ATLANTIC CITY, N.J. — The Bureau of Ocean Energy Management on Wednesday announced plans to open two new areas to offshore wind, one in the Central Atlantic and the other off of Oregon.
Central Atlantic call areas | Bureau of Ocean Energy Management
BOEM Director Amanda Lefton announced the calls for information and nominations at the Business Network for Offshore Wind’s International Partnering Forum, where about 2,700 members of the nascent industry gathered for several days of networking at the Atlantic City Convention Center.
The calls initiate comment periods through June 28 on “site conditions, marine resources and ocean uses” regarding the regions and invite OSW developers to nominate specific areas they would like offered for leasing.
BOEM is looking at six areas totaling almost 3.9 million acres in the Central Atlantic, all at least 20 nautical miles off the coast, and two areas totaling almost 1.2 million acres off of Oregon. The Coos Bay Call Area and the Brookings Call Area are 12 nautical miles from shore at their closest points.
The areas already leased in the Atlantic are all in relatively shallow water on the continental shelf, allowing fixed foundation turbines. Two of the six Central Atlantic call areas would be in deeper water off of the shelf. That location, and the Pacific sites BOEM is considering, would require use of floating turbines.
“Opening new lease areas in the Central Atlantic will spark a second wave of domestic offshore wind development and bolster an emerging manufacturing core in places like Hampton Roads and Baltimore, and in Oregon, where the power of offshore wind can be unleashed along on the West Coast,” said Liz Burdock, CEO of the Business Network for Offshore Wind.
The Biden administration has set a goal of 30 GW of offshore wind by 2030. In February, six companies offered almost $4.4 billion for leases representing 5.6 GW of offshore wind capacity in the New York Bight. (See Fierce Bidding Pushes NY Bight Auction to $4.37 Billion.)
A comprehensive economic study prepared by Cleveland State University concludes that diverting just 15% of Ohio’s current Utica shale gas production to create hydrogen would be sufficient to satisfy existing demand, mostly by the state’s petrochemical, fertilizer, steelmaking and refining industries.
But anticipated growth in demand for use in new technologies — such as blending with natural gas to fuel turbines generating electricity; replacing coke as a reducer in steel production; and fueling fuel cell electric vehicles (FCEVs) — along with traditional industrial use could outpace production of hydrogen from natural gas by 2050 when Utica shale gas production is projected to decline, the 76-page analysis concludes.
The study starts with the assumption that Ohio has an advantage over other states now competing for $9.5 billion in federal funding underpinning the Biden administration’s goal to foster the creation of regional “hydrogen hubs” that would use locally produced hydrogen.
“Ohio has several key advantages over other states in ramping up a hydrogen economy, beginning with its already significant industrial hydrogen market, led by the steel, petrochemical and fertilizer industries,” the analysis begins.
“In the coming years, Ohio will see these industrial markets grow and can leverage them to capture developing power generation, transportation and chemical hydrogen markets. This will be so because Ohio is also in a position to cost- effectively generate, store and deliver large volumes of hydrogen to supply these markets” the report reasons in a reference to the state’s enormous shale gas production. “This includes finding markets for carbon dioxide captured from hydrogen generation” from natural gas.
The state’s industries already produce 161,000 metric tons of hydrogen annually with steam methane reforming (SMR), according to the report, and it could probably meet all the anticipated demand. But relying solely on an increase in production through SMR would create more carbon dioxide that would have to be either sold to other industries as needed or more likely pushed into deep injection wells, adding another cost, according to the report.
The analysis assumes that a carbon tax will not be immediately enacted. While natural gas prices are expected to remain relatively low in the coming decades, other issues — the adoption of FCEVs in trucking, the use of hydrogen in steelmaking, and the cost of building a hydrogen storage and pipeline system — mean that developing an exact timeline is difficult to predict, the analysis warns.
“We know that near-term hydrogen will likely be supplied principally by natural gas via SMR. We also know that hydrogen infrastructure like SMR plants and pipelines have a useful lifespan of up to 50 years, and once built, those assets will not readily be discarded.
“Accordingly, Ohio is likely to be dominated by natural gas-based hydrogen for some time. Indeed, natural gas assets already exist in Ohio that could catalyze a hydrogen economy over the next 10 years, thus enabling Ohio to be a leader in hydrogen development. These assets also include an existing industrial hydrogen market supplied by natural gas.
“We also know that there will likely be a transition at least in part from natural gas to carbon-free forms of hydrogen, like those coming from electrolysis using nuclear and renewable power. How soon these are developed, and what fraction of the hydrogen they can supply, may depend upon regulation of carbon dioxide emissions.
A comprehensive economic assessment of efforts in Ohio to decarbonize heavy industry concludes that diverting 15% of the state’s shale gas output to hydrogen production could meet existing industrial demand but to meet anticipated demand growth by 2050, 15% of renewable generation and Ohio’s existing nuclear power will be needed. | Midwest Hydrogen Center of Excellence, at Cleveland State University
“Even without regulation, however, we can project that they will likely provide an increasing share of hydrogen production and by 2050 may even approach that provided by natural gas,” the report reasons.
Also by 2050, the study assumes that transportation, led by heavy trucking, will be the largest consumer of hydrogen in the state, while cars and light-duty trucking will have moved to battery EVs.
“We also project that heavy-duty trucks (Class 8) will be a major early consumer of hydrogen in the region, where refueling infrastructure can be built along interstate corridors. The Pittsburgh-to-Chicago I-76/I-80 corridor, for instance, is projected to use around 1,200 kg/day by 2030 and about 20,000 kg/day by 2040, even without zero-emission mandates,” the study notes.
Going Green
Working under the assumption that shale gas production will be in decline by 2050, the study turns to green hydrogen, which is produced by electrolysis using not only electricity from wind and solar but also from the state’s two nuclear power plants, Davis-Besse east of Toledo and Perry east of Cleveland.
Energy Harbor, the owner of the two power plants, is working with a $10 million U.S. Department of Energy grant on a facility adjacent to the Davis-Besse plant to use a portion of the reactor’s output to make hydrogen with a low-temperature electrolysis. The project is expected to begin production in 2023.
The study assumes that by 2050, 15% of the energy generated by Energy Harbor will have been diverted from the grid to produce enough hydrogen to meet the expected demand growth. And it assumes that renewable energy projects, primarily solar, will also have to contribute 15% of all energy generated in order to meet hydrogen demand.
“Ohio will likely be looking to supply this larger 3 million metric ton market at the same time that natural gas production from Utica Shale and other Appalachian formations are in decline,” the analysis warns.
“Ohio will need to develop a green hydrogen strategy to prepare for this scenario. Based upon current projections for Ohio generation capacity, if the state repurposed 50% of its nuclear and utility-scale renewable power fleets to make hydrogen for a 2-MMT/year market, it would still be required to support 70% of its hydrogen from steam methane reformation by 2050.
“A 3-MMT/year market will only require more natural gas. Further, 50% repurposing of nuclear and renewable power will put a significant strain on Ohio’s grid, which already imports around 25% of its power.
“Accordingly, Ohio industries will need to plan for both blue and green hydrogen sources to supply Ohio’s anticipated hydrogen demand. It will need to develop strategies for using or sequestering carbon dioxide captured from steam methane reforming processes. And it will need to ramp up its green power generation fleets to replace natural gas over time. This will include extending the life of its nuclear power plants and significantly increasing its fleet of utility-scale renewable power.”
The study was also sponsored by Jobs Ohio, a private economic development group created by the state, and the Stark Area Regional Transit Authority, a regional transit system with 20 fuel cell electric buses. The research was led by Mark Henning and Andrew Thomas of the Energy Policy Center at Cleveland State University’s Levin College of Urban Affairs.
A Seattle-based wind developer has applied for permission to build a floating offshore wind facility in the Pacific Ocean off Washington’s coast.
Trident Winds this month submitted an unsolicited lease request to the U.S. Bureau of Ocean Energy Management (BOEM) to build up to 2,000 MW of floating offshore wind (FOSW) roughly 43 miles west of Grays Harbor and Aberdeen, Wash., at the southern edge of the Olympic Peninsula.
The Olympic Wind project has the potential to become the first FOSW wind farm off Washington’s coast — and the West Coast.
Trident Winds has not determined the number and capacity of individual turbines needed, or the size of the floating platforms, company CEO Alla Weinstein told NetZero Insider. The expected budget has not been nailed down, but construction would begin in 2028 and finish in 2030, if Trident Winds obtains a green light from BOEM.
“There is a lot of interest,” Weinstein said. “There is a lot of [investor] money available.”
Trident is choosing to locate the site 40 miles offshore to avoid shipping lanes and U.S. Navy ship routes, Weinstein said. The location’s average wind speeds are eight meters per second, and the winds peak in winter, she said.
A derrick-like offshore wind turbine usually needs to reach 100-200 feet below the ocean’s surface. Weinstein said the Olympic project will likely be held in place by cables reaching to depths of 700-1,000 feet.
BOEM will review the proposal to confirm that Trident meets federal legal, technical and financial qualifications to hold a lease on the outer continental shelf for offshore wind turbines. If the company qualifies, the federal agency will advertise for other potential developers to bid for the site.
Weinstein founded another company, Principle Power, that made an unsolicited lease request for a wind farm off the Oregon coast in 2013, she said. That project died during discussions with state and federal officials.
The U.S. is putting near-term initiatives into play to reduce long-term EU dependence on Russian LNG without disrupting climate goals, according to Melanie Nakagawa, special assistant to President Biden.
Melanie Nakagawa, special assistant to the president and senior director for climate and energy at the National Security Council | Center for Strategic and International Studies
“There’s real potential for Europe to signal the demand for U.S. LNG and for our U.S. LNG suppliers to provide that gas to them in the form of long-term contracts,” Nakagawa said Tuesday. “We can provide this gas in a way that is climate-aligned.”
Over the next five years, Europe wants to eliminate Russian gas imports, which make up 40% of the region’s gas consumption. In March, the U.S. and EU formed an energy security task force in response to Russia’s invasion of Ukraine, setting simultaneous goals of increasing U.S. LNG supply to Europe this year and ensuring demand in Europe for U.S. LNG through 2030.
Despite existing gas infrastructure limitations, meeting the long-term goal is possible with uncontracted volumes from facilities that are permitted or under construction in the U.S., Nakagawa said during a Center for Strategic and International Studies (CSIS) panel discussion. U.S. Energy Information Administration data show that U.S. liquefaction capacity will surpass the capacities of the top two global LNG exporters by the end of this year. And additional capacity is expected to come online in 2024.
“Through the task force, we’re engaging with key industry players that have the ability to move their volume to Europe,” Nakagawa said. “We’re talking to European member states that have indicated a willingness and an interest in building the import capacity to absorb this additional gas by 2025-2026.”
The key to making long-term LNG contracts feasible under U.S. and EU decarbonization plans is to put technologies, policies and incentives in place that reduce the carbon intensity of natural gas, she said.
In the U.S., Nakagawa sees policies for methane regulations and incentives for carbon capture and storage deployment as essential pathways for LNG suppliers. Powering LNG production processes and facilities with clean energy, she added, also will drive further emission reductions.
And in Europe, she said, the development of hydrogen-ready infrastructure and a green hydrogen economy will ensure the demand side supports decarbonization through 2050.
The long-term LNG contracts themselves also can include an element of flexibility so that Europe is not locked into the supply. Contract terms could allow for the resale of the contract so the supply can move to another region where it may be more beneficial depending on market forces, Nakagawa said.
“We see that in the U.S., where we have destination-flexible contracts,” she said. “Volumes and cargoes have been moving from one destination to another over the past several months.”
CSIS Viewpoint
The U.S. should be able to help cut Russian LNG exports through increased production without increasing greenhouse gas emissions, but that will take “creative policies,” according to Nikos Tsafos, CSIS’ James R. Schlesinger chair for energy and geopolitics.
Addressing a secure LNG supply in the middle of the Russia-Ukraine war and keeping climate targets in mind will require more voices at the table, he said in a presentation on a CSIS report on energy security and climate.
“There’s been a lot of effort from the U.S. government on the diplomatic front to figure out a way to reallocate energy supplies so that more goes to Europe,” he said. “We think that this is something that should be expanded and try to be more inclusive; try to bring in the major players and talk about how we’re going to manage the market.”
Those major players should include the U.S., Australia and Qatar as exporters and China, Japan, Korea, India and the EU as importers.
“You can’t really manage this market purely through price,” he said, adding that buyers and sellers can work together to manage the market while there is “enormous stress.” The process would allow for streamlined decision-making and opportunities to reduce imports, according to the report.
Signaling a need for U.S. LNG developers to expand capacity would support long-term reductions in Russian exports, but the current market signals are “a mess,” Tsafos said.
There are “relatively straightforward” alternatives to expand supply quickly without “locking in emissions” in the long term, he said. Public money, for example, can support the development of LNG projects that are eventually returned to state control, unless they are meeting net-zero-emissions goals, according to the report. Further restrictions can be set related to project methane emissions to qualify for public funding.
As New England wrestles with building the new transmission infrastructure it needs to fuel the clean energy transition, a new effort by the region’s grid operator could help bring some relief that doesn’t come in the form of wires.
ISO-NE is developing a process for allowing energy storage projects to be used as transmission assets.
Storage-as-transmission-only assets (SATOA) would be energy storage devices connected to the grid that can “inject stored power to address transmission system concerns,” ISO-NE’s Brent Oberlin told the NEPOOL Transmission Committee at its April meeting.
The proposal would be technology agnostic, and the projects could come in the form of batteries, air, water or even “large concrete blocks on cranes,” Oberlin said, referencing a Swiss clean energy firm called Energy Vault.
ISO-NE is moving forward on allowing SATOAs after a number of stakeholder requests but said that it will have to be careful to avoid both compromising reliability and significant impacts on the markets.
Toward that goal, the grid operator is setting several limits on its initial plans to allow the projects, which will have to advance through the NEPOOL stakeholder process and ultimately be approved by FERC.
In transmission planning, SATOAs would be limited to being discharged in post-second contingency (post N-1-1). And in operations, they would be “used as a last step to avoid load shedding or criteria violations,” Oberlin’s presentation said. They could only be operated after all other market-facing resources were exhausted.
SATOAs would not be allowed to participate in the region’s wholesale markets. They would only be paid through the transmission cost recovery process.
The initial proposal from ISO-NE would also set size limits, with individual stations not being allowed to exceed 30 MW of charge or discharge capability and total SATOAs in New England limited to 300 MW.
Industry Reactions
Energy storage advocates said that the rollout was a welcome first step, but the process has a long road to implementation.
“Given the transmission investments that will be needed to reach the region’s clean energy and decarbonization commitments, we’ll need every tool and technology available to do that as cost-effectively as possible, and allowing storage to solve transmission needs is a step that we’ve been asking ISO-NE to take,” said Caitlin Marquis, director of Advanced Energy Economy. “The real question will be whether the changes result in storage being considered and selected to meet transmission needs in practice.”
Jason Burwen, vice president of energy storage at the American Clean Power Association, said that ISO-NE’s caution as it develops a process for SATOAs is unsurprising.
“I think ISO-NE is going in with a fairly conservative stance, understandably so, to make sure that its market participants understand that they are going to be watching out to make sure the use cases of these assets are narrowed to when they are really truly for transmission reliability purposes,” Burwen said.
Utilizing SATOAs requires outside-the-box thinking for grid operators, he added.
“It’s really figuring out how to work them into a framework that has traditionally not looked at this as a solution. And that’s always going to be a lot of thinking through complex and challenging topics,” he said.
The MISO Model
In trying to bring in storage projects as a transmission solution, New England is following in the footsteps of other parts of the world, including Australia and parts of Europe, as well as elsewhere in the U.S.
Most notably, MISO has developed a SATOA framework that led to a project currently under development in Waupaca, Wis. The $8.1 million, 2.5-MW project was found to be cheaper and easier to site than a transmission line rebuild that was also under consideration. It’s set to come online later this year.
Now debate in MISO has evolved toward some of the same questions that New England stakeholders are wrestling with: whether the project and others like it can participate in the electricity markets too.
The project’s owner, American Transmission Co., is looking for a way to both participate as a transmission solution and in the region’s energy market, but right now it has no avenue to do so.
MISO has discussed allowing one-off agreements for storage projects that want to do both in the interim to give itself time to think about the rules it wants to put into its tariff, but some stakeholders have urged it to use a deliberate process. (See MISO Market Subcommittee Briefs: Jan. 27, 2022.)
FERC’s proposed transmission planning and cost allocation rulemaking Thursday was a welcome victory for Chairman Richard Glick (D), coming a month after having to walk back a controversial pipeline ruling, and two months before the end of his current term on the commission.
“This is a big deal, a great step and one that is moving forward with bipartisan consensus,” tweeted former Commissioner Neil Chatterjee, a Republican who had frequently clashed with Glick. “Not easy to do on matters that are complex and contentious.”
The NOPR also won praise from groups including the American Council on Renewable Energy, Business Council for Sustainable Energy, Natural Resources Defense Council and Edison Electric Institute, which said it would get new wind and solar connected to the grid while adding resilience.
Glick “forged more consensus than people imagined possible on very tough and complex substance,” said Seth Kaplan, director of governmental and regulatory affairs at offshore wind developer Ocean Winds.
But the proposal also is a retreat from Order 1000’s drive to open transmission development to competition: It offers to give incumbent transmission owners a federal right of first refusal (ROFR) on regional projects on the condition that they partner with an unaffiliated company with a “meaningful level of participation and investment” in the project.
The commission said it was changing course because it feared that Order 1000’s removal of the federal ROFR may be “inadvertently discouraging investment” in regional transmission. Incumbent transmission providers “may be presented with perverse investment incentives” to instead engineer local transmission projects for which they retain development control, the commission said.
Regional transmission facilities subject to competitive procurements represent only a small portion of transmission investment in recent years, it said.
In Order 1000, the commission found that federal ROFRs create “a barrier to entry,” discouraging nonincumbent transmission developers from proposing alternative solutions that could be more efficient or cost-effective. But FERC’s order could not eliminate ROFRs authorized by state laws, and state legislatures in Iowa, Minnesota, North Dakota, Michigan, South Dakota and Texas have supported such protections for their utilities.
‘Practical Reality’
In regions with state ROFRs, “there’s not a practical opportunity for third-party transmission,” said Rob Gramlich, president of consulting firm Grid Strategies. “So, in some sense, I think the commission is just reflecting the practical reality.”
“Competitive transmission is like a 4.8-degree of difficulty in diving. Generation is way easier,” Gramlich continued. “There’s been a 40-year consensus on competitive generation. Not that we have it everywhere, but at least the economic policy is agreed to by every economist who looks at it. In transmission, it’s just harder and it hasn’t worked out well.”
Larry Gasteiger, executive director of WIRES, which represents utilities promoting grid investment, said the commission appeared to be prioritizing transmission development over competition.
“The bigger goal was getting the needed infrastructure built and put in place over other processes,” he said. “I think it’s an acknowledgement by the commission that competition — as it was set forth in Order 1000 and has been implemented for the last 10 years — really hasn’t been working in terms of getting needed transmission infrastructure built. … So we were pleased to see that there wasn’t a further expansion in that direction and, in essence, a doubling down on what wasn’t already working.”
Jeff Dennis, general counsel and managing director of Advanced Energy Economy, said the commission “is looking to build as many coalitions as possible that can move transmission forward.” AEE represents businesses favoring carbon-free energy and electrified transportation.
“Certainly, one could surmise that the commission is sort of offering this renewal of the federal right of first refusal in exchange for incumbents opening the opportunity to invest in transmission to more entities,” he added. “The commission … hasn’t made this kind of political calculation transparent, but one could imagine that is one thing they are trying to do.”
Ed Tatum, vice president of transmission for American Municipal Power (AMP), acknowledged Order 1000 had fallen short, but added, “I’m not sure if elimination of ROFR is the right solution.”
Instead, he said, FERC should adopt the planning process changes that AMP and others proposed in the PJM stakeholder process, which have been rejected by the commission. (See FERC Rejects Challenges to Decision on EOL Projects in PJM.)
AMP and its allies are pressing their case before the D.C. Circuit Court of Appeals. “I think we have a better solution,” Tatum said. “But it might take the courts to help FERC see that.”
Limited Regional Transmission Investments
In the NOPR, the commission indicated dismay that “despite increased investment in transmission facilities overall … recent transmission investment appears to be concentrated in local transmission facility development or regional transmission facilities subject to an exception from competitive transmission development processes, such as immediate-need reliability projects or upgrades to existing transmission facilities, as opposed to investment in regional transmission facilities.”
Baseline and supplemental projects by year | PJM
Although there has been wide acknowledgement that Order 1000’s efforts to open up competition have had only limited success, commenters in the docket were divided on how FERC should respond.
Some, including the California Public Utilities Commission, called for more competition. NRDC, Sierra Club and other public interest organizations said FERC should require transmission providers to plan for local transmission needs as part of the regional planning process. The National Association of Regulatory Utility Commissioners urged FERC to discourage overinvestment in local transmission facilities.
But EEI asked the commission to “remove the complex and costly competitive processes” that it said is delaying transmission development.
FERC noted investment in regionally planned transmission has declined in some regions, including PJM, which averaged $2.76 billion in annual spending on regional transmission from 2005 to 2013 and only $1.65 billion from 2014 to 2020.
Baseline and supplemental projects since 2005 (adjusted by peak load) | PJM
Given the experience since the issuance of Order 1000 in 2011 and the comments it received in this docket, FERC said, it concluded that the order’s elimination of all federal ROFRs for new regional facilities “was overly broad,” resulting in “potentially flawed investment incentives that may be restraining otherwise more efficient or cost-effective regional transmission facility development.”
“Order No. 1000 failed to recognize that at least some of the most notable expected benefits from competitive transmission development processes (e.g., new transmission developer market entry, greater innovation in and potentially lower costs of transmission development) could be achieved or at least reasonably approximated through other means.”
Joint Ownership Proposal
ACEG’s Gramlich and others said they were intrigued by the proposal for joint ventures, a model they said has proven successful in MISO’s Multi-Value Projects and CapX2020, in which 11 transmission-owning utilities in Minnesota and surrounding states built nearly 800 miles of 345-kV and 230-kV transmission. In addition, LS Power Grid New York (formerly North America Transmission) teamed up with the New York Power Authority to win state approval for the New York AC project.
“The public power community has always advocated for more joint ownership,” Gramlich said.
AEE’s Dennis said enlarging the circle of those involved in planning and developing transmission “builds more and more support for determining that those projects are needed, brings in more sources of capital, including low-cost capital from not-for-profit, municipal entities and things like that. That helps move those projects forward.”
Dennis said there would likely be opposition, however, to a final rule that allowed “incumbent transmission owners being able to essentially ally with each other to exercise a right of first refusal.”
‘Right-sized’ End-of-life Replacements
While the commission’s retreat on the federal ROFR would be a win for incumbent TOs, the commission also proposed new procedures to increase transparency on the TOs’ local transmission upgrades.
The NOPR would require transmission providers to include in their long-term regional transmission planning an evaluation of TOs’ plans to replace aging transmission facilities of 230 kV and above to determine whether they “can be ‘right-sized’ to more efficiently or cost-effectively address regional transmission needs.”
It also expressed concern that local transmission planning processes may lack adequate transparency and stakeholder input, resulting in duplicative spending that increases costs for consumers. The commission noted that local transmission facilities are included in regional plans only as “inputs” for modeling of their reliability impacts, “with minimal opportunity for stakeholder review.”
“My initial read of it is it may not be a very dramatic change at all, in terms of how things are currently operating,” said WIRES’ Gasteiger. “Frankly, I think that’s pretty much being done in most regions right now.”
But Gramlich said it “could potentially be huge, particularly because we have so many transmission assets around the country that are well over 50 years old that will need to be replaced. And the practical limitations on developing new rights of way are so extreme that one of the best opportunities to expand capacity is to expand capacity over existing rights of way.”
Gramlich said there has been poor coordination between local and regional transmission upgrades.
“I’ve heard the heads of very large transmission owners in some of the RTOs say that it was working a lot better before Order 1000. Because it used to be that any upgrade they would identify on the local system, they would bring to the RTO, and the RTO would consider a more optimal regional solution,” he said. “And then Order 1000 came along with the requirement to competitively bid anything in the regional process, and that [coordination] largely shut down.”
Dennis said the change could be significant “if the transparency requirements are paired with accountability … meaning ultimately that there is a consequence to building more expensive, less-than-optimal options.”
AMP’s Tatum questioned the 230-kV cutoff. “There’s a whole lot in the [interconnection] queue I believe that is on transmission facilities below 230 kV,” he said.
Order 890 required that transmission providers’ local transmission planning comply with nine principles, including coordination, openness, transparency and information exchange. “However, implementation of these principles in local transmission planning processes appears to remain uneven,” FERC said.
The NOPR would require transmission providers hold at least three stakeholder meetings on each local transmission planning process: one on the criteria, assumptions and models used (Assumptions Meeting); a second on identified reliability criteria violations and other transmission needs (Needs Meeting); and last a review of potential solutions (Solutions Meeting).
Transmission providers would be required to evaluate whether any facilities rated at or above 230 kV that are planned for replacement during the next 10 years can be “right-sized” to more efficiently address regional transmission needs. “Right-sizing could include, for example, increasing the transmission facility’s voltage level, adding circuits to the towers (e.g., redesigning a single-circuit line as a double-circuit line), or incorporating advanced technologies (such as advanced conductor technologies),” FERC said.
Because the proposed rule would not change existing law allowing the incumbent TO to proceed with developing its planned in-kind replacement transmission facility without right-sizing, the commission said it would establish a ROFR for such facilities located within the utility’s retail distribution territory.
Only the incremental costs of right-sizing the transmission facility would be subject to regional cost allocation.
State Role
Dennis said he was pleasantly surprised by the commission’s effort to engage states in regional transmission planning and cost allocation. “I think that, paired with the requirements for much longer-term, multiple scenario-based planning, that [effort] really addresses the reality of what’s happening on the electric system and the resource mix changes that are occurring,” he said.
“By giving them that opportunity to engage up front, they are also giving the states the ability to really shape what regional transmission plans look like and to really say upfront, ‘These are things that we think will benefit our customers’ … instead of just having transmission be something that happens to them.”
The NOPR’s proposed requirement to seek state agreement on cost allocation “was a clear concession to Commissioner [Mark] Christie [R], as part of getting him on board,” Gasteiger said.
Gasteiger, who served in senior roles at FERC under Chairs Joseph T. Kelliher and Norman Bay, said it was essential that Glick won bipartisan support for such a sweeping rulemaking.
“On something of such potentially great significance … the commission [must] act on a bipartisan, if not unanimous, basis, and certainly not on a partisan basis, a 3-2 vote,” Gasteiger said. “And you don’t need to look any further than the pipeline certificate policy statement to see why that’s important.” (See FERC Backtracks on Gas Policy Updates.)
“I was glad to see that the commission made a strong effort to produce a bipartisan decision on this,” he continued. “It always involves a lot of compromise, and nobody gets exactly what they want. But it provides a lot more certainty to the industry and a lot more durability to the commission’s actions.”
After having praised the consensus-building, however, Gasteiger expressed some concern over the state role that helped win Christie’s vote.
“Generally speaking, more process doesn’t lead to getting more transmission built in a timely basis,” he said. “So the devil will be the details and in the implementation of what they’ve put in place. But I do have a concern with elevating or expanding the role of states in the process, and creating more process. What will that mean for actually getting transmission infrastructure built?”
New Jersey on Thursday announced grants of $7.6 million to fund local government purchases of electric trucks, ambulances and other vehicles in an effort to cut transportation emissions and promote municipal electric vehicle use in a strategy that officials also hope will influence private buyers to go electric.
The New Jersey Department of Environmental Protection (DEP) said $6.6 million, a tranche received from the state’s participation in the Regional Greenhouse Gas Initiative, would pay for the purchase of electric garbage and refuse trucks, two ambulances, dump trucks and a rear loader truck, along with charging stations for some of the vehicles. A $600,000 grant would go to help Jersey City, the state’s second largest city, develop an e-mobility program that will reduce vehicle miles traveled through an electric car-sharing program.
The announcement, timed to coincide with Earth Day, came the same day that Paterson, the state’s third largest city, announced its purchase of 38 EVs for use by fire, housing and health inspectors and the city’s Department of Public Works. The $210,000 grant to help Paterson purchase a fleet of Nissan Leafs was the largest award in a fund of $1 million awarded by the New Jersey Board of Public Utilities (BPU) to 16 municipalities under the Clean Fleet Program, which is designed to support EV purchase by local governments. The remainder of the awards range from $37,500 to $40,000.
Gov. Phil Murphy has set a target of putting 330,000 EVs on state roads by 2025. The state had 64,000 light-duty EVs in December, up from 48,000 in June and 41,000 in December 2020, the BPU said.
DEP Commissioner Shawn LaTourette said the $6.6 million award “will enable us to confront environmental challenges head on.”
“The range of vehicles to be purchased with this latest investment will also demonstrate a broad suite of successful electric vehicle applications,” he said.
Cathleen Lewis, e-mobility program manager for the BPU, said the sizable increase in the uptake of EVs over the last six months, which followed the state’s implementation of programs designed to motivate private citizens to purchase EVs and chargers, suggests that the state is making progress toward the 2025 goal.
That shift should be further helped by the funding of municipal vehicle purchases, Lewis said. Government purchases can set an example that will help private citizens overcome concerns such as range anxiety.
“When people see things going on to municipality, they take notice,” she said. “The more that residents see EVs in use, the more confident they are that they are going to be able to use them. [They think], ‘if the town can use it and drive around in it all day, then me going back and forth to my office is not an issue; I clearly can find places to charge.’”
Cutting Idling Emissions
Transportation accounts for about 40% of New Jersey’s emissions. The state in July launched the second year of a program that awarded up to $5,000 to help purchase an EV, but heavy demand exhausted the $30 million in available funds for the incentives in two months. (See NJ Proposes Cutting EV Incentives Amid Big Demand.)
The state has also taken a series of initiatives aimed at increasing the development of charging stations around the state, including reducing the requirements for approval and awarding incentives to help develop stations. The state approved the Clean Fleet Program in August. (See NJ Backs EV Incentive Program for Local Government.)
Paterson, which was founded in 1792 by Alexander Hamilton as the first planned industrial center in the U.S., celebrated the purchase of its EVs by parking three of the vehicles in front of City Hall, presenting a contrast between the vehicle’s status as a harbinger of the state’s potential clean energy future and the state’s historic industrial past.
The new EVs cost $22,920 each through the state’s bulk purchasing system, with BPU funds paying about $6,000 of that, said Fire Chief Brian McDermott, who oversaw the purchase. The vehicles do about 150 miles on a single charge and are a good fit with the demands of the inspectors in a city that is only 8.4 square miles in size.
The inspectors only drive about 30 miles a day but spend a lot of time in the vehicle idling and — if the vehicle is gas-powered — generating carbon emissions, McDermott said. In about eight weeks, the EVs will begin replacing the inspectors’ current vehicles, which include models such as Jeep Liberty, Chevrolet Caprice and Ford Escape, he said.
“For most inspectors, their vehicles are their office,” he said. “So, what do they do when they’re sitting there, on a street corner in between inspections? They leave the car on. They’re looking at their papers. They’ll have their iPad. They’ll do an inspection, then they’ll [sit idling and] prepare for the next inspection.”
He said the city expects each car to be recharged once a week, mostly in off-peak hours to reduce the cost of the electricity used. So far, there are no chargers anywhere in Paterson, he said. But the city expects soon to install them at a firehouse, in the health department building and in the parking authority, he said.
The chargers will be a mix of Level 3 chargers, which can recharge the vehicles in about 45 minutes, and Level 2 chargers, which can recharge them in eight hours, he said. But given the low weekly mileage done by inspectors, he said he expects the cars will often be brought back to full charge in half that time.
Maine Senators voted 19-10 Monday to pass Gov. Janet Mills’ utility accountability bill with an amendment that removed language related to a consumer-owned nonprofit takeover of the state’s investor-owned utilities.
The bill (LD 1959) directs regulators to seek bids for an IOU if it “consistently fails” to meet specific service standards. Legislators, however, did not include the governor’s proposal for an administration-led committee to supply regulators with a bid from a consumer-owned utility (COU).
Mills introduced her utility bill after vetoing a similar bill last year that provided for a COU takeover without a competitive bidding process. LD 1959 passed the House of Representatives last week and now goes to the governor for approval.
As amended, the bill strengthens a provision for imposing an administrative penalty on IOUs for not meeting service standards in a calendar year, allowing for up to a $1 million fine per year. Persistent problems with service would trigger an adjudicatory hearing by the Public Utilities Commission to determine if divestiture to a “qualified buyer” is warranted. The commission would adopt standards for service quality, customer service, field service and interconnection of distributed energy resources.
The amendment added an integrated grid planning provision that supports a “transition to a clean, affordable and reliable electric grid in a cost-effective manner.”
Utility regulators would be required to initiate a proceeding this fall to identify priorities that the state’s IOUs must address in grid planning to help with that transition. Plans would include load forecasts, energy supply data, hosting capacity analysis, emerging grid technologies analysis, and equity and environmental justice analyses.
The amendment also adjusts Mills’ proposal for utilities to file 10-year action plans to address the effects of climate change on grid assets from every two years to every three years.
“For too long we’ve failed to take action to address the failures of [Maine’s IOUs],” said Sen. Stacy Brenner (D), lead sponsor of the bill, in a statement. Supporters of the bill point to historically low customer satisfaction metrics for Central Maine Power and Versant Power as justification for new service standards.
“This bill will ensure our utility companies put the needs of their customers first, that we’re planning a power grid that is reliable and ready for Maine’s independent energy future and that we help protect ratepayers,” Brenner said.
Amid a flood of comments last week on ISO-NE’s proposal to delay elimination of its contentious minimum offer price rule, the most significant came from Massachusetts’ top energy official (ER22-1528).
In a letter to FERC, Massachusetts Energy and Environmental Affairs Secretary Kathleen Theoharides expanded on the state’s position, separating it from a coalition of the other New England states by calling on the commission to order the immediate removal of the MOPR.
“The commonwealth supports elimination of the MOPR but opposes an approach to elimination that prolongs the effects of the MOPR any longer than necessary,” Theoharides wrote. “I urge the commission to use its regulatory authority under the Federal Power Act to direct changes to the ISO-NE’s tariff by taking the fewest risks and least time necessary to eliminate the MOPR.”
The New England states, through the New England States Committee on Electricity (NESCOE), had previously said that they would not oppose the two-year transition proposal put forward by the grid operator. It was a near-consensus (barring New Hampshire) position that has been cited repeatedly by ISO-NE, serving as a powerful message to other stakeholders and helping secure enough votes for the grid operator’s proposal to ultimately pass through NEPOOL.
NESCOE reiterated its position in a comment, noting that its lack of opposition to the delay comes with the major caveat that the group will “fiercely oppose any attempts to extend the deadline for full MOPR reform beyond [Forward Capacity Auction] 19.”
And Connecticut stayed in line with the NESCOE position, writing in its own comments that it does not oppose the delay because of worries about the “fragile state of the ISO-NE markets” and the possible negative effects of immediately removing the MOPR.
NESCOE declined to comment specifically on Massachusetts’ new stance, saying that its views are reflected in the filing.
Protests and Support
The states’ comments were among more than 200 submitted by advocacy groups, companies and individuals ahead of last Thursday’s deadline on an issue that has gathered an unusual amount of scrutiny for the grid operator. (See ISO-NE Sends MOPR Filing to FERC, Teeing up Big Decision.)
A large consortium of environmental groups filed a protest asking FERC to order the MOPR be immediately removed.
“ISO-NE’s [FPA] Section 205 filing offers the commission a chance to reconsider the unjust, unreasonable and unduly discriminatory rates that have resulted from the string of commission orders establishing ISO-NE’s current tariff and MOPR rules,” the groups wrote.
They said that keeping the MOPR in place for another two years will keep state-sponsored clean energy resources from clearing the capacity market and impose higher costs on consumers. They also challenged the credence of the reliability worries that have been cited by ISO-NE in extending the MOPR for two more years.
“Despite the ISO’s substantial analytical capabilities and unique access to data — all funded by ratepayers — the ISO’s case for reliability needs contained in its filing is limited to extremely general and speculative concerns about capacity accreditation, retirement of existing resources and potential commercial-operation delays applicable to all new entry in the region,” the protest says. The American Council on Renewable Energy also filed its own separate protest.
Writing in support of the ISO-NE proposal were groups representing power generators and suppliers in New England and nationally, as well as several individual companies.
“The filing strikes a just and reasonable balance among a wide range of stakeholder and ISO-NE interests; is supported by a large majority of NEPOOL, including supporting votes from each of the six NEPOOL sectors; and is the product of input from, and is unopposed by, the New England States Committee on Electricity,” the New England Power Generators Association wrote. “This alignment is remarkable on a market design issue that has compelled countless pleadings and disagreements among stakeholders and policymakers in New England.”
The Electric Power Supply Association concurred and called the filing a “balanced set of revisions.”
Filing together, the three generation companies that had originated the proposal to delay elimination of the MOPR by two years — Calpine, Cogentrix Energy Power Management and Vistra — defended the ISO-NE proposal as a necessary safeguard that was developed and approved through a sturdy stakeholder process.
“It is critical that ISO-NE adopt a transition mechanism that appropriately balances the various interests of consumers and investors while making it easier for sponsored policy resources to enter the [Forward Capacity Market]. The specific transition mechanism ISO-NE has proposed accomplishes those goals in a just and reasonable manner,” they wrote.
Hawaiian Electric Company (HECO) this month withdrew its plans to build a key battery storage system on Oahu just months after applying to develop the project. Tight deadlines and supply chain issues appear to be the reason for the cancellation.
The proposed West Loch Battery Energy Storage System (BESS) would have consisted of 80 MWh of storage capacity intended to cover a portion of the potential energy shortfall stemming from the planned shutdown of the AES Hawaii Power Plant this September. The 180-MW, coal-fired plant supplies about 20% of Oahu’s electricity. (See Hawaii PUC Weighs Coal Plant Closure Options.)
Over the past year, HECO vacillated on its plans for building the BESS in the West Loch area of Pearl Harbor, the site of an existing 20 MW solar facility. In January, the utility finally applied to the Hawaii Public Utilities Commission for expedited approval to begin initial work on the $2.5 million project, contending that quicker review “would improve the likelihood that the Company could successfully capture this opportunity, as the manufacturing capacity may be sold by the battery supplier at any time” (2022-0019).
In approving HECO’s down payment for the project in February, the PUC cautioned that it would not allow the utility recovery of those initial costs if the project was rejected after more thorough review.
The regulator also warned that “there is no guarantee that HECO will not encounter delays or additional obstacles, due to ongoing global manufacturing and supply chain issues relating to the batteries and/or any other components of the Project, as well as other factors.”
HECO’s cancellation suggests the foresight of that warning.
According to an April 12 PUC order approving the project withdrawal, the company supplying the BESS notified HECO that it would be unable to deliver materials this year, prompting the utility to withdraw its application.
In an email to NetZero Insider, HECO said that both the reasons for the delays and the name of the battery supplier itself are proprietary information.
But the utility noted that it had few specific details about the delay, saying the supplier “just told us” that the equipment delivery would not arrive on time. Other Hawaii clean energy projects, such as the Hale Kuawehi solar project on the Big Island, have recently been subject to delays — and even cancellations — due to supply chain issues stemming from the COVID-19 pandemic.
HECO said the AES coal plant will still be decommissioned on schedule and expressed confidence that its other renewable energy projects can handle any energy shortfalls.
“Hawaiian Electric has initiated several contingency programs to boost generation reserves and increase reliability in preparation for the retirement of AES, such as Fast DR, Battery Bonus, Grid Services procurements, energy efficiency and public education on energy conservation,” the utility said.
The PUC last year approved HECO’s plan to spend $34 million to create an emergency demand response program that will rely on residential solar and battery systems to make up to 50 MW of DR available to the utility in the face of energy shortfalls. (See Hawaii Approves EDRP Plan for Oahu.)
“This [battery] project was never intended to be the sole replacement for the coal plant,” the PUC said when reached for comment.
HECO estimates that it will complete three solar-plus-storage projects on Oahu by the end of the year: AES Waikoloa Solar (30-MW/120-MWh), Mililani 1 Solar (39-MW/156-MWh) and Waiawa Solar Power (36-MW/144-MWh).
It also suggested that the West Loch site could host another battery facility in the future.
“It was always in the plans for the West Loch PV facility to accommodate a BESS,” the utility said.
Central Atlantic call areas | Bureau of Ocean Energy Management
