we can make it a transportation transformational bill,” he said.
“There are provisions in it for low- and no-emissions buses. There is a discretionary grant program that is steered towards policy outcomes, such as access to opportunity, emissions reductions, favorable environmental outcomes; that’s going to give communities and regions the opportunity to make the choice for energy-efficient policies going forward.”
Simon said the significant funding, as well as the specificity regarding how it must be spent, is aiming to help each technology reach a point at which it can survive in a competitive market.
“What is it that you need to kind of get past the kind of the economic tipping point? It doesn’t need to be 70% of the market; it needs to be 20 or 30%,” he said.
Officials from the departments of Energy and Defense spoke at the Congressional Renewable Energy and Energy Efficiency Policy Forum at the Dirksen Senate Office Building in D.C. on Monday to express their concerns about the growing threats to the grid.
Andy Bochman, senior grid strategist for national and homeland security at the Idaho National Laboratory, acknowledged “the imperative for the United States to move as rapidly as possible from carbon-emitting fossil fuels.”
Adding that “one can’t help but imagine a grid with many more wind turbines and solar panels that are currently deployed,” he said additional renewables will not be enough.
“We’re going to need to add much more power to the grid in the near- and mid-term future than renewables alone can provide. There are also some serious grid stability issues to address like voltage support and other ancillary services, which become much more challenging with high penetration of variable generation sources,” he explained.
“We’ve been closing coal plants without fully accounting for the lost baseload generation they provide. Renewables are necessary and super helpful in reducing emissions, but with few exceptions, they’re not ready to play that role, at least not on their own. Gas plants do provide baseload, but they must also be [eventually] phased out.”
Bochman suggested the solution lies in the further development and installation of small modular nuclear reactors, one of which the Idaho lab has assisted in developing. The new plants would be built at the site of former coal plants in order to take advantage of existing transmission lines.
“It’s maybe a tough sell for some, but overall, the public’s attitude towards new nuclear energy is improving swiftly as climate concerns begin to eclipse fears of nuclear energy, and a recent Pew study confirms this.
“There are still plenty of well founded objections to overcome, but small modular reactors and other advanced nuclear designs do meaningfully address most of them,” Bochman argued, adding that the Idaho lab has developed new cybersecurity technology incorporated into the software control system of a small nuclear plant.
Military Microgrids
Joseph Bryan, DOD’s chief sustainability officer and senior adviser for climate, said that the Pentagon has been concerned about the reliability of the commercial power system as it affects the operations of its bases throughout the country.
“Our military installations … are in communities around the country, and they rely almost exclusively on the commercial electric grid for power. And what we all know in this room is that the commercial electric grid is at risk from a couple of different threats. One [is] climate-induced severe weather, from hurricanes to extreme heat, which we’re experiencing in real time [from] wildfires out west.
“We also have a risk from cyberattack. We know that critical infrastructure around the world and even in the United States — think about things like the Colonial Pipeline attack last year — that our adversaries are interested in targeting our critical infrastructure,” he said.
That has led DOD to embrace energy efficiency and build its own distributed generation “to take our facilities off the grid and relieve pressure on the commercial grid,” he added.
To do this, the department has embraced renewable generation, batteries and efficiency “to preserve the [commercial] grid and preserve our own mission by being more efficient and [using] distributed generation.”
“A solar storage [facility] … attached to critical missions can ensure that those functions stay up and running, even if you lose the commercial grid. So, the grid goes down, and you have an efficient operation that has battery backup and PV or other renewable energy assets that do not require logistic support or don’t require fuel deliveries to an installation in times of crisis; that can be important.”
Energy service companies and a data policy coalition on Monday urged New York regulators to reject or amend a petition from the state’s investor-owned utilities to strengthen cybersecurity requirements regarding customer data (Case Nos. 20-M-0082; 18-M-0376).
The joint utilities on May 4 petitioned the New York Public Service Commission to approve six updated and three new requirements in the current self-attestation (SA) of the commission-approved Data Security Agreement (DSA) and a process for regular SA review and potential updates.
The utilities should use a risk-based approach to evaluate cybersecurity concerns, distinguishing between the risk to utility IT systems and the risk of improper access to customer data, whereby they could classify the sensitivity of such data and align appropriate levels of protection, NRG Energy said.
“Instead, the JU Petition opts to overly burden energy service entities [ESEs] and customers by requiring cyber security and encryption methods normally reserved for highly sensitive data at the highest levels of government,” NRG said.
Because the New York State Energy Research and Development Authority (NYSERDA) is working to implement the Integrated Energy Data Resource (IEDR) platform and the commission is considering the utilities’ Data Access Implementation Plan (DAIP), which includes a Data Ready Certification process, the utilities requested that the PSC “move expeditiously” to address the petition no later than Sept. 15, the date of the commission’s regular monthly session.
The utilities’ petition is “misguided and administratively inefficient” and should rather address “the root of the matter,” which is utility liability for a data breach caused by a customer-authorized third party, said Mission:data, a Seattle-based policy advocacy coalition.
Until the commission conclusively removes such liability from the joint utilities, a policy choice that has been made by numerous other states, the PSC will face unending requests from the utilities to increase cybersecurity requirements, even if such requirements are unreasonable, costly, impractical or ineffective, Mission:data said.
“Ultimately… the petition is ‘security theat’ — the performance of precautionary gestures that lack underlying substance,” Mission:data said.
In its July 26 comments, D.C.-based software company Arcadia Power concurred with Mission:data and requested that the commission conclusively remove liability from the utilities for customer-permissioned third-party data breaches. It also urged the PSC to establish a right to due process for ESEs with respect to cybersecurity standards while also requiring ESE representation on a proposed governance committee.
In addition to the general request to adopt a risk-based approach to cybersecurity that includes the SA, Arcadia recommended the commission remove or modify the current SA requirement that all confidential customer utility information be stored in the U.S. or Canada only (Cybersecurity Protection 10).
“Such a blanket restriction is not informed by risk level and is also premised on a flawed understanding of zero trust architecture. There are better ways to address national security concerns related to data processing than implementing such an overly broad geographic restriction,” Arcadia said.
To the extent there is any actual, incremental risk associated with processing data outside of the U.S. and Canada, Arcadia suggested there are numerous mitigation measures under a risk-based framework that would offset such a perceived risk.
“At a minimum, ESEs should be allowed a waiver from these unduly burdensome geographic restrictions upon implementing risk-based mitigation measures that more fully address the data processing security risks at the core of that policy’s rationale,” Arcadia said.
All of the modifications and additions to the SA proposed by the utilities should be reviewed in a stakeholder collaborative prior to the commission rendering a decision, a process that would allow stakeholders to articulate concerns about implementation, said New Jersey-based energy services company Family Energy, which offers gas and electric products throughout New York state.
New York Attorney General Letitia James in March announced that her office was requiring Family Energy to reimburse customers more than $2.1 million for its “dishonest business practices.”
The Infrastructure Investment and Jobs Act (IIJA) provides $753 million to help hydropower dams improve their efficiency, safety and resilience, as well as providing production incentives for existing dams to add hydropower to their operation, according to a fact sheet from the National Hydropower Association (NHA).
But what it doesn’t do, said NHA CEO Malcolm Woolf, is address a more pressing issue in the industry: reform of the multiyear, massively expensive federal relicensing process that is driving some dams to stop producing power and give up their licenses.
Malcolm Woolf, NHA | EESI
“The number of voluntary license-surrenders has been increasing,” Woolf told a live and virtual audience at the Environmental and Energy Studies Institute (EESI) Congressional Renewable Energy and Energy Efficiency Policy Forum on Capitol Hill on Monday. “We had 41 facilities give [licenses] up in the 2010s. We’ve had another 17 in just the last two years … which becomes really dangerous when you realize that half the nonfederal fleet is up for relicensing by 2035.”
Woolf was one of eight energy industry officials speaking at the live event, which focused on the opportunities created by the IIJA, the challenges of the law’s implementation and the policy gaps that still need congressional action, including hydropower relicensing.
For Curt Rich, CEO of the North American Insulation Manufacturers Association, the law’s $225 million to help update and implement more energy-efficient building codes represents “an unheard-of level of investment.”
“The Department of Energy building code program kind of walks along at about $5 [million] to $10 million a year,” Rich said. With the increased funding, and “as you train the workforce to enforce updated codes and implement updated codes, it in turn is really going to catalyze energy-efficient construction and just support all of the other initiatives that are underway across building sectors to drive energy efficiency.”
Rich also sees IIJA money going to states for energy-efficiency incentives as a key driver for the industry, especially to motivate commercial or multifamily building owners to move ahead with upgrades.
“It’s really hard to get people to just act in their own interest,” he said. “The money for efficiency programs that will be flowing through residential, commercial and industrial buildings, principally through the states, that will provide decent incentives for building owners to act.”
Bill Parsons, ACP | EESI
Bill Parsons, vice president for federal and state affairs at the American Clean Power Association, spoke about the IIJA provisions giving FERC backstop siting authority to override state opposition to interstate transmission projects as a vital step forward.
Increasing renewables on the grid will make a major buildout of the transmission grid essential, Parsons said, but he also argued that intermittent renewables should not be automatically viewed as “unreliable.”
Nationally, renewables “were about 14% of the generation mix last year,” he said. But “at times, in certain areas, we have been 80%. You didn’t hear about it because there was no reliability issue.”
Parsons also raised concerns about the IIJA’s Made in America preference on projects receiving federal dollars: for example, funds for building out the electric vehicle and lithium supply chains. While a domestic energy storage supply chain is “critically important,” he said, it is “unrealistic” to require a 100% U.S. supply chain on projects receiving IIJA funds.
“We don’t hold many other industries to a standard of 100% sourcing domestically,” he said.
Pitching to the audience of congressional staffers at the event, Parsons additionally pointed to a crew-mandate bill passed in the House of Representatives earlier this month as part of the defense authorization bill, which would require crews on U.S. ships working on offshore wind or oil projects to be American citizens or permanent residents, or from the same country as the vessel’s flag.
“It’s literally going to freeze the first 19 offshore wind projects in [their] tracks,” he said. “We need to train people to crew [these ships], but we need to be realistic about time frames as it relates to mandates and how these vessels are crewed if we don’t want to freeze the offshore wind industry before it has a chance to begin.”
The Digital Energy Workforce
The IIJA provided $62 billion to the Department of Energy, which Kelly Speakes-Backman, principal deputy assistant secretary for the department’s Office of Energy Efficiency and Renewable Energy, said is “the biggest investment to the department since our founding. It stands up 60 entirely new programs, and it expands 12 existing ones.”
In the nine months since President Biden signed the bill into law, $13 billion in funding has been made available, and about half of the 60 new programs have issued requests for information, drawing thousands of pages of industry and public input, she said.
“That’s one thing you’ll see about the way we do our business these days: really making sure that it is locally placed information to draw from to build out our program,” Speakes-Backman said.
Joy Ditto, CEO of the American Public Power Association, also talked about the importance of community engagement in making sure the IIJA is implemented to benefit smaller communities. While the law’s many programs and funding announcements are a huge opportunity for the nation’s 2,000 publicly owned utilities, Ditto said, many of her members, especially smaller utilities, have challenges just applying for the money, either because of limited staff and expertise, or they are not sure if they will qualify for specific programs.
“A lot of our focus now is just enabling our members to interface with the federal government, giving them resources to access funds as they become available,” Ditto said.
The close connection between workforce development and ensuring the success of IIJA projects was another key theme at the forum. As of 2021, the U.S. energy workforce stood around 7.8 million, with 40% of that total employed in “net-zero-emissions-aligned” jobs, according to DOE’s recently released U.S. Energy and Employment Report.
But Jeannie Salo, North America vice president for government relations at Schneider Electric, was adamant that those workers and others coming into the energy sector need to be trained with digital jobs skills.
“We often talk about the digital economy,” Salo said. “There is no other economy; it’s just the digital economy, and digitization is at the core of everything we need to do to be more efficient, to transform our infrastructure.”
“The barriers are training that’s tied to real jobs and [the] lack of awareness of clean energy careers at all in secondary schools,” she said. Schneider is upskilling its workers at a “smart factory” in Kentucky, she said, which is helping the company attract and retain workers.
Jason Walsh — executive director of the BlueGreen Alliance, a coalition of labor unions and environmental groups — agreed, saying a well trained and credentialed workforce “is going to matter more than ever.”
“The climate crisis is so urgent, we’ve only got one shot to do this right,” Walsh said. “And so verifiable, credentialed skills for the workers that do that work are going to be absolutely fundamental because they’re not going to get another go.”
At the same time, Walsh said the clean energy transition will require investment and workforce development levels well beyond the IIJA.
“The clean energy, energy-efficiency economy is inherently more labor intensive than an economy based on fossil fuels and waste,” Walsh said. “Manufacturing and installing sources of our fuel rather than burning them — that creates jobs. In the building sector, energy efficiency turns the wasted energy into work, so that goes from no jobs to lots of jobs.”
Washington state lifted its remaining drought designations last week because of an unexpectedly cool and wet May and June.
The unseasonably cool weather has caused Cascade Range snowpack to last longer into the summer, which will support late-summer water needs, Jeff Marti, statewide drought coordinator at Washington’s Department of Ecology, said in a statement.
“Conditions have improved. All areas of the state, including the five watersheds specified in the drought declaration, have received significantly above-normal precipitation,” Marti said. “The outlook is much better than forecast back in May.”
The wet weather doubled the normal June rainfall figures for much of Eastern Washington. “Conditions have been anything but drought-like,” Marti said. “We’ve experienced one of the wettest, coldest springs in recent memory.”
In July 2021, Gov. Jay Inslee declared a drought emergency for 96% of the state, citing the severe effects of climate change. Last year’s declaration sped up processing for emergency drought permits and allowed temporary transfers of water rights. The cities of Seattle, Tacoma and Everett were not included in the drought emergency because they have significant amounts of stored water.
On May 26, the area of Washington from the Cascades to the west was removed from the drought designation. Most of Eastern Washington, except for four areas, was designated as a drought advisory area. A “drought advisory” means that rainfall is above the 75% mark but could potentially drop below.
In May, five watersheds in areas spread across parts of eight northeastern counties were still in “drought emergency” because they had not received enough rainfall to recover. This land covers about 9% of the state. The drought emergency area covered parts of Spokane, Lincoln, Grant, Adams, Whitman, Stevens, Okanogan and Pend Oreille counties.
The lifting of drought designations addresses those Eastern Washington areas.
