Kentucky officials have asked FERC to again shut down American Electric Power’s proposed $2.6 billion sale of its Kentucky operations to Liberty Utilities.
The Kentucky Public Service Commission, Kentucky Office of the Attorney General and Kentucky Industrial Utility Customers said in a March 30 protest that AEP (NASDAQ:AEP) and Canada’s Algonquin Power & Utilities (NYSE:AQN) conglomerate, whose North American assets include Liberty, have yet to address or propose mitigations for the “adverse impacts of the transaction on zonal transmission rates” (EC23-56).
FERC temporarily halted the transaction in December, directing AEP and Liberty to write in more consumer protections before it would approve the deal. AEP and Liberty responded in February by including a five-year freeze on the current return on equity and 55% equity capital structure; a commitment from Liberty to maintain the same credit profile for five years; and a five-year cap on operations and maintenance and administrative costs at the 2022 rate. (See AEP, Liberty Utilities Try Again on Kentucky Territory Deal.)
However, the Kentucky intervenors said that AEP’s and Liberty’s pledge that Kentucky Power and Kentucky Transco would remain in PJM’s AEP East transmission pricing zone “for the foreseeable future” is not good enough to protect consumers from rate increases.
The Kentucky PSC said even if Kentucky Power remains in the AEP East zone, its rates under Liberty’s ownership will increase because the utility will have higher incremental fixed and variable costs caused by “building a new transmission organization from the ground up.” The PSC said the zonal revenue requirement’s extra costs will “far exceed” any savings AEP will experience from shedding its Kentucky operations.
The regulators said that if Kentucky Power is separated from AEP ownership but remains in the AEP East zone, the PSC would lose its ability to use its “retail ratemaking jurisdiction to influence AEP’s decisions” on transmission investment in the seven-state AEP East zone, regardless of the benefit to Kentucky consumers. The commission said AEP-affiliated companies would no longer be under pressure to avoid shifting costs to Kentucky consumers.
“Applicants cannot simply ask the FERC and other stakeholders to accept its ostrich-like approach to the impacts if a move is made, or if it is not,” the Kentucky parties said.
They also argued that AEP and Liberty’s “extensive reliance” on future retail rate benefits aren’t relevant to FERC’s decision because the PSC deemed them necessary to shield consumers from the transaction’s rate hikes.
AEP and Liberty are hoping to close their transaction by April 26. If they fail again to gain commission approval by then, termination rights kick in for the parties.
The EPA on Friday approved a waiver for California’s Advanced Clean Trucks regulation, clearing the way for the state to launch the zero-emission program for medium- and heavy-duty trucks starting with model year 2024.
The regulation will require truck manufacturers to sell an increasing percentage of zero-emission medium- and heavy-duty trucks in the state from 2024 through 2035.
The zero-emission vehicle sales requirements will also apply in states that have adopted California’s Advanced Clean Trucks (ACT) regulation, including Washington, Oregon, New York, New Jersey, Massachusetts and Vermont.
California Gov. Gavin Newsom on Friday called the EPA decision “a big deal for climate action.” Newsom said California will be the first government in the world requiring zero-emission trucks.
“We’re leading the charge to get dirty trucks and buses — the most polluting vehicles — off our streets, and other states and countries are lining up to follow our lead around the world,” Newsom said in a statement.
The EPA waiver was needed because air quality standards in the ACT differ from those of the federal government. California is allowed to adopt and enforce its own vehicle emissions requirements if they exceed federal standards and EPA grants a waiver.
“Under the Clean Air Act, California has long-standing authority to address pollution from cars and trucks,” EPA Administrator Michael Regan said in a statement on Friday. “Today’s announcement allows the state to take additional steps in reducing their transportation emissions through these new regulatory actions.”
Mixed Reactions
The American Trucking Associations (ATA) on Friday criticized the EPA decision, saying it allowed California to create a “regulatory patchwork.”
“This isn’t the United States of California,” ATA CEO Chris Spear said in a statement.
Spear said the regulation’s “technologically infeasible rules” and “unworkable and unrealistic timelines” were setting the stage for a supply-chain crisis.
But environmental groups welcomed the EPA decision.
Heavy-duty trucks account for only about 10% of vehicles on the nation’s roads but have an oversized impact on air pollution, according to the Environmental Defense Fund. The impacts are felt especially in low-income areas and in communities of color, EDF said.
“The Advanced Clean Trucks Rule will save lives, save money for truckers and fleets, save the state billions of dollars in health care costs, and help create thousands of new jobs,” EDF clean transportation attorney Andy Su said in a statement.
Three Waiver Requests
The California Air Resources Board adopted the Advanced Clean Trucks regulation in June 2020. CARB has said that its rule will drive technology development and investment in zero-emission trucks.
In deciding whether to grant a waiver for ACT, the EPA held a virtual public hearing in June 2022 and accepted written comments through Aug. 2.
EPA also granted a waiver on Friday for a CARB regulation that extends emissions warranty periods for heavy-duty diesel trucks in model years 2022 and later.
EPA has yet to decide on a third waiver request from CARB. The Heavy-Duty Low NOx Omnibus Regulation, which CARB approved in August 2020, aims to reduce emissions of nitrogen oxides from trucks. The rule sets new standards starting with the 2024 model year and tightens the standards further in 2027.
CARB has asked EPA for more time before EPA acts on the low NOx waiver request, the federal agency said.
Increasing Sales Requirement
In August, CARB adopted the Advanced Clean Cars II regulation, banning the sale of gas-powered cars in 2035. The rule allows some sales of plug-in hybrid vehicles at that time. (See Calif. Adopts Rule Banning Gas-powered Car Sales in 2035.) CARB must still receive a waiver from the EPA to enforce those regulations.
Advanced Clean Trucks isn’t a total ban on gas-powered truck sales. Zero-emission sales requirements vary by vehicle class. For Class 2b and 3 trucks, such as step vans and city delivery trucks, the rule requires 5% ZEV sales in 2024, increasing to 55% in 2035.
For class 4 to 8 trucks, such as large delivery trucks, school buses and beverage trucks, the 9% requirement for zero-emission new vehicle sales in 2024 grows to 75% in 2035. ZEV sales requirements for Class 7 and 8 tractors range from 5% in 2024 to 40% in 2035.
ACT also includes a credit system in which a truck manufacturer may sell ZEV credits they earn to other manufacturers. Manufacturers may receive early credits for zero-emission trucks sold starting with model year 2021, and certain hybrid electric trucks may earn partial credits.
Under ACT, zero-emission sales requirements for trucks don’t increase after 2035. But a 2020 executive order from Newsom set a goal for all medium- and heavy-duty vehicles in the state to be zero-emission by 2045 where feasible.
In addition to ACT, CARB is expected to vote during its April 27 meeting on adoption of another zero-emission truck regulation, Advanced Clean Fleets.
The regulation would require some or all new trucks added to certain types of fleets to be zero-emission starting in January 2024. The three types of fleets covered are drayage, state and local, and fleets deemed high priority.
Stakeholders told the New York Public Service Commission it should modify utilities’ proposed transmission planning framework, saying the plan lacks independence and could favor local upgrades over more efficient regional projects (20-E-0197).
The PSC received comments from about 20 agencies, companies, nonprofits and trade coalitions. They said the CGPP’s timeframe does not match NYISO processes and that the proposed independent body responsible for advising the PSC lacks diversity. In addition, the methodologies for identifying transmission upgrades appear biased, and advanced technologies were inadequately considered, the commenters said.
Independence of Advisory Group
Stakeholders said the utilities’ proposed make-up of the Energy Policy Planning Advisory Council (EPPAC) would make it a vessel for expanding utility interests.
As proposed, the EPPAC would include a representative and an alternate from each utility, Department of Public Service staff, NYISO, the New York State Energy Research and Development Authority, renewable generation and storage associations, power authorities (New York Power Authority, Long Island Power Authority) and environmental justice community associations.
New York City was forceful on this, writing that the EPPAC “creates an inherent conflict” because of how much control the utilities would have over its processes. It is hard to imagine why the council would advance results “inconsistent with their views, plans and proposals,” the city said, calling it “mostly a plan for the electric utilities to coordinate among themselves with no requirement to incorporate input from others.”
The New York Power Authority said that the proposed EPPAC leaves some sectors with “a reduced opportunity to provide valuable input.”
NYISO, NYPA, Environmental Defense Fund, the Working for Advanced Transmission Technologies (WATT) Coalition, the “Clean Energy Parties” (including the Alliance for Clean Energy New York, Advanced Energy United and solar and battery organizations) and a joint filing by organizations including the Alliance for Clean Energy New York, the New York Offshore Wind Alliance, Natural Resources Defense Council and the American Clean Power Association (“the Alliance”), argued that the PSC should expand the EPPAC with non-utility members to diversify the council.
Synching with ISO Process
Most commenters also said the CGPP, which operates on a three-year life cycle, is incompatible with NYISO’s two-year public policy transmission planning process for identifying and evaluating necessary transmission upgrades.
The CGPP “would not integrate well with existing NYISO transmission planning processes and would not fully reap the benefits available from competition in the identification and procurement of local and bulk solutions to transmission need,” wrote NYPA.
This was echoed by the CEP, the Alliance and EDF Renewables, which proposed a compromise to reduce CGPP to a two-year cycle but complemented with a PSC review lasting no more than six months.
Threat to Competition
Commentators also complained that the CGPP gives utilities control over public policy transmission need processes, threatening competition.
The CGPP turns the “existing FERC-approved system on its head” and gives utilities opportunities “to displace bulk upgrades with smaller, less efficient local upgrades,” LS Power wrote. It would threaten transmission competition and eliminate consumer benefits “including reduced cost per MW of incremental transfer, increased production cost savings, reduced emissions, and cost containment,” LS said.
“Placing [utilities] in charge of selecting a bulk solution raises potential jurisdictional issues and may create inefficient incentives” wrote NYPA. It warned the utilities’ plan gives them the ability to “favor their own projects rather than exposing transmission needs to competitive selection.”
NYISO said the PSC should “require clear criteria for the prioritization of solutions in a multifaceted planning process,” since this provides the CGPP with “clearer workstreams and avoid a preference for local transmission solutions where a regional solution can more efficiently achieve the CLCPA targets and benefit ratepayers.”
EDFR, the CEP, and the Alliance also highlighted this issue, which they said the PSC could address by encouraging greater flexibility in transmission evaluations and increasing transparency in competitive processes.
Grid-enhancing Technologies
Many commentators also said the CGPP should be more open to future technologies, specifically distributed energy resources and energy storage.
The CGPP does not “adequately incorporate the value of grid enhancing technologies” while the CEP argued the proposal “does not establish a clear, transparent, timely or collaborative process for evaluating and including [new] technologies.”
Transource Energy said that the utilities “limited their recommended list of technologies.” The EDF said CGPP evaluations failed to provide “detailed distribution grid planning that will be needed in New York.”
ECOGY Energy, a Brooklyn-based developer, advised the PSC to require more flexibility at the distribution level to improve long-term planning for future technologies, while Transource said the PSC should add several public review processes within the CGPP cycle to review technologies deployed since the last cycle.
The first CGPP cycle is scheduled to start July 1 and end on July 1, 2025.
There are many polarizing issues dividing America today, but support for reliable electricity is not among them. No one is in favor of power outages, and no one should be left in the dark.
Extreme weather events have stressed the grid in most regions of the country over the last decade, and the frequency and severity of these events are only expected to increase in the years ahead. Every type of generation has struggled through these events. To solve this problem, utility commissioners, grid operators and federal regulators must look beyond generation solutions.
The U.S. grid is aging and balkanized. Most regions have limited ties to one another, meaning there is little transmission capacity available to transfer electricity between neighboring areas. Yet studies show interregional transmission lines can serve as lifelines in an emergency — delivering power from unaffected areas to storm-ravaged regions where power plants were forced to halt operations.
As a recent U.S. Department of Energy (DOE) draft study demonstrated, increasing interregional transmission capacity yields the greatest value, improving access to affordable power and helping ensure a reliable supply of electricity. Interregional transmission lines allow grid operators to access more generation resources and are particularly useful for providing additional supply during extreme weather events, according to the DOE. The agency also identified a “pressing need” for more transmission infrastructure.
During Winter Storm Uri in February 2021, an additional gigawatt of transmission capacity between the Texas grid and the Southeast could have saved Texans nearly $1 billion and kept the lights on in 200,000 homes, according to a report from Grid Strategies. Meanwhile, interregional transmission ties allowed the Great Plains and Midwest grid operators to import 15 times more electricity during the storm than the Texas grid, helping avoid widespread outages that killed hundreds in the Lone Star state.
In December 2022, some grid operators in the Southeast were forced to conduct rolling blackouts when power plants came offline because of harsh winter weather. Those outages would have “undoubtedly been far more widespread” had operators not been able to access power imported through interregional transmission lines, according to a Rocky Mountain Institute analysis. Additional interregional capacity would have allowed the Southeast to access available Midwestern generation, alleviating the region’s supply shortage.
Forward-looking studies evaluating the grid under extreme weather conditions predict similar results unless significant interregional transmission is developed. At least 65 GW of new interregional transmission capacity was needed to keep the lights on during simulated extreme weather conditions from 2035 to 2040, according to a recent report by GE Energy Consulting.
American homes and businesses depend on FERC to access reliable, economically efficient energy services at a reasonable cost. To ensure reliability and low prices, commissioners must evaluate ways to remove barriers to and encourage the development of these interregional projects. Three near-term options are available.
First, a minimum interregional transfer capacity requirement would provide significant reliability benefits by producing much needed long-range transmission. FERC, having convened a technical conference on such a standard in late 2022, should pursue a rulemaking to establish a minimum threshold.
Second, the commission should accept Invenergy’s petition and host a technical conference to discuss removing barriers to merchant interregional high-voltage, direct-current transmission lines. FERC’s current transmission-related rulemaking proceedings do not consider the evolving role of these technologies, and a technical conference would allow regulators to consider the costs, impact and utility of such projects, as the National Association of Regulatory Utility Commissioners noted.
Third, the agency should ensure its forthcoming transmission planning and cost allocation rulemaking includes needed reforms that can benefit interregional planning, as well as regional transmission planning. Requiring planning regions to quantify a minimum set of transmission benefits metrics can help eliminate one of the main barriers to planning interregional lines. Going forward, FERC should also lay the groundwork for a future rulemaking focused on reducing obstacles hindering interregional project development.
U.S. grid operators have seen several major system failures in the last several years. Our aging grid has demonstrated it cannot meet today’s demands, leaving millions at risk for extreme weather events in the coming decades. Expanding transmission capacity to ensure customers have constant access to affordable power will require sound policies to strengthen interregional ties. It’s time for FERC to act.
Ted Thomas is founding partner at Energize Strategies and former chair of the Arkansas Public Service Commission.
BALTIMORE — The first U.S. wind farms are being connected to the grid with one-off radial transmission lines, but as the industry grows it will have to follow Europe’s recent example and build out meshed high voltage, direct current (HVDC) systems, experts told the Business Network for Offshore Wind’s International Partnering Forum last week.
“Why are we thinking about doing this?” asked Judy Chang, a fellow at Harvard’s Kennedy School. “Overall savings, reliability, resilience, maximizing the integration of renewables while strengthening the grid through offshore systems.”
The Elia Group, which runs the grid in Belgium and eastern Germany, last year created a new subsidiary called WindGrid to pursue such offshore transmission opportunities.
Having an independent set of eyes looking at the infrastructure needed to connect offshore wind farms has worked well in Europe and now Elia’s new unit is starting to bring that business to the United States market, said WindGrid CEO Markus Laukamp. One of the big challenges in the U.S. is that transmission planning and generation develop at the same time in parallel tracks. That makes it hard to build out the transmission system, which takes longer to complete, he said.
“I think one of the challenges that we see for the U.S. is really to get these things in order so that maybe not next year — maybe five to 10 years — you can do things in the way that makes the most sense for the ratepayer and that is optimizing a coordinated grid,” Laukamp said.
New York is hoping to start planning a meshed offshore grid in tandem with its upcoming wind procurements, said Georges Sassine, vice president of the New York State Energy Research & Development Authority.
Sassine said he has been urging NYISO to run a public policy transmission planning process under Order 1000 to help bring renewable power into New York City both from on and offshore resources. The planning process for transmission should happen at the same time New York is working to procure the offshore wind that needs to be connected to the grid, Sassine said.
WindGrid is building an artificial energy island in the North Sea that will initially help connect wind farms to the Elia Group’s grid in Belgium. It has planned expansions to connect to Denmark and the United Kingdom, said WindGrid’s Thomas Kobinger. His firm is also building a similar project in the Baltic Sea to connect Denmark and Germany with multiple offshore farms via equipment on the Danish island of Bornholm. Such major projects have benefits for the onshore grids they are connected to, Kobinger said.
“We can reduce bottlenecks in the AC system. We can even reduce losses on the AC system. So, there’s a lot of benefits from a system perspective,” said Kobinger.
One idea is to connect wind to shore through shared corridors where multiple wind farms would plug into the same place on the grid onshore. Connecting corridors together in a mesh means that power could flow to multiple cities from one wind farm, said James Ware, senior electrical project manager for Ørsted. Meshed networks can cut fossil generation, avoid congestion, offer more flexibility to the system and can facilitate transfers during emergency situations, Ware said.
“But the question still remains … how far does the benefit go?” Ware said. “And who pays for it? And what is that cost?”
While figuring out where the costs and benefits of the HVDC links flow is tricky, they are obvious enough that many in the United States are already thinking of using them, including Public Service Enterprise Group, said its Offshore Wind Development Manager Rafael Wilches.
The states’ and federal government’s increased offshore wind goals require a “serious” look at multi-terminal HVDC systems, Wilches said.
Getting there will require bringing HVDC vendors, transmission owners, the ISO/RTOs and other stakeholders together to plan out such systems to make sure that different pieces can operate with each other. Funding from the federal and state governments would also help move the ball forward, Wilches added.
The U.S. has a long-term goal of getting 110 GW of offshore wind by 2050, which represents a lot of power that needs to get to land, said Hannah Taylor of the Department of Energy’s Wind Energy Technology Office.
“We need to do that … cost effectively, efficiently, equitably and responsibly,” Taylor said. “And we view multi-terminal systems and HVDC technologies as a pathway to get to that solution.”
DOE has multiple funding opportunities for research and development into HVDC technologies, and its Loan Program Office is available for the next step of helping new technologies reach commercialization, she said. DOE can also convene stakeholders to gather input on how best to interconnect growing offshore wind.
The department’s National Renewable Energy Laboratory is working on a project to help understand the protection and HVDC breaker needs for such off-shore circuits, said Taylor.
“That will be a key technology in realizing multi-terminal DC in the U.S.,” she said.
MISO said it created more than $4 billion in value for its membership over the course of 2022.
That’s according to grid operator’s 2023 Value Proposition, which calculates last year’s collective annual savings for members versus the lack of a resource sharing pool.
MISO said it has saved members about $40 billion since the value proposition was first calculated at about $1 billion in 2007. The RTO said the value proposition shows a $12 return for every dollar of investment in MISO membership.
“I’m proud that MISO continues to deliver substantial benefits to our entire footprint,” MISO CEO John Bear said in a press release. “We spend a lot of time with our members and stakeholders to better understand their needs and ensure alignment as our industry continues to rapidly change.”
As with prior years, MISO said its large geographic footprint accounted for most of the cost savings. It said its ability to share capacity saved members between $2 billion and almost $3 billion.
MISO said its energy dispatch efficiencies, where its real-time and day-ahead markets deploy the most economic resources, saved members from $620 million to $690 million. The RTO also said its renewable resource optimization — which connects low-cost renewable resources where they’re helpful, thus reducing the need for more capacity investment — saved members between $410 million to $480 million.
“We work tirelessly to ensure that our region receives the most out of MISO membership,” said Wayne Schug, MISO’s vice president of strategy and business development. “Reliably building and operating the grid of the future while supporting our members’ sustainability and affordability objectives requires close collaboration. As we advance the work discussed in MISO’s reliability imperative and enable the future grid, we expect the value proposition to grow substantially.”
“Reliability imperative” refers to the responsibility to ensure the clean energy transition occurs in a reliable and orderly manner.
BALTIMORE — With major new projects coming online starting this year, the offshore wind industry is turning to longer-term goals of rolling out more than 100 GW of capacity and setting up the associated supply chains, speakers said Wednesday at the Business Network for Offshore Wind’s International Partnering Forum (IPF) Conference.
The conference marked the 10th anniversary for BNOW, as the conference has grown from occupying a small conference room to filling the Baltimore Convention Center, CEO Liz Burdock said.
“Together, we have grown the U.S. offshore wind industry,” Burdock said. “We’ve taken it from legislation to demonstration and this year to commercialization.”
The federal Inflation Reduction Act passed last year includes direct subsidies for offshore wind, but also seeks to grow new markets for OSW, such as hydrogen. Passage of the law makes it impossible to accurately forecast the industry’s eventual size, Burdock said, but the Biden administration has a goal of 110 GW by 2050, and states are starting to step up their own goals, which amount to about 77 GW.
Maryland Gov. Wes Moore (D) announced a new, more aggressive target for the technology than his predecessor, who had set a goal of 1.6 GW.
“Once the Bureau of Ocean Energy Management approves the new lease areas for our state, Maryland will aim to produce 8.5 GW of power through offshore wind,” Moore said. “And let’s be clear, that’s enough energy to power nearly 3 million homes.”
Other states either have raised — or are planning to raise — their targets for offshore wind, with New Jersey last year announcing a new 11-GW target, and New York considering raising its 9-GW goal to 16 to 19 GW.
Moore hopes that expanding Maryland’s goal will attract new industrial jobs to Baltimore, which used to be a major producer of steel.
“The steel we made in Baltimore helped win two world wars,” Moore said. “The steel we made in Baltimore helped stand up the tallest buildings in the world. The steel we made both helped create tens of thousands of jobs and millions of dollars of wealth.”
Demand dropped off in the later 20th century and the mills shut down, but now offshore developer US Wind is planning to lease 100 acres where an old steel mill stood as it builds out the resources needed for its planned offshore wind farms. Other firms are setting up shop in the state to further the industry as well.
“Maryland steel led the American economy in the 20th century,” Moore said. “I want Maryland wind to lead the American economy in the 21st century.”
Moore said he ordered the Maryland Energy Administration to focus on delivering grants to companies that make up key links along the offshore wind supply chain. Increasing the high-paying jobs associated with the industry can change lives and lead to generational prosperity, he said.
“That’s why I am deeply serious when I say that Maryland will lead in offshore wind,” Moore said. “I mean that. I am deeply serious. When I say that we have the real estate, the brainpower, the assets and the agenda to get it done, I mean that.”
President Biden in 2021 set a goal of building 30 GW of offshore wind by 2030, which many at the time thought was ambitious, White House National Climate Adviser Ali Zaidi said. But that target can be reached, and the industry could even go well beyond it, he said.
“And the reason is because this is not just an opportunity for electricity,” Zaidi said. “It’s an opportunity to create good-paying jobs across manufacturing, and shipbuilding and port operations — construction jobs, operations jobs and more as we build a brighter, more sustainable and fairer future for all of us all across the United States.”
Offshore wind investments tripled last year, totaling $10 billion, with 46 states having some piece of the supply chain for offshore wind, he added.
“Through the Inflation Reduction Act, the president has delivered game-changing support for building clean energy components here in the United States of America,” Zaidi said. “We’re working to swiftly implement the manufacturing tax credit to support U.S. production of offshore wind components, like blades and nacelles and towers and foundations.”
New York’s 9-GW target for offshore wind is just the start, said New York State Energy Research and Development Authority CEO Doreen Harris.
“New York certainly has some of the most aggressive and ambitious climate and clean energy objectives in the nation, and … talk about something we need more of: we need more offshore wind,” she added.
While New York and other states want to attract the same kind of jobs that Gov. Moore does, Harris said states could also benefit from working together to develop regional hubs for with their neighbors.
Setting ambitious, long-term goals is a big help for the industry because those, in turn, will attract the kind of supply chain investments needed to produce jobs and create the wind farms themselves, US Wind CEO Jeff Grybowski said.
“We know that we won’t be able to do it on our own here in the U.S. The supply chain is paying attention — a lot of attention — to U.S. projects,” he said. “The state policy goals are critically important to that because this industry needs the long-term vision.”
The policy support from states and the federal government has coalesced to the point where real investments are being made by global suppliers feeding domestic developers, he added.
The domestic industry will have to initially rely on foreign supply chains because the expertise in offshore wind is in Europe, although that will have to change over time.
“The global supply chain is not big enough to service the rest of the world, never mind throwing in the U.S. requirements as well,” said Tony Appleton, director of offshore wind for engineering firm Burns & McDonnell. “So, it’s very important the U.S. develops its own supply chain.”
On top of that, Americans will eventually get “pretty annoyed” about supporting European jobs in the supply chain through their electric bills, so developing domestic capacity will be more politically sustainable, he added.
Thirteen years after the Champlain Hudson Power Express was first proposed, the first shipment of HVDC cable needed to build it arrived in New York on Thursday.
The 35 drums each hold 2,000 to 3,000 feet of cable. More than 500 drums will be needed to build the roughly 140-mile underground sections of the 339-mile, 1,250-MW line from Quebec to New York City.
The 190-mile underwater portion of CHPE will require an even greater amount of cable, which will be essentially the same except for an extra layer of exterior protective material.
The logistics of the shipment were fairly straightforward: a 3,829-mile journey aboard a freighter from Karlskrona, Sweden, to the Port of Albany, then another 53 miles by truck to CHPE’s staging area in Fort Edward.
The regulatory process, not so much.
Since Transmission Developers Inc. submitted 10 paper and 10 electronic copies of its request for a certificate of environmental compatibility and public need to the New York Public Service Commission on March 29, 2010, the expected price tag has more than doubled; the designed electrical capacity has shrunk by more than a third; and 4,573 additional documents have been submitted into the public record as part of PSC case No. 10-T-0139.
The project is an important piece of New York state’s clean energy strategy, importing emissions-free hydroelectric power to the largest U.S. city, which has very limited options for siting renewable energy generation within its own borders and relies instead on fossil fuel plants.
When completed, it will be the longest fully underground power line in the U.S., with an expected carbon impact equal to taking more than half a million internal-combustion-engine cars off the road per year.
NYISO considers CHPE important to New York state’s future grid reliability, so much so that if it is delayed, New York City’s transmission security margins could be deficient.
Some developments in the last 13 years:
The initial proposal was for two 1,000-MW HVDC circuits; it was subsequently revised to a single 1,000-MW line; in its final form, CHPE is a single 1,250-MW line.
CHPE had to deal not only with state and federal regulators but owners of the railroad grades where much of the overland portion of the line will be buried. It also had to negotiate payments to 132 taxing entities along the route (total cost: $1.4 billion over the first 25 years) and execute project labor agreements with more than a dozen unions.
The initial 2010 request to the PSC indicated the developers would seek a $2.3 billion loan guarantee; the price tag was publicly estimated at $2 billion in 2013; the PSC raised the debt ceiling to $4.5 billion in early 2022 and then $6 billion later in 2022.
The PSC approved construction and operation of CHPE in April 2013, but the docket shows very few filings over the next six and a half years; the PSC did not approve the CHPE contract until April 2022.
CHPE in August 2022 said it was pushing the estimated in-service date of the line back from late 2025 to the spring of 2026, because of regulatory delays and supply chain constraints; on Thursday it said only that the line would start delivering power in 2026.
A ceremonial groundbreaking was held in November 2022, but that was only for two staging areas; the PSC did not issue the notice to proceed with actual construction of the line until Feb. 27, 2023.
And as all this was happening, the 2,100 MW of emissions-free energy produced by the Indian Point nuclear plant — 20 miles north of New York City and right along the path of CHPE — went offline permanently; New York state codified a clean-energy transition; and New York City moved to ban fossil fuels in new construction, simultaneously reducing the supply and increasing the demand for clean energy well beyond whatever CHPE will provide.
As of Thursday, 4,574 documents have been filed with the PSC in the CHPE case, for everything from the overland rock removal permit to requests for nondisclosure to electrical drawings to a special hauling permit (cost: $40) for an oversized office trailer.
One of the newest documents, filed Wednesday, is an update on the regulatory situation on the other side of the border. It indicated three main authorizations are still required for construction of the Hertel-New York Interconnection Project, the roughly 35-mile underground line in Quebec that will connect to CHPE.
They are: authorization from the government of Quebec under the Environmental Quality Act; a permit from the Canada Energy Regulator; and authorization from the Regie de l’energie du Quebec (the Quebec Energy Board). All are expected by the end of this summer, the filing indicates.
Anticipating long lead times, Hydro-Quebec already has signed a contract with NKT to manufacture underground cables and is negotiating with NKT to install them. It expects to execute a contract with Hitachi to manufacture converter equipment shortly.
Hydro-Quebec is still negotiating property easements to site the line but has been authorized by the government of Quebec to take what it needs by eminent domain if necessary.
The PJM Board of Managers on Monday announced that it will seek a delay in the 2025/26 Base Residual Auction (BRA), scheduled for this June, as well as future auctions to allow the RTO and stakeholders to draft market changes to address reliability concerns.
“In arriving at this decision, the board recognized that, despite the implications of auction delay, reforms are necessary to the capacity market design in order to conduct an effective Base Residual Auction,” the board stated in a communication to stakeholders. “The board therefore determined that PJM should postpone executing any further auctions under the current rules until we go through the stakeholder process and file resulting rule change proposals with FERC.”
A special meeting of the Members Committee has been scheduled for April 4, during which PJM is set to provide an update on the delay and consult with stakeholders. PJM’s tariff requires that it consult with stakeholders at least seven days prior to making any Federal Power Act Section 205 filing. The board said that PJM will continue pre-auction activities if the filing is rejected by FERC.
The board did not specify an alternative date for the 2025/26 BRA, nor which subsequent auctions PJM will seek to postpone in an upcoming filing with FERC. But the RTO had presented three options for delaying future BRAs during past stakeholder meetings, including postponing the 2025/26 auction to May 2024. The following three auctions would also be delayed by sixth months under that alternative, bringing the auction schedule back to its normal cadence of three years in advance of the corresponding delivery year in May 2026 for the 2029/30 DY.
During a March 15 meeting of the Resource Adequacy Senior Task Force (RASTF), several stakeholders questioned whether it was too ambitious to expect an order from FERC and implement the changes, particularly if the commission issues a deficiency notice, before May 2024. PJM’s Adam Keech told the task force he heard stakeholder’s concerns that May could prove too optimistic and would share that with the board. (See PJM, Stakeholders Present Initial Capacity Market Proposals to RASTF.)
PJM spokesperson Jeff Shields told RTO Insider the RTO has no comment beyond the scenarios presented to stakeholders.
In a letter initiating the Critical Issue Fast Path (CIFP) process on revising the capacity market, the board asked stakeholders to provide feedback on whether any changes should be made effective prior to the 2027/28 BRA and whether that should include delays to the auctions. The letter lays out a series of concerns the board has with reliability in future years and requested that PJM and stakeholders draft proposals for a capacity market overhaul. The board aims to evaluate the recommendations and vote on a proposal to file with FERC on Oct. 1, 2023. (See PJM Board Initiates Fast-track Process to Address Reliability.)
Stakeholders provided mixed feedback over a handful of meetings, with supporters believing a delay would provide time to change the auction parameters to yield more accurate price signals, while opponents worried about the impact to state auction timelines and the possibility that the market change proposal could be delayed or rejected by the commission.
The GOP-led House on Thursday passed a fossil-fuel friendly energy infrastructure package that Democratic Senate Majority Leader Chuck Schumer said will be “dead-on-arrival” in his chamber.
H.R. 1, the Lower Energy Costs Act, passed on a 225-204 vote with just four Democrats voting in favor: Jared Golden of Maine, Marie Gluesenkamp Perez of Washington and Henry Cuellar and Vicente Gonzalez of Texas.
At the heart of the bill is a raft of changes to the Mineral Leasing Act, National Environmental Policy Act (NEPA) and Clean Air Act intended to accelerate the permitting of oil, natural gas and mining projects, in part by reducing environmental reviews and protests.
The bill directs the Department of the Interior to “immediately resume” quarterly onshore oil and gas lease sales, requiring four such sales annually in nine Western and Plains states, while increasing the fees associated with protesting the sales. It also seeks to streamline the permitting process for drilling for oil and gas in the Gulf of Mexico and off the coast of Alaska.
H.R. 1 would additionally roll back Obama-era restrictions on leasing of coal mines on public lands and ease the process for the mining of other materials, such as uranium and minerals considered critical to the supply chain of clean energy resources, such as lithium. It also restricts ownership of that supply chain by China-based entities.
But conspicuously absent from the bill are any of the kind measures that Democrats — including West Virginia Sen. Joe Manchin — and clean energy advocates have been seeking to expedite permitting of new electric transmission. (See Republicans Opening Offer on Permitting is Missing Electric Tx.)
After Thursday’s vote, House Speaker Kevin McCarthy (R-Calif.) tweeted that H.R. 1 is “an important bill that lowers energy costs, reduces global emissions and strengthens America’s national security” — although that second claim sparked criticism from Twitter users who pointed out the bill actually contains a provision to repeal the Inflation Reduction Act’s greenhouse gas reduction fund, which provided competitive grants, emphasizing projects that benefit disadvantaged communities.
Cathy McMorris Rodgers (R-Wash.), chair of the House Committee on Energy and Commerce, said the vote showed her party is “prioritizing the American people over the Democrat’s radical climate agenda.”
“Reform of our broken permitting process will spur greater energy production, boost economic growth, create jobs and bring down costs for American families. It will limit the threat posed by hostile nations like Russia and China,” said Sen. John Barrasso (R-Wyo.), ranking member of the Senate Committee on Energy and Natural Resources.
Reactions
House passage of the bill predictably received support from the fossil fuel sector and its allies.
“It is clear now that both Republicans and Democrats share the common goal of providing reliable energy to Americans and making energy safer, cleaner and more affordable,” American Petroleum Institute CEO Mike Sommers said in a statement. “This is a positive step towards enacting serious, bipartisan permitting reform, and we look forward to continuing to collaborate on real solutions that will modernize our infrastructure and benefit all Americans.”
Thomas Pyle, CEO of the American Energy Alliance, a group with financial ties to participants in the oil and gas industry, said the bill signals that Republicans “are keeping their promise to fight the Biden administration’s radical approach to energy policy.”
Pyle said the bill will reduce the U.S.’s dependence on China for minerals and mineral processing.
The National Rural Electric Cooperative Association (NRECA) called the development a “meaningful step forward” on permitting modernization, citing a provision to expedite reviews under NEPA and other federal processes.
“As threats to electric reliability mount and our nation increasingly relies on electricity to power more of the economy, it is critical that Congress streamline the process to permit, build and maintain the infrastructure that keeps the lights on across the country,” NRECA CEO Jim Matheson said.
Critics of the bill pointed to the lack of provisions pertaining to electric infrastructure.
Steven Nadel, executive director of the American Council for an Energy-Efficient Economy, criticized H.R. 1 for attempting to repeal energy efficiency and electrification investments from the Inflation Reduction Act, including the greenhouse gas reduction fund.
“This bill would leave many Americans continuing to live in homes with outdated heating equipment, poor insulation and high energy costs,” Nadel said. “This is a repeal of investments that enable households and businesses to make energy-saving improvements. It’s a repeal of funding for low-carbon technologies in low-income and disadvantaged communities. It’s a repeal of job training programs.”
Gregory Wetstone, CEO of the American Council on Renewable Energy (ACORE), said “any truly comprehensive permitting bill needs to help streamline the nation’s unworkable approval process for electric transmission lines.”
DOA — or Possible Compromise?
Wetstone also was among those calling for compromise as the bill heads to the Democrat-controlled Senate.
“We remain hopeful Congress can negotiate a bipartisan, bicameral solution this year,” Wetstone said.
Utah Gov. Spencer Cox (R) and Louisiana Gov. John Bel Edwards (D), co-chairs of the National Governors Association’s Energy and Infrastructure Working Group, issued a joint statement calling for Congress and the Biden administration “to work together to find common ground to improve the energy and infrastructure delivery process.”
A spokesperson for Sen. Joe Manchin, chair of the Senate’s Energy and Natural Resources Committee, said Manchin could see the bill becoming the foundation for a cross-party effort on permitting.
“Sen. Manchin is taking a close look at HR1 and is hopeful there might be a pathway to permitting legislation that could gain bipartisan support,” spokesperson Sam Runyon said in a statement.
But the response from other Congressional Democrats suggests H.R. 1 might not be the right vehicle for such compromise.
“By passing this legislation today, House Republicans are putting polluters over people. This bill is nothing more than a grab bag of Big Oil giveaways and loopholes that endanger the health, safety and security of Americans,” said Rep. Frank Pallone (D-N.J.), ranking member of the House’s Energy and Commerce Committee.
“The House has passed HR1 — the GOP ‘energy package’ that would gut environmental safeguards and lock us into dirty energy sources. It would set the U.S. back decades in our transition to clean energy,” Schumer tweeted Thursday. “HR1 is dead-on-arrival in the Senate.”
