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November 13, 2024

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NY Adds Clean Trucks Rule to Low-emissions Vehicle Program

New York has joined the short list of states to finalize regulations designed to spur the market for zero-emission medium- and heavy-duty vehicles (Z-MHDV).

The Department of Environmental Conservation on Wednesday adopted amendments that incorporate California’s Advanced Clean Trucks (ACT) rule into New York’s existing low-emission vehicle program. New Jersey, Oregon and Washington also adopted the regulations last year.

Under the rule, which California added to its state codes last spring, Z-MHDV sales requirements will increase gradually starting with model year 2025.

In 2035 and thereafter, New York’s annual Z-MHDV sales must be:

  • 55% for vehicles weighing 8,501 lb. to 14,000 lb., such as full-size pickup trucks, small utility trucks, cargo vans, and passenger vans;
  • 75% for vehicles weighing more than 14,000 lb.; and
  • 40% of MHDVs designed to pull trailers.

Manufacturers will accrue credits for in-state Z-MHDV sales that can be banked and traded in New York. In addition, the rule requires manufacturers to report sales information and credit trades annually to demonstrate compliance.

New York has about 685,000 MHDVs that emit 15.4 million metric tons of greenhouse gases annually, representing 24% of the state’s on-road vehicle emissions, according to an analysis of the state’s ACT program that was backed by the Natural Resources Defense Council.

Adopting ACT, according to the report, will provide an estimated net societal benefit of $19 billion through 2050. Those benefits include annual electric utility bill savings of $325 million from increased electricity sales for Z-MHDV charging.

ACT also will cut MHDV fleet fossil fuel use in half by 2050, and fleet charging will increase electricity use from an estimated baseline for the year by 7% to 10.1 million MWh, the report said. In terms of GHGs, the report said ACT will reduce emissions by 64 million metric tons over 30 years.

Adoption of the regulations demonstrates the state’s commitment to protecting communities from pollution, said Mary Barber, director of regulatory and legislative affairs at Environmental Defense Fund.

“Now, policymakers, utilities and the private sector must come together to build the charging infrastructure necessary to fuel these zero-emission trucks, which will ensure they are on New York’s roads as soon as possible,” Barber said.

Statewide, there are only 128 fast-charging ports available to any vehicle, the report said, adding that fleet owners, government and private entities need to invest $131 million per year in charging infrastructure from 2025 to 2050 to support the new regulations.

New York Gov. Kathy Hochul in September signed a bill requiring all new passenger cars and trucks sold in the state to be zero-emission by 2035. The law includes a mandate for all MHDVs to be zero-emission by 2045, where feasible. In addition, it directs lead state agencies to develop a zero-emission vehicle market strategy by January 2023.

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Winds of Climate Change Policy Sweep Through West in 2021

Western lawmakers and regulators produced a whirlwind of climate initiatives last year, advancing numerous bills, regulations and proposals to reach net-zero emissions by 2050. 

Washington Adopts Cap-and-trade, Low-Carbon Standard

The passage of Senate Bill 5126 in April made Washington the second state in the nation behind California to adopt a cap-and-trade program, fulfilling a longtime objective of Democratic Gov. Jay Inslee. A task force appointed by Inslee is leading brainstorming efforts for the program, to be implemented by the state’s Department of Ecology. The program could potentially link up with the Western Climate Initiative trading pact, which currently includes California and Quebec. (See Wash. Becomes 2nd State to Adopt Cap-and-trade.)

Washington lawmakers last spring also passed a bill (HB 1091) implementing a low-carbon fuel standard (LCFS). The new law requires that carbon emissions from gasoline and diesel fuel sold in the state be cut 10% below 2017 levels by 2028 and 20% by 2035. The rules exclude emissions from fuel exported out of state or used by water vessels and railroad locomotives. (See LCFS Bill Passes Washington Legislature.)

The legislature also approved a bill (HB 1287) that requires the state’s Department of Transportation to establish a system to predict the growth of electric vehicles in the state and the expected number and locations of charging stations. The legislation also calls for utilities to use state predictions to map out where charging stations should be installed in their own areas. 

Inslee vetoed a portion of the bill that called for the state to implement a “road usage” charge for EVs — a fee based on vehicle miles traveled — saying he didn’t want Washington’s conversion to electric vehicles to be legally linked to such a charge. (See Inslee Vetoes Part of Wash. EV Mapping Bill.)

A new Republican-sponsored law (SB 5000) will cut Washington’s 6.8% vehicle sales tax in half for the first 650 hydrogen fuel cell vehicles (FCEVs) sold in the state. (See Green Transportation Bills Headed for Inslee’s Desk.) Douglas County Public Utility District last year broke ground on the state’s first green hydrogen production facility, which is intended to provide fuel for the FCEV fueling stations.

Ore. Tackles Cap-and-invest, Clean Power, Landfill Methane

In Oregon, the state’s Environmental Quality Commission last month approved a cap-and-invest program that sets declining caps on greenhouse gas emissions from the state’s fuel suppliers, targeting a 90% cut by 2050. The cap portion of the new Climate Protection Program (CPP) will cover natural gas local distribution companies and suppliers of gasoline, diesel and propane. Another CPP component requires certain industrial stationary sources to reduce their GHG emissions using best available emissions reduction approaches, with plans subject to review by the state’s Department of Environmental Equality (DEQ). (See Oregon Adopts GHG Cap-and-invest Program.)

Oregon lawmakers last spring passed the country’s most ambitious clean energy mandate (HB 2021) (tied with New York), requiring the state’s investor-owned utilities to serve their customers with 80% emissions-free electricity by 2030 and 100% by 2040. IOUs serve about three-quarters of the population. (See West Coast Could Be Net Zero by Midcentury.)

In the fall, Oregon also adopted the nation’s most stringent landfill gas emissions standards, part of an effort to reduce the release of heat-trapping methane. The DEQ estimates that landfills accounted for 37% of Oregon’s carbon dioxide-equivalent emissions from stationary sources in 2019, excluding power generators. (See Oregon Adopts Nation’s Strictest Landfill Emissions Rules.)

On the EV front, an advisory group convened by Oregon’s Department of Transportation published a report last summer showing that the state must have 155,249 public chargers in place — compared with about 3,500 today — to accommodate the 2.5 million EVs that policymakers expect will be registered by 2035. The report also outlined recommendations for how the state should get there. (See Oregon Study Charts Explosive Growth of EV Chargers.)

Sweeping Bill in Nev.

Nevada lawmakers in May passed a far-reaching bill (SB 448) to expand electric transmission and boost the presence of EV chargers across the state. (See Nev. Bill Would Ramp up Tx, EV Spending, Prepare for RTO.)

“This bill would create a framework by which we could then develop transmission lines across the state of Nevada and be able to access wind in Wyoming, solar in the Southwest, hydro in the Northwest, and provide power to our neighbors in Southern California and Central California,” said Sen. Chris Brooks (D), the bill’s chief sponsor.

The new law also aligns utility planning processes with the state’s decarbonization goals. Another provision requires utilities to join a regional transmission organization by 2030, a process Gov. Steve Sisolak got underway last month with the appointment of a task force that will advise the governor and legislature on the process. (See Nev. Gov. Sisolak Appoints Regional Tx Task Force.)

Regulators in Nevada and neighboring Arizona late last year both approved plans encouraging utilities to adopt electric vehicles. The Nevada Public Utilities Commission approved NV Energy’s plan to spend $1electr00 million over three years to develop about 1,820 EV chargers at 120 sites, in accordance with SB 448. (See NV Energy Gets Green Light for $100M EV Charger Plan.) Meanwhile, the Arizona Corporation Commission directed that state’s IOUs to develop transportation electrification plans that base future investments on a “high-adoption scenario” for EVs.

Additionally, Nevada’s Legislative Commission voted in October to adopt Clean Cars Nevada, a regulation that aligns the state’s zero-emissions vehicle (ZEV) policies with California and provides automakers with credits for selling ZEVs in state. Although the regulation won’t take effect until model year 2025, automakers will be able to begin earning “early” credits this year. (See Nev. Adopts Clean Cars Rule, Allows Early Credits.)

Winds Blow from Calif.

Despite the policy actions elsewhere in the West, California in many respects remained the climate policy trendsetter for the region and the country, advancing new initiatives related to cap-and-trade, EVs and building decarbonization.

At the U.N. Climate Change Conference of the Parties (COP26) in Glasgow, Scotland in November, California demonstrated its clout when it entered an agreement with Quebec and New Zealand to cooperate on carbon markets and other climate actions. The pact, signed by California Air Resources Board (CARB) Chair Liane Randolph, calls for the three governments to explore alignment of their cap-and-trade programs through program features such as cap setting, auctions, credit allocation and market rules. (See Calif., Quebec, NZ Pledge Cooperation on Climate, Carbon Markets.) 

California leads the nation in ZEV ownership, and CARB last year moved broadly to help the state accelerate uptake of the vehicles. 

In August, the agency proposed a plan to give auto manufacturers environmental justice (EJ) credits for selling ZEVs at a discount to community programs that offer services such as ZEV car sharing. Manufacturers could use the EJ credits to boost the number of total credits they earn under the state’s existing ZEV credit program, which is based on a purchased vehicle’s range on a single charge. (See CARB Plan Aims to Broaden Access to ZEVs.)

In October, CARB proposed to allow car manufacturers selling vehicles in the states that follow California’s ZEV regulations to transfer ZEV credits among states, starting with model year 2026. Twelve states have so far adopted California’s ZEV rules. (See CARB Plan Would Allow Interstate Transfer of ZEV Credits.) 

CARB in November approved a $1.5 billion clean transportation funding plan that includes $515 million for a popular electric car incentive program, $570 million for the Hybrid and Zero-Emission Truck and Bus Voucher Incentive Project, and $75 million for a program that encourages low-income residents to replace old cars with zero- or near-zero-emissions vehicles. The plan also gives $195 million to the Clean Off-Road Equipment Voucher Incentive Project, which provides incentives for equipment such as zero-emission tractors and forklifts. (See CARB Approves $1.5B Clean Transportation Package.)

On the building decarbonization front, the California Energy Commission last summer approved a major state building code update expected to “juice the market” for heat pumps, according to Commissioner Andrew McAllister. The new code sets requirements for electric heat pumps for space and water heating, solar paired with battery storage in commercial buildings, and wiring homes to equip them for all-electric appliances. (See Calif. Energy Commission Adopts 2022 Building Code.)

“California is being forced to lead even more than before, and that’s a good thing,” McAllister said when the CEC approved the code. “The winds are blowing through California. They start here and blow elsewhere.”

This story relied heavily on the previous reporting of John Stang, Elaine Goodman and Hudson Sangree.

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Connecticut Governor’s Order on Climate Sets Stage for Federal Funding

An executive order that Connecticut Gov. Ned Lamont signed Dec. 16 will help the state direct federal infrastructure funding to climate solutions, Department of Energy and Environmental Protection Commissioner Katie Dykes said Tuesday.

The order on reducing carbon emissions and adapting to climate change continues the state’s efforts to implement the recommendations issued by the Governor’s Climate Change Council (GC3) last January.

Allocations that come from the federal Infrastructure Investment and Jobs Act will “help to jump-start and catalyze a lot of the climate solutions that we’ve been focused on as part of the GC3 for both reducing emissions and protecting communities from the impacts of climate change,” Dykes said during a webinar hosted by the DEEP Office of Climate Planning.

Strategic planning efforts that come from the governor’s order, Dykes said, will put the state in a position to capture the emission reduction and adaptation benefits from the investment of federal dollars.

The order includes 23 directives for state agencies related to transportation, buildings, resilience, jobs, land use, and equity and justice.

State agencies will take action under the order in accordance with the authorities of the executive branch, but Dykes said the order is “not a substitute for further legislative partnership and action.”

“We’re eager to continue … working on a legislative agenda that will help to accelerate our ability to invest in climate mitigation and adaptation and resilience,” Dykes said.

Climate Leadership

The order also advances the GC3’s commitment to environmental justice by creating the Connecticut Equity and Environmental Justice Advisory Council (CEEJAC) within DEEP.

Part of CEEJAC’s mission will be to integrate environmental justice considerations into DEEP’s rulemaking, permitting and compliance processes. The 15-member council must include three individuals who are members of communities of color, low-income communities or community-based organizations, or who are academics with relevant knowledge.

The order also addresses health equity by creating an Office of Climate and Public Health within the Department of Public Health.

To enhance economic opportunities related to climate and energy investments, the order established the Connecticut Clean Economy Council to advise state agencies on how to strengthen state programs while lowering emissions. The council will meet quarterly to identify ways to ensure the state’s workforce is prepared to deliver climate-related solutions and has equitable opportunities to participate in the clean economy.

In addition, work by the GC3 will continue under the order. The council must prepare an annual progress report on mitigation and adaptation and resilience planning, starting with an initial report due at the end of this year.

Energy Planning

This year DEEP will update the state’s Comprehensive Energy Strategy as part of a periodic update. As usual the department will update the state’s energy needs related to electricity, heating, cooling and transportation, but Lamont also gave it new directives for the plan.

DEEP must identify ways to make heating and cooling more affordable while also reducing emissions from residential and commercial buildings and industrial processes to meet state emissions targets for 2030 and 2050. The update also must include options for making the energy sector more resilient to extreme weather and fuel price swings.

The agency will release details this week about the start of its planning process for the energy strategy update, according to Rebecca French, director of the Office of Climate Planning.

Transportation

Three directives in the order will address high emissions in the state’s transportation sector.

The Department of Transportation will stop funding the purchase of diesel buses by the end of next year and develop a strategic plan to address barriers to transitioning the state’s bus fleet to electric technologies. A separate DOT plan must identify investments for achieving a vehicle-miles-traveled reduction target for 2030.

By next January, DEEP must also release an assessment of the need to adopt California’s medium- and heavy-duty vehicle emissions standards to meet state climate goals.

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New York TOs Defend New Public Policy Tx Category

New York transmission owners on Monday urged the Public Service Commission to reject a challenge to its new category for transmission projects intended to help the state meet its climate goals (20-E-0197).

The TOs, including all the investor-owned utilities in the state as well as the New York Power Authority and the Long Island Power Authority, said that LS Power Grid New York’s petition for a rehearing was “legally defective” and construed the facts of the PSC’s order.

The PSC in September established a category for transmission and distribution investments made to help achieve the state’s environmental goals. It directed IOUs to revise their proposed benefit-cost analyses and resubmit them within 90 days. (See New York Adopts Groundbreaking Tx Investment Rules.)

LS Power in October argued that costs of local transmission can only be allocated under the NYISO tariff’s FERC Order 1000 processes; that any regional cost allocation is pre-empted by FERC’s exclusive jurisdiction over transmission; and that any facilities that operate over 200 kV are not “local” facilities. On the last point, the company urged the commission to “clarify this bright line.”

The TOs countered that LS Power did not meet the requirements for rehearing requests, as it “points to no errors of fact or changed circumstances, and the legal errors it alleges are wrong as a matter of law and/or are procedurally barred.”

They also said that NYISO’s competitive solicitation and planning process does not displace alternative, voluntary, multi-TO funding of transmission projects, which remains lawful and is encouraged by FERC.

In addition, they said, LS Power’s 200-kV argument is flawed because FERC permits participant funding for both local and non-local transmission projects, irrespective of voltage. FERC’s definition of local transmission “does NOT apply a 200-kV bright line” to projects that generally serve local load, they said, and the state’s Accelerated Renewable Energy Growth and Community Benefit Act does not contain a voltage bright line.

With both LIPA and Consolidated Edison having proposed projects above 200 kV, LS Power argued that any PSC decision to permit New York utilities to recover the costs of such high-voltage projects through a statewide assessment would interfere with FERC’s exclusive jurisdiction over transmission services under the Federal Power Act.

“The commission should make clear to all the New York utilities that they should not undertake needless and expensive planning for such projects,” LS Power said.

The TOs refuted LS Power’s claim, saying it “is negated by the PSC’s explicit recognition of FERC’s jurisdiction over voluntary participant funding agreements,” and that LS Power “erroneously assumes that the NYTOs would not file FERC-jurisdictional participant funding agreements for FERC’s review in advance of implementing the associated rates.”

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Decarbonizing Midwest Economies? It Depends on the State

Illinois in September 2021 became the first Midwestern state to enact legislation designed to create a carbon-free electric generation system by 2050.

The Climate and Equitable Jobs Act, which Democratic lawmakers negotiated over three years with organized labor, environmental groups and the wind and solar industries, also bailed out two of Exelon’s nuclear plants at the cost of $700 million in subsidies. The bill also gives specific dates for the closing of coal-fired plants, as well as oil- and gas-fired turbines.

The legislation requires all investor-owned, baseload coal-fired power plants and remaining oil peakers to shut down by 2030. The municipally owned Prairie State coal plant, with customers in six states, must reduce its emissions by 45% by 2035 through carbon capture and sequestration and must shut down by 2045, unless it can curtail all of its carbon dioxide emissions. City Water, Light and Power, the Springfield municipal power operation, which heats and lights the State House, faces the same shutdown rule.

Gas turbine plants, even those now under construction, must also close by 2045 under the terms of the bill, although the state would have an option to allow continued operation if they are critically needed: in other words, if the anticipated growth in renewable energy — from 7% in 2021 to 100% by 2045 — cannot be achieved.

And as if anticipating that possibility, the Illinois Environmental Protection Agency is now considering final permits for a 1,100-MW combined cycle gas turbine in downstate Illinois. If built, it would join two other new gas turbines approved previously and now under construction.

The question, which was debated somewhat before passage of the landmark legislation, is whether in 25 years the gas turbines would become obsolescent in the competition with what lawmakers believed would be massive amounts of wind and solar generation.

Even as the state EPA considers final permitting for the gas turbine, the Illinois Commerce Commission, in consultation with the Illinois Power Agency, is hosting a series of public webinars to dig into exactly what will have to be done to design and build a robust statewide energy storage system backing up wind and solar. The final two sessions are planned for later this month.

Gov. J.B. Pritzker’s (D) administration is also targeting transportation decarbonization and is in line for $149 million in initial grants from the $1 trillion federal infrastructure bill to build electric vehicle charging stations.

The Pritzker administration is also working to make Illinois a center of electric vehicle manufacturing. In May the governor welcomed Canadian bus and truck maker Lion Electric at the groundbreaking in Joilette for a new bus assembly plant, made possible by $7.9 million in state tax credits. (See Canadian EV Co. Lion Electric to Build Truck, Bus Factory in Illinois.)

Electric truck maker Rivian, which acquired a former truck plant used by Diamond Star Motors downstate, announced a massive expansion of the facility in November. Samsung is considering a battery plant nearby.

In Northern Illinois, the state is hoping Jeep’s parent company Stellantis will consider converting its Belvidere assembly plant to build an electric version of its Dodge Charger. A decision is expected in the first quarter.

Minnesota Clean Car Rule to Affect 2025 Models

Minnesota is another Midwestern state with a governor aiming to move into an electric future.

Gov. Tim Walz (D) proposed stricter car emission standards in September 2019, even as President Donald Trump fought California’s standards for low- and zero-emissions vehicles.

In 2021, the Walz administration won a regulatory battle and moved to implement a clean car plan modeled on California regulations mandating new cars sold in 2035 be emission free. Republican lawmakers, some representing rural regions where EV chargers are rare, tried to block Walz by threatening to block funding to the agency that would implement the plan.

After months of debate and efforts by GOP lawmakers to stall the state’s two-year budget if Walz did not rescind his proposal, the Minnesota House of Representatives in June approved by a 99-34 vote an environmental budget bill that included tougher vehicle emissions standards and required auto dealers to carry more hybrids and EVs. (See Minnesota’s ‘Clean Cars’ Emissions Standards Debated, Approved.)

But the compromise stalled the governor’s plan until January 2024 and only begins applying to 2025 model year vehicles. The clean car rule is expected to become an issue in this year’s gubernatorial election.

Walz is up for re-election. Regardless of whether he wins, a buildout of EV charging stations has begun in the state and is expected to expand, based on the Biden administration’s infrastructure bill.

Minnesota is in line over the next five years for at least $68 million of the administration’s $7.5 billion aimed at building EV charging infrastructure. The state’s largest EV charging spend so far has been about $7 million from the Volkswagen settlement fund over a 10-year period.

Ohio Utilities Still Count on Subsidies for Old Coal Plants

In contrast to Illinois and Minnesota, Ohio is focused on protecting fossil and nuclear power plants, having capped the state’s renewable portfolio standard at 8.5% by 2026 and dramatically slowing the growth of rural utility-scale solar development by giving county governments control. The state has also stymied wind farm development since 2014. (See Ohio Lawmakers Slow Utility-scale Wind and Solar.)

Thanks to lawmakers, Ohio electric customers are also subsidizing two large 1950s-era coal-fired power plants jointly owned by the state’s investor-owned utilities and a rural electric cooperative. The statewide customer-paid OVEC subsidy was included late in the development of the now infamous Ohio House Bill 6, approved by lawmakers in 2019 to bail out two nuclear power plants then owned by a FirstEnergy subsidiary. H.B. 6 is at the heart of the largest, ongoing federal public corruption investigation in the state’s history.

The former speaker of the Ohio House of Representatives, accused of masterminding the legislation, has been indicted on federal racketeering charges. FirstEnergy has paid a $230 million fine in a deferred prosecution deal with the U.S. Justice Department and has fired its CEO and a handful of others. And lawmakers, in new legislation, deleted the nuclear bailout from the law — but not the OVEC subsidy.

A bipartisan bill introduced in the Senate in March had hearings in May and June but did not have the votes for passage out of the Senate Energy and Public Utilities Committee. Two Republicans introduced a companion bill in the House in September. Hearings were held in September and October, but no vote occurred.

Another effort is expected in 2022. Meanwhile, the subsidy has cost Ohio customers about $400 million so far and is expected to cost $1.4 billion by 2030.

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The Mid-Atlantic in 2022: Offshore Wind, Decarbonization and Youngkin

The key climate policy stories that bear watching in the Mid-Atlantic region in 2022 make up a short but high-impact list that includes offshore wind, how quickly the region’s investor-owned utilities will decarbonize and Glenn Youngkin.

The clean energy landscape in the Mid-Atlantic region got a major shake-up in November when Republican Youngkin edged out Democrat Terry McAuliffe as Virginia’s next governor, and Republicans captured a majority in the state’s House of Representatives. Youngkin released no major policy statements on energy during or after the campaign, beyond isolated statements that he would not have signed the Virginia Clean Economy Act (VCEA) and, once in office, would pull the state out of the Regional Greenhouse Gas Initiative (RGGI), which functions as a multistate carbon market.

Passed in 2020, the VCEA mandated the state’s utilities to decarbonize, Dominion Energy by 2045 and Appalachian Power by 2050, while also calling for 5,200 MW of offshore wind, and 16,000 MW of solar and onshore wind. Clean energy advocates quickly noted that repeal of the law is unlikely as long as Democrats retain their majority in the Senate.

Youngkin’s claim that he can take the state out of RGGI via an executive order is on similarly shaky ground; the legislature approved Virginia’s participation in RGGI in 2020, and again, the Senate would be a firewall for any move to leave. (See Youngkin Vows to Pull Va. from RGGI.)

Still, as governor, Youngkin has the power to slow down the state’s move toward clean energy — via executive orders and appointments to the Energy and Environmental Quality departments. However, outgoing Gov. Ralph Northam successfully promoted the VCEA and clean energy in general as a job creator and a draw for businesses to locate in the state, and the sector continues to have significant momentum.

Youngkin’s election also means the Mid-Atlantic now has another Republican governor in addition to Maryland’s Larry Hogan, who has a relatively positive record on climate. Under Hogan, Maryland has been part of the U.S. Climate Alliance of states committed to net-zero or similar major cuts in carbon emissions. Virginia is also a member, so any action by Youngkin to leave the alliance would also send a strong signal of where he wants to take the state.

New Jersey’s gubernatorial election was also a squeaker, but in that contest Gov. Phil Murphy, the Democratic incumbent, edged out a victory. Some in the state immediately started speculating whether the close election might push Murphy to moderate his strong clean energy policies.

The governor quickly put such ideas to rest by signing an executive order committing the state to cutting its carbon emissions 50% under 2006 levels by 2030 and backing up that goal with more than $33 million in state funds to purchasing medium- and heavy-duty (MHD) electric vehicles. (See Murphy Toughens NJ Emission-reduction Goals.)

Murphy has been particularly focused on vehicle electrification, especially in the MHD sector where electrification can help the state clean up the heavy-duty traffic and emissions coming out of its ports.

The Offshore Hub Competition

Offshore wind was one of the biggest Mid-Atlantic stories in 2021 and will continue to a major force in the region’s energy sector for the coming years, generating clean power, economic growth and jobs as the industry builds a supply chain up and down the coast.

The U.S. lags far behind the United Kingdom and Europe in offshore development, and the technology is particularly important because of its potential to provide more consistent, reliable power than solar or onshore wind, especially during cold winter months.

President Joe Biden has set a goal of 30 GW of offshore wind on both U.S. coasts by 2030, and last year saw fierce competition among East Coast states vying to turn their Atlantic ports into manufacturing and operational hubs for the thousands of megawatts of massive offshore turbines now in development.

Certainly, Youngkin will be hard-pressed to oppose Virginia’s leading edge in offshore wind development, with the first phase of the state’s Coastal Virginia Offshore Wind (CVOW) project — a 12-MW pilot — up and running 27 miles off Virginia Beach.

The next phase of the project, which is wholly owned by Dominion Energy, will add more than 2,600 MW of turbines, stretching from 27 to 35 miles offshore. The project still has to pass muster with the Virginia State Corporation Commission. According to the CVOW website, customers will pay for the $9.8-billion project with expected rate increases of about $4 per month, “though this figure will initially be less and will vary from year to year.”

Dominion is also building the nation’s first Jones Act-compliant vessel to be used for offshore wind operations. A federal law, the Jones Act requires ships that move goods between U.S. ports to be built, owned and operated by U.S. citizens or permanent residents. Both Dominion and Ørsted, which is partnering with the utility on CVOW, have leased space at the Portsmouth Marine Terminal to develop assembly and staging facilities for the project.

New Jersey is not far behind, with the state’s Board of Public Utilities (BPU) thus far selecting three projects totaling 3,758 MW for development off the southern New Jersey coast. More solicitations are in the works as the state moves toward Gov. Murphy’s 2035 goal of 7,500 MW. In September, state officials also broke ground on an offshore wind hub on the South Jersey coast, with European and U.S. manufacturers slated to open manufacturing and staging facilities in the area. (See NJ Breaks Ground On Offshore Wind Hub.)

The major challenge ahead for all these projects, located in federal waters, will be securing approvals from the Bureau of Ocean Energy Management, which has announced reviews of CVOW and at least two of the New Jersey projects. As the projects move through federal approval, they could encounter opposition from environmental and business stakeholders, particularly the fishing industry. At the state level, cost allocation issues could emerge both for the projects themselves and associated transmission.

More broadly, transmission will be another key issue to watch this year, specifically where the undersea cables to be laid for the wind farms will come ashore, where they will connect with the grid and what kind of upgrades will be needed to handle the hundreds of thousands of megawatt-hours of power the turbines will generate.

Under a state agreement approach, New Jersey is working with PJM to incorporate the integration of its offshore wind into the grid operator’s planning process. Again, the competition to work on these projects will be fierce; the BPU and PJM are reviewing 80 proposals they received from a solicitation, with decisions expected in the second half of 2022 on which projects, if any, will move forward.

North Carolina and Maryland are also looking to get in on the action, developing projects and ports, but not at the scale of Virginia and New Jersey. The coming year should provide some signals on how fast the industry and its supply chain can scale.

Which Way to Net Zero?

On the flip side of offshore wind is the question of how fast Mid-Atlantic utilities can end their dependence on coal-fired generation as they work toward decarbonizing the electricity they supply to their customers. All major Mid-Atlantic utilities have committed to achieving net-zero emissions, in most cases by 2050, but each has different paths and different regulatory terrains to navigate. The role of nuclear power in achieving clean energy goals also remains a topic of heated debate.

For example, Public Service Enterprise Group (PSEG) in New Jersey announced in June that it had pushed up its target for net-zero to 2030. But the utility is decarbonizing by selling its fossil fuel assets, rather than taking them offline, and has pushed hard for the state to subsidize its three nuclear plants through its zero-emission credits (ZECs) program. The BPU approved an extension of the credits in April. The plants currently provide about 90% of New Jersey’s carbon-free energy.

The New Jersey Office of Rate Counsel, the state’s consumer advocate, has repeatedly filed appeals to roll back PSEG’s ZECs, which it will likely continue under the new leadership of Brian Lipman. (See Veteran Litigator Appointed Head of NJ Rate Counsel.)

Meanwhile, in North Carolina, Duke Energy had attempted to slow-walk its retirement of coal and natural gas, filing an integrated resource plan that would keep 3,050 MW of coal-fired power online until 2035, while also adding 9,600 MW of new natural gas generation. The IRP, which covered both Duke Energy Progress and Duke Energy Carolinas, was submitted in both North and South Carolina.

The plan faced strong opposition from clean energy advocates who have criticized Duke’s methodology for scheduling coal plant closures and called for the utility to hold technology-neutral “open-source” solicitations. (See NCUC Debates Best Path for Duke Coal Retirements.) In a November order, the North Carolina Utilities Commission accepted Duke’s short-term resource mix, but the final approach to coal retirements in North Carolina will be influenced by HB 951, signed by Gov. Roy Cooper in October, which requires the state to reduce carbon emissions 70% by 2030.

Under the law, the NCUC will be responsible for formulating a carbon plan by the end of 2022, which will be a primary focus for the coming year, with plenty of hearings and debate ahead. Another major point for debate will be the new law’s provisions on performance-based rate making, under which Duke might only have to file rate cases every three years and be allowed automatic rate increases in between, providing it meets performance standards to be set by the commission.

With a Democratic governor and Republican legislature, North Carolina will be ripe for a robust debate on utility business models and IRP methodologies in the year ahead.

The Pennsylvania RGGI Debate

Pennsylvania’s energy discussions last year were dominated by discussions about whether the state should join RGGI, as Gov. Tom Wolf and state agencies faced off with the legislature over the adoption of official rules for the carbon market. The state’s long association with fossil fuels — most recently, the booming natural gas industry in the Marcellus Shale — would make its participation in RGGI a strong statement and potential model for other states with historic ties to the fossil fuel industry.

In March, the Pennsylvania Department of Environmental Protection published its rulemaking requiring fossil fuel generators in the state to obtain emission allowances under RGGI.  (See Pa. Releases Rulemaking to Join RGGI.) That decision was then backed by the state’s Environmental Quality Board in July, and the Pennsylvania Independent Regulatory Review Commission in September.  (See PA Backs Final Rule for RGGI Entrance and Pa. RGGI Regulations Approved by IRRC.)

But the state legislature continually challenged the RGGI rulemaking, with the Senate Environmental Resources and Energy Committee voting in August to send a letter to regulators protesting the state’s entrance into RGGI. (See Pa. Senate Committee Disapproves of RGGI Entry Again.) The Senate took further steps to block RGGI, passing a disapproval resolution in October, followed by a 130-70 disapproval vote in the Pennsylvania House in December.

Wolf said the legislative votes to block RGGI had been due by the end of October, arguing that the rule was therefore approved by default. But the Legislative Reference Bureau, which is responsible for publishing state rules, has refused to print the RGGI regulation, siding with the Republicans’ interpretation of the law.

In a letter issued to the bureau in December, DEP Secretary Patrick McDonnell said the dispute could result in “time-consuming litigation” if the bureau does not reconsider and publish the rule, and that it had “no legal authority” to substitute its own interpretation of the statute.

Wolf is expected break the standoff by vetoing the RGGI disapproval resolution, and the legislature currently does not have enough votes to overcome the veto.

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AEP to Pay $570K in NERC Penalties

American Electric Power (AEP) will have to pay $570,000 to ReliabilityFirst for violations of NERC reliability standards, according to a settlement approved by FERC last week (NP22-4).

The regional entity submitted the settlement in a notice of penalty on Nov. 30; FERC indicated on Dec. 30 that it would not review the settlements, leaving the penalties intact. The commission also approved a nonpublic notice of penalty regarding an unnamed registered entity (NP22-7), in accordance with FERC and NERC’s policy on violations of Critical Infrastructure Protection standards.

AEP reached its settlement with RF over infringements of FAC-009-1 (Establish and communicate facility ratings), PRC-023-2 (Transmission relay loadability) and FAC-008-3 (Facility ratings).

The violations of FAC-009-1 occurred in both the RF and MRO footprints. As a result, the settlement specified that RF will pay $188,100 of the settlement to MRO; the division was determined based on the relative net energy for load of affected facilities in each region.

The violations were self-reported on five occasions from 2018 to 2020, detailing “a widespread issue with the accuracy of its facility ratings.” Specifically, 440 facilities in RF’s territory and 146 in MRO’s needed their ratings either increased or decreased. Most of the derates and increases in both territories were less than 10%; the highest increase of 1,095% was seen in the MRO footprint, while the biggest derate was seen in RF, at 84%.

RF and MRO attributed the root cause of the violations to a lack of adequate internal controls at AEP for “ensuring that engineering guidelines … were consistently followed when establishing ratings of new facilities, after acquiring existing facilities, or after making changes to existing facilities in the field.” The earliest violation was found to have begun June 18, 2007, when AEP was required to comply with FAC-009-1, and the violations ended on Feb. 27, 2020, when AEP corrected all its facility ratings in both the MRO and RF footprints.

Both REs determined that the violations represented a “serious” risk to bulk power system reliability, noting that without accurate facility ratings an entity “may operate equipment above its maximum ratings … potentially causing equipment degradation and failure,” or call for unnecessary load shedding due to erroneously low ratings. However, no harm is known to have occurred because of the violations. AEP’s mitigation activities included validating facility ratings data for all applicable facilities and performing a comprehensive review of its facility ratings process and methodology to prevent future errors.

Transmission Relay Settings Faulted in RF

Unlike the FAC-009-1 violations, the rest of AEP’s settlement only concerned facilities in RF.

The PRC-023-2 infringements stemmed from requirement R1 of the standard, which states that transmission owners, generator owners and distribution providers “set transmission line relays so they do not operate at or below 150% of the highest seasonal facility rating of a circuit for the available defined loading duration nearest 4 hours.” AEP self-reported to RF in December 2017 and August 2018 that it had identified a total of nine instances where a transmission line relay trip limit was set below 150% of the circuit’s seasonal facility rating.

All instances arose from upgrades or changes to relays or circuit breakers that the utility failed to follow up on by ensuring the relay trip limits were appropriately adjusted. RF identified the root cause as “lack of an internal control to prevent ratings changes without the review and approval” of the appropriate personnel. No harm is known to have occurred and the line was never more than 74% of the established relay trip limit during any of the documented instances.

To mitigate the issues, AEP committed to apply revised relay settings for the nine incidents, while also reviewing its facilities rating database within the MRO footprint to identify any potential PRC-023 compliance concerns. It also developed controls to prevent future ratings changes without review and approval.

Finally, the utility reported its violation of FAC-008-3 to RF in January 2018, informing the RE that an engineering review of generators found that ratings for isolated phase buses at several gas turbines did not match vendor documentation. At the time of its report, the utility had already revised the ratings.

RF said the misrating was due to AEP failing to “verify and validate that all equipment specification was correct,” and also lacking effective internal controls to validate specifications. In response, AEP conducted a review of documentation for all generating units that did not indicate any needed revisions. The utility also established a preventive control to ensure future equipment changes must obtain director level review and sign-off from “all applicable engineering disciplines prior to the initiation of a project or work.”

Wind Farm Operator Knocked for Dismissing Alarms

FERC also approved last week a $54,000 penalty leveled against NaturEner Wind Watch by WECC (NP22-5). NaturEner, based in Florida, operates a platform that schedules wind and hydroelectric assets while also controlling and operating two wind facilities in WECC’s footprint.

The entity’s penalty resulted from two violations of BAL-001-2 (Real power balancing control performance), self-reported in October 2018 and June 2019. Requirement R2 of the standard mandates that balancing authorities ensure their clock-minute average of reporting area control error (ACE) does not exceed their clock-minute balancing authority ACE limit (BAAL) for more than 30 consecutive clock-minutes.

On May 28, 2018, a server providing information to NaturEner’s energy management system failed at 7:27 p.m., causing reporting ACE to rise beyond BAAL. The EMS issued an alarm to the system operator at 7:37 and again at 7:42; the operator acknowledged the alarms but did not act on them, despite knowing that the automated displays and applications had not been functioning properly that day.

Another alarm was issued at 7:52, 25 minutes after the reporting outage began, but the operator did not take action to bring reporting ACE back within BAAL until 7:59. As a result the limit was exceeded for 33 minutes.

The second incident occurred at 10 p.m. April 18, 2019, when alarms were repeatedly triggered by flow limit exceedances in the area. These alarms were not related to NaturEner’s operations, so the system operator — an employee different from the one involved in the previous incident — silenced them. However, in doing so he also silenced the BAAL alarms.

At 12:10 a.m. NaturEner experienced low-wind conditions, leading to a fall in generation and schedule curtailments at 1:05 and 1:42. At 1:47 a BAAL timer event started, but the operator had moved away from the controls and closed his eyes. As a result he did not notice a third rapid drop-off in generation. When an unrelated BAAL alarm began to sound at 2:13 the operator noticed the exceedance and began to work on the problem, but the issue was not resolved until 2:17, when the BAAL had already been exceeded for more than 30 minutes.

WECC determined that both violations posed a moderate risk to the BPS. Although the RE did not find that the operators intentionally caused the infringements, the oversight could have led to frequency excursions from over- or under-generation, damaging equipment and inhibiting system response.

NaturEner responded by terminating the two responsible employees and providing additional training to all other system operators on their obligation to maintain situational awareness. It also disabled the ability of the system operators to silence an alarm “without both looking at the EMS screen and acknowledging the alarm’s content.” WECC verified that NaturEner had completed mitigation activities on May 27, 2020.

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MOPR, Capacity Auction Highlight 2021 for PJM

While 2020 was marked by the emergence of COVID-19 and its disruptions on everyday life, 2021 featured an attempt to return to some normalcy while still dealing with the impacts of the pandemic.

PJM’s year was punctuated by changes in the capacity market through votes by stakeholders and the Board of Managers and a lack of action by FERC that led to the implementation of the RTO’s narrowed minimum offer price rule (MOPR). The year also included the first capacity auction conducted since 2019, as well as moves to seek solutions for the incorporation of more renewable resources into the grid.

Here’s a review of some of the biggest PJM stories of 2021 and a peek at issues stakeholders will be tackling in 2022.

MOPR Changes

In March, FERC’s technical conference on capacity markets targeted PJM’s MOPR, with both commission Chair Richard Glick and PJM CEO Manu Asthana saying the MOPR was not “sustainable” because it was hindering state decarbonization efforts and that it was forcing consumers to “spend billions of dollars extra in the name of trying to address price suppression” by state-subsidized resources.

Glick said he wanted FERC to move quickly on the MOPR despite other capacity market changes that could take longer to accomplish, seeking its replacement or elimination in time for the 2023/24 Base Residual Auction originally scheduled for December.

PJM-2021-22-capacity-auction-results-(PJM)-Alt-FI.jpgCapacity price results from the 2021/22 Base Residual Auction in May | PJM

 

By the end of June, stakeholders overwhelmingly supported PJM’s replacement for the extended MOPR, handing the final recommendation to the board. The proposal topped eight other plans in a special Members Committee meeting, receiving an 87-18 vote for a sector-weighted score of 4.18/5 (83.6%).

The new MOPR applies only to resources connected to the exercise of buyer-side market power or those receiving state subsidies conditioned on clearing the capacity auction. The vote was conducted under the RTO’s critical issue fast path (CIFP) accelerated stakeholder process mechanism, initiated for the first time in PJM’s history by the board in April.

Market participants are also asked to sign attestations declaring that they are not exercising market power or receiving state funds tied to clearing in the auction. PJM said it and the Monitor will conduct “fact-specific, case-by-case reviews” if they suspect market power. If they have concerns that a market seller “provided a misrepresentation or otherwise acted fraudulently,” a referral to FERC can be made for further investigation.

With the new rules in place, PJM would eliminate both the expanded MOPR and the prior MOPR, which was limited to new natural gas resources.

The PJM Board of Managers approved the RTO’s MOPR proposal, sending it to FERC on July 30. By the end of August, dozens of comments flowed into FERC in both support and opposition to the filing (ER21-2582).

Ultimately the rule took effect at the end of September after FERC deadlocked 2-2 on PJM’s proposal, becoming effective “by operation of law.” (See FERC Deadlock Allows Revised PJM MOPR.)

Richard-Glick-2021-07-27-(RTO-Insider-LLC)-FI.jpgFERC Chairman Richard Glick | © RTO Insider LLC

Glick and Commissioner Allison Clements, both Democrats, supported the PJM filing, with Republicans James Danly and Mark Christie standing in opposition.

At FERC’s October open meeting, Glick said “good riddance” to the old MOPR, calling it a “thinly veiled attempt to frustrate state efforts to promote cleaner energy.”

Christie said in his statement that he agreed that the expanded MOPR needed “to be replaced or significantly modified” because it was “simply unsustainable” because of the disparate energy policies among PJM’s 13 states and D.C. But he called the RTO’s proposal the “flawed and rushed result of an ‘expedited’ stakeholder process.” Danly said PJM’s proposal should have been rejected because it eliminated “all mitigation of the price-suppressive effects of state subsidies.”

By October, Vistra, Old Dominion Electric Cooperative, the Electric Power Supply Association and regulators from Ohio and Pennsylvania filed rehearing requests. FERC ultimately declined rehearing requests on Nov. 29, setting up further action in appellate court. (See FERC Declines Rehearing of PJM MOPR: Ball now in 3rd Circuit Court.)

The PJM Power Providers Group, the Pennsylvania Public Utility Commission and the Public Utilities Commission of Ohio all filed challenges with the 3rd U.S. Circuit Court of Appeals.

Return of Capacity Auctions

PJM was finally able hold the 2022/23 BRA in May and post results in June after a delay of more than a year, stemming from FERC’s 2019 approval of the extended MOPR.

The RTO announced that capacity prices dropped significantly for the 2022/23 delivery year, with rest-of-RTO prices falling by nearly two-thirds to $50/MW-day and prices in the Eastern and Southwest Mid-Atlantic Area Council (MAAC) regions falling to their lowest on record. (See Capacity Prices Drop Sharply in PJM Auction.)

The BRA cleared 144,477 MW of resources for the June 1, 2022, through May 31, 2023, delivery year at a cost of $3.9 billion, or $4.4 billion less than the 2018 auction for 2021/22 delivery year, after adjustments for an increase in entities choosing to skip the auction by using the fixed resource requirement (FRR).

The auction gave PJM a 19.9% reserve margin, above the 14.5% requirement, including load and resource commitments under FRR.

Before the auction, Dominion Energy Virginia chose the FRR option beginning with the 2022/23 BRA over concerns an expanded MOPR would undermine its ability to meet Virginia’s renewable energy targets. The utility’s FRR election covered more than 60 generating units totaling more than 18.1 GW, including its 1.7-GW Surry nuclear power plant. All told, 175 generating units chose the FRR for the 2022/23 BRA, the second highest on record and more than double the 85 units that chose the FRR option for 2021/22. (See Dominion Opts out of PJM Capacity Auction.)

To get back to a three-year forward schedule for PJM’s capacity auctions, FERC in October approved a compressed schedule for auctions through 2024.

PJM received approval from the commission to push the 2023/24 BRA to Jan. 25, after initially scheduling it for December, because of FERC-required changes related to the market seller offer cap. The RTO said the auction delay was necessary to give capacity market sellers and the Monitor a “realistic opportunity” to appeal PJM’s final decisions on unit-specific offer cap requests resulting from the MSOC changes.

But the BRA has been delayed once again, after the commission last month partially reversed its May 2020 decision on PJM’s proposed energy price formation revisions. PJM must submit a compliance filing with the commission within 30 days proposing a new schedule for the BRA and subsequent capacity auctions impacted by the delay. (See related story, FERC Reverses Itself on PJM Reserve Market Changes.)

Fast-start Pricing

In May, FERC accepted PJM’s compliance filing on its rules for fast-start resources, allowing tariff changes to take effect on an issue that had been before the commission since 2017 (ER19-2722). (See FERC Accepts PJM Fast-start Tariff Changes.)

PJM’s proposal added a new section to its Operating Agreement defining a fast-start resource as “capable of operating with a notification time plus start-up time of one hour or less, and a minimum run time or minimum down time of one hour or less, based on operating characteristics.”

Resource Adequacy

The Resource Adequacy Senior Task Force (RASTF), a new senior task force aimed at addressing resource adequacy topics and recommending possible changes to the capacity market, won stakeholder approval in October.

David Anders, director of stakeholder affairs for PJM, called the task force the “central clearinghouse” for work related to resource adequacy following stakeholder discussions on the MOPR.

The task force was partially the result of a letter issued by the board in April urging stakeholders to address a series of topics related to the capacity market, including the evaluation of characteristics of the appropriate level of capacity procurement and the examination of the need to strengthen the qualification and performance requirements on capacity resources.

Stakeholders suggested including a discussion on opportunities to address the social cost of carbon; procurement of clean resource attributes in the RTO’s capacity, energy and ancillary services markets; FRR rules; and generation performance assessments.

The RTO is looking to implement an issue charge for the RASTF this month, with work in the task force expected to be completed by late 2023 in time for implementation in the 2027/28 BRA in May 2024.

Energy Transition

PJM announced in October that it received 79 proposals addressing both the onshore and offshore demands of New Jersey’s ambitious offshore wind program as part of the RTO’s “state agreement approach” under FERC Order 1000.

The RTO is currently evaluating issues around reinforcing networks and preparing reviews of the offshore elements of the proposals by collaborating with consultants with offshore wind expertise.

NJ-OSW-Project-Solicitation-(PJM)-Alt-FI.jpgPJM gave an example of how proposals to New Jersey’s solicitation for offshore wind transmission projects may look. | PJM

 

The New Jersey Board of Public Utilities has already awarded three offshore wind projects in two solicitations: the 1,100-MW Ocean Wind 1 and 1,148-MW Ocean Wind 2 projects, both developed by Ørsted, and the 1,510-MW Atlantic Shores project, a joint venture between EDF Renewables North America and Shell New Energies US. The BPU is planning to hold three more solicitations over the next five years to help the state reach its goal of supplying 7,500 MW of offshore wind by 2035. (See NJ Awards Two Offshore Wind Projects.)

The BPU has issued a guidance document indicating certain processes to be employed going forward during the project evaluations. New Jersey retains the right to elect to move ahead with any of the projects and is targeting the end of the year to make final decisions.

Besides the offshore wind initiative, PJM in December kicked off what it said will be a multiyear initiative on the study of integrating the increasing number of renewable resources in the region. (See PJM Energy Transition Study Released.)

The paper, “Energy Transition in PJM: Frameworks for Analysis,” included the RTO’s preliminary five-year strategy built on three pillars: facilitating state and federal decarbonization policies; planning for the grid of the future; and fostering innovation for the transition.

PJM said the study is designed to help identify gaps and opportunities in the current market construct and provide insights into the future of market design, transmission planning and system operations.

Wind-Turbines-in-Fayelle-County-PA-(RTO-Insider-LLC)-Alt-FI.jpgWindmills stand on a hill in Fayelle County, Pa. | © RTO Insider LLC

 

The study considers three scenarios in which an increasing amount of energy is served by renewable generation. The “base” scenario included 10% of the annual energy in the PJM footprint coming from renewable generation, while the “policy” and “accelerated” scenarios had renewables representing 22% and 50% of the annual energy, respectively.

In the accelerated scenario, up to 70% of the dispatch was considered carbon-free when combined with nuclear generation. The accelerated scenario includes 29 GW of offshore wind, 36 GW of onshore wind and 55 GW of solar. As of 2020, renewables represented 6% of PJM’s annual energy.

Work on the study is expected to continue through 2022 with an updated report coming around the end of the first quarter of the year.

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SPP Aspires to Increase its Western Footprint in 2022

SPP traces its emphasis on collaboration — with staff, members, regulators, other stakeholders and even grid operators — to the RTO’s beginnings 80 years ago.

In the early days after the attack on Pearl Harbor, 11 Southeastern utilities shared their energy resources to help fuel an Arkansas aluminum plant. SPP says that collaborative spirit is alive today as “we tackle emerging challenges, create the unimagined and build the grid of the future.”

“Responding to crisis and change is in our DNA,” CEO Barbara Sugg said in a pre-holiday letter to stakeholders, rounding out a year of growth and challenges.

Case in point: The response to February’s Winter Storm Uri, when SPP lost more than a third of its generating capacity to freezing conditions and resorted to the first load sheds in its history. Within a month, five teams of several hundred staff and stakeholders were working on a comprehensive review of the RTO’s actions during Uri to determine how it could better prepare for future extreme reliability threats.

The report, “A Comprehensive Review of SPP’s response to the February 2021 Winter Storm,” was released in July. Staff is already working on the report’s 22 recommendations addressing the root causes, and a task force has been formed to take on issues related to fuel assurance and resource planning and availability. The Improved Resource Availability Task Force, led by Arkansas Commissioner Ted Thomas, reports to the board and the Regional State Committee and will publish monthly status reports. (See SPP, Members Begin Response to February’s Winter Storm.)

“While still navigating a pandemic, you helped us literally weather the storm,” Sugg said.

Despite its disastrous consequences, Uri didn’t stop SPP from reaching its four goals for 2021: launching the Western Energy Imbalance Service (WEIS) market; restructuring stakeholder groups to make them more efficient and productive; beginning to reengineer transmission planning; and creating a new, five-year strategic plan.

That plan, Aspire 2026, “frames the process and distills” the strategy’s key elements using mechanisms to “track and report progress toward aspirations and make mid-course adjustments.” SPP engaged its board, members, regulators and staff leadership through the planning effort.

“The most important driver of the process was a sincerely held belief that our stakeholders should be aligned around the direction we intend to travel together,” the report says.

Aspire 2026’s five strategic opportunities, meant to “strengthen [SPP’s] core” capabilities and “change the game,” include:

  • implementing the Holistic Integrated Tariff Team’s (HITT) 21 recommendations by 2026;
  • optimizing SPP’s seams;
  • expanding its Western services;
  • using innovative transmission-planning processes; and
  • anticipating and preparing for the grid of the future.

The HITT recommendations focus primarily on keeping market and transmission costs low, while the seams initiative allows SPP to build on its “recent intentional efforts” to maintain productive relationships with its neighbors. Sugg’s effort since becoming CEO in early 2020 to defrost the MISO relationship has paid dividends with the RTOs’ joint targeted interconnection queue study searching for interregional projects to alleviate their jammed generator interconnection queues. (See No MISO-SPP Joint Study in 2021.)

The innovative planning processes are expected to save $3-$4 million annually while also resolving growing stakeholder concerns about continued transmission investment amid rapid industry changes. That is why SPP is also working to improve its ability to anticipate grid changes so it can “proactively address, drive and shape” that change.

Centralized unit commitment and dispatch (SPP) Content.jpgSPP foresees centralized unit commitment and dispatch leading to improved market services in the west. | SPP

The grid operator is doing its part in the West, where it offers energy services to utilities in every state in the Western Interconnection. It provides RC services and its WEIS market, and is currently offering partial RTO services to several utilities in a region clamoring for RTOs. (See FERC Commissioners Opine on Western RTO.)

SPP is also administering the Northwest Power Pool’s Western Resource Adequacy Program (WRAP) for its 26 participants. Once fully implemented, the WRAP will help Western balancing authorities respond to potential generation shortages during critical hours as the region addresses the retirement of thermal resources and its growing reliance on variable renewable resources. (See Implementation Underway for NWPP’s Western RA Market.)

The grid operator intends to expand its RTO footprint and develop a Western market system that is fully integrated with its existing market system, thus achieving “meaningful, equitable value creation for new and existing members.”

“Market growth will provide more value to both load and generation in our market footprint,” the RTO says. “The West provides opportunities for greater access to diverse resources and to tap into larger markets with a demand for SPP’s generation.”

To that end, the RTO has quietly unveiled its Markets+ program, which it says is not simply a day-ahead market offering but a “conceptual bundle of services.” By centralizing day-ahead and real-time unit commitment and dispatch, SPP says Markets+ will provide easy transmission service across the footprint and set the stage for the reliable integration of renewable energy’s growth.

Staff presented the Markets+ model to interested participants during a virtual December meeting and plans to hold in-person forums in Phoenix, Portland and Denver by July. It is gathering information from interested parties, including the WRAP participants, as part of an extensive five-step process leading up to the program’s launch.

A year-end review of SPP would be incomplete without addressing another issue related to the Tariff’s Attachment Z2, which reimburses transmission customers that fund network upgrades.

Staff is preparing to claw back and refund $138 million in transmission-upgrade credits, dating as far back as 2008, as it waits on a response to its rehearing request of the D.C. Circuit Court of Appeals’ August ruling that FERC was correct in reversing a retroactive waiver it had granted the RTO over collecting Z2 upgrade costs. (See “SPP Asks for Z2 Rehearing,” SPP Markets and Operations Policy Committee: Oct. 11-12, 2021.)

“Our favorite topic from years gone by that we can’t get rid of … the gift that keeps on giving,” Sugg said in October. “This will be a major undertaking for SPP and our stakeholders.”

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ERCOT, PUC Say Grid is Ready for Winter Weather

The new year began in Texas with an arctic cold front sweeping away the previous week’s 80- to 90-degree temperatures and bringing ice, snow and a brutal reminder of last February’s destructive winter storm.

This time around, ERCOT has inspected 324 generation plants and transmission facilities to check compliance with new winterization rules. The Public Utility Commission has tweaked market rules to allow the grid operator to set aside more operating reserves and to do so sooner. And effective New Year’s Day, ERCOT’s systemwide offer cap has been set at $5,000/MWh, down from the $9,000 cap that sent several retailers and cooperatives into bankruptcy after the February storm.

Electricity usage during the cold snap was down too, over 20 GW less than the record peak demand on Feb. 14 that the ERCOT grid was unable to handle. The return of springlike temperatures later this week, exemplifying the dry La Niña conditions expected this winter, has further eased concerns.

<img src="//www.rtoinsider.com/wp-content/uploads/2023/06/140620231686782886.jpeg" data-first-key="caption" data-second-key="credit" data-caption="

Alison Silverstein

” data-credit=”© RTO Insider LLC” style=”display: block; float: none; vertical-align: top; margin: 5px auto; text-align: left; width: 200px;” alt=”Silverstein-Alison-2019-11-22-RTO-Insider-FI” align=”left”>Alison Silverstein | © RTO Insider LLC

“Easy peasy,” energy consultant Alison Silverstein, a former FERC and PUC staffer, said Saturday. “Pretty sure ERCOT can handle this shift.”

But another February storm, which became energy Twitter’s story of the year?

ERCOT, the PUC and Texas Gov. Greg Abbott say the system is ready.

“Texans can be confident the electric generation fleet and the grid are winterized and ready to provide power,” said Woody Rickerson, ERCOT vice president of grid planning and weatherization.

“The lights will stay on,” promised PUC Chair Peter Lake during a December press conference. (See Texas PUC Chair Lake: ‘The Lights Will Stay On’).

Texas power plants “are good to go,” Abbott tweeted.

The problem is, the same can’t be said of the natural gas system, which has borne the brunt of the blame from FERC, NERC and others for the storm’s outages because of fuel unavailability. A Federal Reserve Bank of Dallas study has estimated it will cost as much as $50,000 to winterize a wellhead. (See FERC, NERC Release Final Texas Storm Report.)

Texas lawmakers passed legislation requiring both the electric and gas industries to weatherize against extreme temperatures. However, a loophole allows gas facilities to opt out for a nominal fee. The gas network is being mapped to determine those facilities critical to power production, but that process isn’t expected to be finished until 2023.

Yes and no — thanks to the power plant winterization initiative.

“The odds are much, much lower that half of ERCOT’s generation fleet will fall to freezing weather,” Silverstein told RTO Insider. “But because neither the gas producers and pipelines have made comparable efforts to winterize their production, we have no guarantee that freeze-ready natural gas plants will have fuel to burn.”

Silverstein said ERCOT’s more conservative operating plans and a better statewide communications plan to improve awareness of winter-weather threats and potential electric shortfall could also help avoid repeats of another major winter power outage, similar to those of 2011 and 2021.

“If they can get through 2022 without another major outage or call for conservation, that’ll look like success,” Silverstein said. “But that’s a sadly low bar.”

Energy-only No Longer?

PUC, ERCOT and their stakeholders are also taking a second look at the grid operator’s energy-only market, which pays generators only when they are providing energy to the market. The PUC has developed a two-phase process, with a Phase 1 implementation plan due Jan. 10.

The second phase will evaluate a proposed backstop reliability service and a load-side reliability mechanism that Lake has been pushing since October. ERCOT staff have promised to provide a report on what it will take to design and build each of the Phase 2 proposals on Feb. 15, the one-year anniversary of when the outages began. (See PUC Forges Ahead with ERCOT Market Redesign.)

PUC staff issued a memo laying out the Phase 2 proposals and requesting stakeholder input. The commissioners received 54 filed comments before a Dec. 10 deadline but have yet to publicly address those comments.

Lake has favored the load-side reliability mechanism, but the other three commissioners have offered some pushback. The mechanism will be developed according to a set of principles that include offering economic rewards and providing “robust” penalties or alternative compliance payments based on a resource’s ability to meet established standards; building on ERCOT’s existing renewable energy credit trading program framework; providing a forward price signal to encourage investment in dispatchable generation; using dynamic pricing and sizing to ensure reliability needs are met without over-purchasing reserves; and mitigating market-power concerns for generation companies that also serve retail customers. (See Study Suggests Texas LSEs Can Provide Reliability.)

The proposed backstop reliability service would procure accredited new and existing dispatchable resources as an insurance policy to help prevent emergency conditions. The service’s principles include nonperformance penalties and clawbacks for noncompliance; deploying resources in a manner that doesn’t negatively affect real-time energy prices; and allocating costs to load based on a load-ratio share basis measured on a coincident net-peak interval basis.

“Phase 2 … is a grab bag of a bunch of different ideas with basically no specifics. It’s unclear, confusing, and it’s impossible to tell what it will mean for the market,” Stoic Energy President Doug Lewin said. “The regulatory uncertainty around this vague ‘blueprint’ will likely slow down development from lots of different developers, including storage developers.”

The renewable industry has criticized backstop reliability, saying there are ways to improve reliability without favoring generation. They point to storage, demand response, energy efficiency and real-time co-optimization, which has been pushed back to 2024, at the earliest.

“We saw comments from [clean-energy buyers] that really pointed to the risk of the commission trying to add new reliability costs to renewable energy,” said Colin Meehan, a clean-energy analyst, during a December virtual panel discussion. “Their members represent about 500,000 employees in the state of Texas. These are … big businesses that are very concerned about the commission’s moves to add costs to renewable energy.”

“Renewables are clearly very important to our energy future, but the Texas PUC is considering changes that would make renewables more expensive at the behest of Gov. Abbott and his fossil fuel industry contributors,” Environment Texas Executive Director Luke Metzger said in a statement. “That could lead some projects to get canceled or scaled back, making the grid less reliable and dirtier. That’d be like cutting out our nose to spite our face.”

Metzger issued the statement after ERCOT last week released its latest long-term look at its expected capacity. Texas already leads the nation in wind production, with the grid operator listing more than 28 GW of installed capacity. The grid already has more than 10 GW of solar, a number that is expected to exceed 19 GW by the end of 2022.

That doesn’t take into account second thoughts developers might have, given the regulatory uncertainty over ERCOT’s future market design. Texas politicians were quick to blame renewables for the February disaster, but half of the grid’s thermal generation was inoperable during that time.

On Sunday, more than 10 GW of thermal generation was unavailable during the year’s first cold snap.

Silverstein is among the many stakeholders calling for a more significant reliability analysis to determine exactly what reliability issues need to be solved.

“That is not at all clear. … [It] requires a significant amount of sophisticated analysis that nobody has done at ERCOT and no one has done anywhere else either,” she said.

Unless the commission “commits to a slower, more deliberate pace with more transparent analysis and broader consideration of options,” Silverstein said, the market design’s second phase will be “another disaster for those of us in the public and industry who want to see Texas’ electric system and market follow a thoughtful, stakeholder-informed, analytically based, transparent and provably reasonable policy development process with outcomes that are demonstrably reliability-improving and cost-effective.”

Lewin said the PUC wasted “precious time” on the load-side reliability mechanism, “an extremely unpopular idea which had the support of only a handful of stakeholders out of scores of commenters.”

“The PUC spent very little time on ideas with more support,” he said, listing needed improvements to black start, increasing energy efficiency and demand response, and finding ways to increase storage. “I hope there’s a pivot to focus on changes that will meaningfully increase reliability.”