Nevada is poised to be at the center of a robust and interconnected transmission system in the Western U.S., but the state must move quickly, the chairman of a new task force said Tuesday.
Speed is necessary because of the extended time it takes to develop new transmission projects, said Nevada state Sen. Chris Brooks (D), who chairs the Regional Transmission Coordination Task Force. The group held its first meeting on April 26.
And Nevada faces competition from other states, Brooks noted.
“We are not alone in this,” Brooks said. “We are in a race with our neighboring states to really take full advantage of our position here in the West.”
During the 2021 session Brooks was the sponsor of Senate Bill 448, wide-ranging energy legislation that included creation of the task force. Gov. Steve Sisolak signed the bill into law in June and appointed the group’s members in December. (See Nevada Gov. Sisolak Appoints Regional Tx Task Force.)
SB 448 requires transmission providers in the state to join a regional transmission organization by Jan. 1, 2030, although providers may be able to receive a waiver of the deadline.
The task force’s work will complement that goal. The mission of the 21-member panel is to advise the governor and lawmakers on the potential costs and benefits of the state joining or forming an RTO.
The group will explore policies that would support the state entering an RTO by Jan. 1, 2030.
It will look at the siting of transmission facilities needed to reach the state’s clean energy and economic development goals.
And it will evaluate which businesses and industries could move to the state once it enters an organized, competitive regional wholesale electricity market.
The group will prepare a report to the Legislature, which is due by Nov. 30. Another meeting is scheduled on Oct. 12, and the group is expected to meet again after that to vote on a final report.
Brooks said there’s also an option for the task force to form working groups to tackle specific topics.
Member Perspectives
The group’s first meeting featured overviews of electric transmission and wholesale markets, and it also heard about Nevada’s existing transmission network and the status of projects in the pipeline.
Task force members introduced themselves and shared their perspectives on a regional transmission system.
Mona Tierney-Lloyd, head of U.S. policy for Enel North America, is the geothermal industry’s representative on the task force. Enel’s projects in Nevada include the Salt Wells geothermal plant and Stillwater, a combined solar and geothermal facility.
Tierney-Lloyd said Enel has “a very strong interest” in the creation of an RTO, which would deliver economic opportunity, boost system efficiency and increase reliability. It would also provide an avenue for developing demand-side technologies, she said. “Having a strong transmission grid is really the backbone for providing development of those resources.”
Kris Sanchez, deputy director of the Governor’s Office of Economic Development, said his office has been looking at how to ensure Nevada’s economic vitality coming out of the pandemic.
“One of the things that we recognized is that Nevada needed to start really investing in … looking at what we would need to make sure that the state was strong moving forward, and that we grow jobs in these critical industries like energy and transmission,” Sanchez said.
As a representative of the Bureau of Consumer Protection in the Office of the Attorney General, Consumer Advocate Ernest Figueroa said his goal is to maximize ratepayer benefits. Figueroa is a non-voting member of the task force.
Economic Benefits
Task force member Leslie Mujica, executive director of Las Vegas Power Professionals, a nonprofit focused on workforce development, represents the general public on the panel.
She said Nevada can become a leader in renewable energy and electrification.
“Most importantly … there are billions of dollars ready to be spent and invested in our state that will create not only high-paying jobs, but careers, long-term careers,” Mojica said.
John Seeliger, regional energy manager for Nevada Gold Mines, represents the mining industry on the task force. The mining industry is very energy-intensive, he said, and it’s looking at ways to decarbonize.
“We’re very interested in making sure we have a stable and robust transmission system,” Seeliger said.
Staff at cybersecurity firm Dragos warned on Tuesday that the Pipedream malware they discovered this month represents “a threat that should be taken seriously,” with potential to disrupt industrial control systems (ICS) across a wide range of critical infrastructure sectors.
Dragos disclosed the Pipedream malware suite April 13, and the Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency confirmed the discovery separately in a joint statement with the FBI and National Security Agency. (See E-ISAC Warns of Escalating Russian Cyber Threats.)
Sam Hanson, Dragos | Dragos
The firm dubbed Pipedream’s developer “Chernovite,” in keeping with its policy of not attributing hacks to specific nation-states or other groups, and said it appears to be an “impact group” focused on conducting the actual cyberattack rather than gaining access to target networks. The group appears capable of operating in both information technology and operational technology networks, giving it “the potential for significant industry impact.”
In a webinar focused on the new malware, Dragos Vulnerability Analyst Sam Hanson emphasized that the Chernovite team appear to be “professionals [with] the resources on their side to improve their capabilities and industrial impact over time.” While there is no evidence Pipedream has been used in any attacks so far, its existing capabilities and the sophistication of its developers mean the danger is likely to rise over time.
Modular Structure Allows Wide Range of Targets
The version of Pipedream discovered this month targets programmable logic controllers (PLC) from Schneider Electric and Omron Automation, along with Open Platform Communications Unified Architecture (OPC UA) servers. PLCs are computer systems that constantly monitor the state of input devices and control the state of output devices, while OPC UA is an open-source standard for data exchange between sensors and cloud applications.
However, presenters in Tuesday’s webinar warned that users should not assume they are safe because they don’t work with these two vendors. The modular nature of Pipedream means it can be easily modified to attack equipment from other manufacturers or different types of ICS hardware.
Rather than a single tool, Dragos’ researchers said Pipedream is more like a collection of utilities that an attacker “could package together or use individually.” Its many components — given code names by Dragos — include Evilscholar, which enables interaction with Schneider Electric controllers; Badomen, which interacts with Omron controllers; Mousehole, for OPC UA servers; Dusttunnel, a Microsoft Windows implant that facilitates remote interactive operations; and Lazycargo, which can be used to install an unsigned driver on a target device.
In a sample deployment scenario Dragos shared, an initial access group — likely separate from Chernovite — gains entry into an enterprise network, after which Chernovite uses Dusttunnel to establish a permanent foothold and move laterally into an OT network. Mousehole is then used to identify OPC UA servers and connected devices. The attacker can then use Evilscholar and Badomen to interact with the appropriate PLCs and disrupt the target’s operations.
Malware Teams’ Sophistication Growing
Jimmy Wylie, Dragos | Dragos
Jimmy Wylie, Dragos’ principal malware analyst, emphasized that the discovery of Pipedream’s capabilities does not mean it has been neutralized; the targeted hardware is used across the electricity, oil and gas sectors, and should be considered vulnerable without mitigating activities. Recommendations for Schneider Electric devices include changing default credentials and monitoring for new outbound connections; for Omron equipment, restricting access to certain ports and, where possible, restricting workstations from making outbound connections; and disabling OPC UA discovery to reduce the target’s “attack surface.”
In addition, Wylie warned that the new malware displayed a much greater level of sophistication than relatively “sloppy” tactics seen in the last decade, suggesting the pace of malware development is accelerating.
“This is an attack tool, and also a research utility,” Wylie said. “Pipedream combines the breadth of knowledge of Crashoverride” — the malware used to attack Ukraine’s power grid in 2017, also called Industroyer — “with the in-depth knowledge of protocols of Trisis,” which was used in a cyberattack against targets in the Middle East in 2017.
“In six years, we’ve gone from something that was sloppy and defective” — referring to Crashoverride — “to something that’s professionally made and easy to use,” he added.
Carbon dioxide, nitrogen oxide and sulfur dioxide emission levels in PJM increased last year after the historic lows of 2020 during the height of the COVID-19 pandemic, according to a report released Tuesday by the RTO.
But emission rates did drop, in some cases sharply, compared to 2019 levels, continuing an overall decline since 2005, according to PJM’s annual Emission Rates Report, used by generators, state regulators and other stakeholders in planning for environmental objectives.
Marginal carbon dioxide emission rates in PJM from 2017-present | PJM
The average CO2 emission rate for electric generators in PJM increased 6.6% from 2020 to 2021, going from 791 pounds/MWh to 843 pounds/MWh. That, however, was 1% lower than in 2019. The RTO attributed the increased levels last year to relaxed COVID-19 precautions and business and consumer activity returning to near pre-pandemic levels, with 2020 seeing historically low CO2 emission levels.
Since 2005, CO2 emission rates have fallen 35% across the RTO’s footprint. Emission rates for NOx and SO2 have decreased 85% and 94%, respectively, during the same period.
NOx emission rates increased 5.6% in 2021, but they were down 15.6% compared to 2019. SO2 rates increased 11.6% in 2021, but they were down 12.7% compared to 2019.
On average, combined cycle gas-fired generators accounted for 59.75% of the marginal unit — the resource that sets the LMP — time on the system In 2021. Combined cycle generators made up 64.33% of the marginal unit time in 2020.
Coal units were the second largest marginal unit in 2021, coming in at 14.15%, down from 17.53% in 2020. Wind units made up 11.04%, up from 6.75% in 2020.
Cost allocation negotiations for the second half of MISO’s long-range transmission planning process heated up this week over whether interconnecting generators should bear a portion of project costs.
At a Tuesday meeting of MISO’s cost allocation stakeholder group, staff said the RTO is leaning toward ruling out a “generator pays” element in its long-range transmission cost allocation.
Jeremiah Doner, MISO director of economic and policy planning, said the RTO prefers keeping transmission cost allocation to load separate from network upgrades to interconnection customers. Several stakeholders at the meeting asked MISO to reconsider devising cost assignments for interconnecting generators in order to pay for long-range transmission projects.
MISO is currently designing a different cost allocation to apply to the third and fourth cycles of its multiyear long-range transmission plan. (See MISO Seeking New Tx Cost Allocation for Major Buildout.) The grid operator hopes to have a new allocation in place by the end of next year, though some stakeholders hope it can finish earlier than that.
The long-range planning is occurring in four parts, with the first two focusing on the RTO’s Midwestern footprint and more immediate needs. The third cycle will include transmission needs in MISO South, while the fourth will include both the Midwest and South and solutions to increase transfer capability between them. MISO has so far studied and recommended $10 billion worth of projects for the first phase of the plan. (See MISO Focuses Stakeholders on $10B LRTP Projects.)
Sustainable FERC Project attorney Lauren Azar said implementing a generator-pays model will introduce a host of complex issues.
Clean Grid Alliance’s Natalie McIntire said that if MISO plans to allocate transmission costs to generation, it must also “slice and dice” its current process for assigning interconnection upgrade costs. She also said that if generators take on transmission costs based on how it benefits them, the RTO should also consider compensating generators for the contributions they provide, including reliability and furthering carbon reductions.
“There’s two sides to these questions about generator benefits,” McIntire said.
Doner said generation trying to clear the interconnection queue will still have network upgrade costs even after long-range projects are built, though they will be comparatively cheaper than current costs. Doner pointed out that ultimately, transmission charges flow back to load.
Mississippi Public Service Commission counsel David Carr said he was in favor of exploring a “generator pays” percentage of cost sharing and said it seemed that clean energy nonprofits were trying to “shut down” the possibility. He also said that while load will ultimately pay, it’s a matter of “which load” will pay: “All load, or the load from generators that rely on the projects?”
Southern Renewable Energy Association Executive Director Simon Mahan said that existing generation will likely benefit from the long-range projects. He asked if stakeholders would want long-range project costs assigned to existing generation. Mahan also said assigning costs to generation on transmission projects that stand to increase MISO’s Midwest-South regional transfer constraint is bound to be complicated.
Some stakeholders asked that proponents of generator cost assignments come forward with proposals of how and when generation could be assessed and assigned transmission costs.
Entergy’s Yarrow Etheredge said that while the RTO didn’t seem receptive to exploring generator charges in transmission cost sharing, it’s possible for projects stemming from MISO and SPP’s Joint Targeted Interconnection Queue study. (See Now, the Hard Part: MISO, SPP Tackle JTIQ Cost Allocation.)
Recognizing that cost allocation will continue to feature heavily in stakeholder meetings, MISO announced that it’s assembling an internal cost allocation team. Current employee Milica Geissler is serving as team lead.
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?”
