For climate action and energy policy in the Northeast, 2021 was a big year. Massachusetts and Rhode Island passed landmark climate bills, and climate councils in New York and Vermont adopted initial plans for decarbonizing their states. Those legislative and strategic imperatives, along with other efforts across the region, set up much more work for 2022, but one challenge stands out for Northeast states: They need a comprehensive, long-term way to pay for their plans to reduce emissions in the transportation sector.
No Plan B for TCI-P
The governors of Connecticut, Rhode Island and Massachusetts pulled their support for the Transportation and Climate Initiative Program (TCI-P) in the fall. And other states that were eyeing TCI-P participation are now backpedaling on the idea.
TCI-P’s vision is to allow participating states to decarbonize transportation, which is the biggest emitting sector across the Northeast, and raise money for decarbonization strategies through a cap-and-invest system. While the region’s states have ambitious plans for electric vehicle adoption, charging infrastructure and alternative transport solutions, they have no long-term alternative plans for raising the funds expected from TCI-P.
That funding gap is a real problem, but for now, states are looking to the American Rescue Plan Act (ARPA) and the Infrastructure Investment and Jobs Act, along with utility investments, to make near-term funding progress. And in 2022, they will continue to consider longer-term strategies that will reduce sector emissions and produce funds for reinvestment in climate solutions.
In 2022, watch for these clean transportation funding efforts for the region:
potential ARPA funding recommendation this month of $100 million to $150 million from the Vermont Climate Council for the state’s transportation sector;
transportation sector funding mechanism recommendations for the Vermont Climate Action Plan update in the spring;
transportation sector funding mechanism recommendations for the final New York Climate Action Council Scoping Plan due at the end of 2022;
a directive to legislators from the new Rhode Island Electric Vehicle Charging Station Plan — due for release this week — to identify funding support for EV incentives; and
a recommendation in Maine’s new Transportation Roadmap to develop EV infrastructure funding through new sources, such as a clean fuel standard, road user charge, gas tax or carbon mechanism.
Policy
In March, Gov. Charlie Baker signed the Next Generation Roadmap for Massachusetts Climate Policy, which set a mandate for the state to reach net-zero emissions by 2050.
Central to the state’s climate goals are two emission-reduction pathways that are now in jeopardy. In addition to losing the long-term emission reductions of the TCI-P, the state’s plan to supply 20% of its electricity from Canadian hydro resources via the New England Clean Energy Connect transmission line could fall apart.
Accessing Canada’s hydropower required siting part of the NECEC project in Maine, but residents there voted in November to halt the line’s construction activities. And Maine regulators have suspended an environmental permit for the project.
Climate advocates are hoping to see Massachusetts make up for the potential loss of hydropower with more offshore wind procurements. OSW supporters in the legislature want to pass new legislation “as soon as possible” to boost the state’s target for the resource, according to Kai Salem, policy coordinator at the Green Energy Consumers Alliance.
Before Massachusetts climate advocates hone their legislative priorities for 2022, they are waiting for the Baker administration to release the state’s Clean Energy and Climate Plan in July. They are also anxious to see the overdue Commission on Clean Heat kick into action. Stakeholders expect the commission to begin its work this month to meet a deadline for policy recommendations in November.
Rhode Island joined Massachusetts last year in the drive for net-zero emissions by 2050. Gov. Dan McKee signed the Act on Climate in April, making the target legally binding. By the end of the summer, climate advocates started criticizing the administration for being slow to address the act. McKee, however, directed the state’s Executive Climate Change Coordinating Council (EC4) at the end of September to step up the pace of its work to meet the act’s objectives.
With the upcoming release of the state’s EV charging station plan this month, the legislature will begin to consider follow-on policies in support of the plan. Up for immediate consideration will be a 100% Renewable Energy Standard; a mandatory public charging station minimum for the state; and code changes to make buildings ready for EV adoption.
Planning
Planning activities to address climate-related solutions have a wide footprint across the Northeast, and the work will have many deliverables in the New Year.
New York’s Climate Action Council spent last year developing its draft scoping plan, which it adopted right before Christmas. A key priority for the council this year will be to solidify its recommendation on how to value greenhouse gas emissions, which it refrained from doing in the draft plan. The council will now take public comments on the plan and release a final version in January 2023.
In addition, New York is gearing up to release its Great Lakes Wind Feasibility study this month. The New York State Energy Research and Development Authority will submit the study to the Public Service Commission. NYSERDA officials say the PSC likely will decide this year whether the state should develop OSW on the New York side of Lake Erie and Lake Ontario.
Vermont’s Climate Council also released a climate action plan in December after a year of work. While the council works to fill certain gaps in the initial plan, including how to pay for decarbonizing the transportation sector, advocates will begin to push legislation for some of the plan’s major initiatives.
Those initiatives include:
a Clean Heat Standard;
a 100% Renewable Energy Standard;
a scaled-up weatherization program;
a formal environmental justice policy for the state; and
a revamped transportation modernization bill.
In Rhode Island, the EC4 will spend most of this year updating the state’s 2016 Greenhouse Gas Emissions Reduction Plan, as required by the Act on Climate. The update will build a foundation for the EC4’s work to develop strategies by the end of 2025 for reaching net-zero emissions by 2050. The council will start the year with a series of public sessions to help shape what net-zero emissions means for the state.
In 2021, Maine officials oversaw the development of a handful of reports that stem from the state climate council’s December 2020 action plan. Five new reports will help drive climate and energy policy efforts in the state in the New Year. They include the:
Forest Carbon Taskforce report, which the group released in October with a recommendation to set an annual forest carbon sequestration target of 12 million metric tons of carbon dioxide equivalent through 2045;
Distributed Generation Stakeholder Group draft report, which is due this month and will inform a final report on potential programs and grid upgrades to expand DG in the state;
Agricultural Solar Stakeholder Group report, which the group released in December and includes a recommendation to create a dual-use pilot program;
Clean Transportation Roadmap, which lead state agencies released in late December and includes a recommendation to adopt California’s Advanced Clean Cars II and Advanced Clean Trucks programs; and
Maine Offshore Wind Roadmap, for which working groups made initial recommendations in December that will inform early industry action, such as port development, and a finalized roadmap by November.
CAISO intends in 2022 to focus on long-term transmission planning, connecting storage to its grid and extending the real-time Western Energy Imbalance Market (WEIM) to a day-ahead market amid a push for greater Western regionalization.
“We’re going to turn the corner into ’22, and it is going to be a big year,” CEO Elliot Mainzer told the Board of Governors at its year-end meeting Dec. 17. “We are ready to go on the enhanced day-ahead market and all our other initiatives.”
CAISO must also keep competing with SPP, which is pushing West with its RTO and Western Energy Imbalance Service, and managing the Northwest Power Pool’s Western Resource Adequacy Program.
SPP’s recently unveiled Markets+ program could challenge CAISO’s proposed extended day-ahead market (EDAM).
“It’s a conceptual bundle of services proposed by SPP that would centralize day-ahead and real-time unit commitment and dispatch, provide hurdle-free transmission service across its footprint and pave the way for the reliable integration of a rapidly growing fleet of renewable generation,” the RTO says on its website.
“For utilities that see value in these services but who aren’t ready to pursue full membership in a regional transmission organization at this time, Markets+ provides a voluntary, incremental opportunity to realize significant benefits.”
SPP has scheduled a series of stakeholder meetings to discuss the new offering in Denver, Phoenix and Portland, Ore., during the first half of 2022.
WEIM and EDAM
CAISO is hoping the EDAM will give it an advantage and is wasting no time getting started this year.
Three newly established EDAM working groups will meet Monday and continue through Thursday to discuss resource sufficiency, transmission commitment, greenhouse gas accounting and other topics. CAISO’s goal is to complete EDAM market design by the end of 2022, implement and test it in 2023 and go live in early 2024.
“Amidst a dynamic and competitive environment for market services, we are fully committed to positioning EDAM as the next major step in West-wide market integration,” Mainzer said in his December report to the board.
CAISO revived the EDAM effort last year after putting it on hold following the energy emergencies of summer 2020. An online forum to relaunch EDAM in October drew 600 attendees. (See CAISO Promotes EDAM Effort in Forum.)
The level of interest was a sign of the growing demand for Western regionalization, Mainzer said at the time.
“I have never seen or felt a greater sense of interest and urgency on this topic,” he said.
A coalition of Western utilities formed the Western Markets Exploratory Group last summer to examine working together on transmission expansion, day-ahead energy sales and other market services, while leaving open the possibility of forming or joining a Western RTO. (See Western Utilities to Explore Market Options.)
EDAM seeks to build on the WEIM’s record of financial success and steady expansion. The WEIM has produced more than $1.7 billion in benefits for its participants since 2014. By 2023 it expects to have 22 members representing 84% of load in the Western Interconnection.
Establishing trust between California-run CAISO and the rest of the West remains a work in progress.
Toward that end, the CAISO board approved a power-sharing plan with the WEIM Governing Body in August. A joint meeting of the two bodies Dec. 16 was the first held under the new rules. (See CAISO Agrees to Share More Power with EIM.)
“This past year raised difficult issues with respect to resource sufficiency and the prioritization of service to loads, exports and wheel-throughs,” Mainzer said in his report. “Both these issues are vitally important to our partners throughout the West and key to the trust that is the foundation of regional markets.”
The board and Governing Body are expected to vote on a revised resource sufficiency evaluation proposal in February. CAISO plans to address wheel-throughs in a separate stakeholder initiative.
Transmission Planning
Another major CAISO effort this year involves new, long-term transmission planning to meet the state’s goal of serving retail customers with 100% clean energy by 2045, as required by Senate Bill 100, signed by Gov. Jerry Brown in 2018.
The ISO intends to develop an extended 20-year transmission outlook working with the California Public Utilities Commission (CPUC), which prepares statewide integrated resource plans, and the California Energy Commission (CEC), which produces long-term energy demand forecasts.
The CPUC’s IRP envisions connecting 18 to 22 GW of new renewable generation and importing 1 to 3 GW of out-of-state wind power to meet the state’s interim 2031 energy goals.
“These procurement portfolios require significant in-state and out-of-state transmission investments,” the CPUC’s Public Advocate’s Office said in written comments responding to a July 27 stakeholder call.
CAISO plans to release the first findings of its new 20-year transmission outlook in early 2022, Mainzer told the board in December.
The 20-year effort is meant to run in parallel with CAISO’s normal 10-year transmission planning process. It will consider the CEC’s long-term demand forecasts, including the impacts of increased electrification in the transportation and building sectors. Connecting resources still in development — such as offshore wind, energy storage and utility-scale solar — also is part of the agenda. (See CAISO Launches 20-year Transmission Planning Process.)
One big difference is that CAISO’s 10-year process looks at in-state needs, but clean energy goals may require more interregional planning and collaboration, which the longer-term process will address, Jeff Billinton, director of transmission infrastructure planning, said at a kickoff meeting in May. He cited the TransWest Express Transmission Project, intended to bring Wyoming wind to California, as one example.
“This planning process is using SB 100 resource portfolios and other inputs to characterize the longer-term architecture of the ISO high-voltage transmission system. It will evaluate onshore, offshore and interregional transmission solutions,” Mainzer said in his report. “The 20-year outlook is designed to provide an overarching transmission planning roadmap to guide interconnection queuing, resource planning, network upgrades and resource procurement in the years ahead.
“At the same time, the ISO has been conducting a stakeholder process to explore foundational reforms to transmission queuing procedures given that we now have over 250 GW of requests for service in our transmission queue, which is an unsustainable situation for all concerned,” he said.
RA and Batteries
CAISO, the CPUC and CEC face another year of dealing with resource adequacy problems following the energy emergencies of summer 2020 and a close scrape on July 9 when major transmission pathways between the Pacific Northwest and California were derated because of a massive wildfire. (See CAISO Declares Emergency as Fire Derates Major Tx Lines.)
The addition to the grid of approximately 2,250 MW of batteries since summer 2020 should help meet summer evening peaks, the time when CAISO’s grid has been most strained. California’s dependence on solar power and imports made the state vulnerable to Western heat waves that drive air-conditioning demand after sunset.
CAISO previously estimated the state will need at least 12 GW of battery storage to meet its clean-energy goals.
In December, the CPUC adopted measures aimed at securing up to 3 GW of additional capacity through supply- and demand-side programs to prevent shortages in extreme heat waves in the summers of 2022 and 2023.
The measures included ordering the state’s three big investor-owned utilities — Pacific Gas and Electric, Southern California Edison and San Diego Gas & Electric — to accelerate procurement of battery storage. The commission projected shortfalls of 2 to 3 GW this summer but noted that PG&E, SCE and SDG&E have already procured 1 GW in response to earlier commission decisions.
Since late 2019, the CPUC has directed the state’s IOUs to collectively procure more than 17 GW of additional capacity, including a June order for 11.5 GW of new resources to come online between 2023 and 2026.
Acting on a July emergency proclamation by Gov. Gavin Newsom, the CEC approved a plan in September under which batteries capable of providing at least two hours of discharge by the end of October 2022 can be licensed and connected to the grid in far less time than it would normally take.
The proclamation ordered CAISO, the CPUC and CEC to “work with the state’s load-serving entities on accelerating plans for the construction, procurement and rapid deployment of new clean energy and storage projects to mitigate the risk of capacity shortages and increase the availability of carbon-free energy at all times of day.”
It cited severe drought as an exacerbating circumstance. Two extremely dry winters in the past two years in California dried up major reservoirs so that hydropower plants had to reduce or cease production. The power plant at Lake Oroville, one of the state’s largest reservoirs and hydroelectric generators, shut down in August because of falling lake levels.
Winter storms in December generated snowpack in the Sierra Nevada that was about 160% of average for the month, but more is needed during the rest of the winter to alleviate drought conditions. Sierra snowpack supplies water for residential and agricultural use throughout the state’s dry summer months.
Greater dependence on variable resources such as wind and solar could mean none of WECC’s five subregions will “be able to eliminate the hours at risk for loss of load even if they build all planned resource additions and import power,” the regional entity warned.
WECC examined RA under several scenarios including a “drought case” in which the Glen Canyon and Hoover dams on the Colorado River ceased hydroelectric production because of low water levels.
In August, the U.S. Bureau of Reclamation for the first time declared a water shortage for Lake Mead, behind Hoover Dam, in response to a historic drought impacting the entire Colorado River Basin. (See Feds Invoke First-ever Colorado River Water Restrictions.)
WECC said “entities may have many more options to address resource adequacy issues in the five- to 10-year time frame than in the near term” but urged quick action.
“If the current long-term issues are not addressed immediately, they may be insurmountable when they become near-term issues,” WECC said.
PJM’s upcoming 2023/24 Base Residual Auction will be delayed again after FERC on Dec. 22 partially reversed its May 2020 decision on the RTO’s proposed energy price formation revisions, requiring tariff and Operating Agreement revisions within 60 days (EL19-58).
In a 3-1 vote, the commission reaffirmed its previous decision directing PJM to consolidate its tier 1 and tier 2 reserve products, but it said it erred in its approval of changes to the shape of the RTO’s operating reserve demand curve (ORDC). Commissioner James Danly was the lone vote against the decision, saying he would publish his full dissent in the future, while newly appointed Commissioner Willie Phillips did not participate in the order.
PJM filed its proposal unilaterally in March 2019 under Section 206 of the Federal Power Act because stakeholders could not come to a consensus on a single plan after more than a year of discussions and debate. (See PJM Files Energy Price Formation Plan.)
PJM’s realignment of its reserve market under the proposal it filed with FERC in 2019 | PJM
The RTO uses an ORDC and transmission constraint penalty factors to establish LMPs. Under its current rules, the maximum price the energy component of an LMP can reach is $3,750/MWh.
But the “downward sloping” ORDC, approved by FERC in May 2020, allowed the RTO’s LMPs to reach or exceed $12,050/MWh in cases of extreme reserve shortages.
The commission approved the proposal in a 3-1 vote in 2020, with then-Commissioner Richard Glick issuing a strongly worded dissent that said he was “particularly troubled” that PJM’s revision to the ORDC was accepted and that annual increased costs to load could reach up to $2 billion. (See FERC Approves PJM Reserve Market Overhaul.)
Public interest and consumer organizations challenged FERC’s decision over the increased costs to ratepayers. In May, several petitioners, including state consumer advocacy agencies, asked the D.C. Circuit Court of Appeals to reverse the decision, and the court in August remanded it.
FERC said the 2020 order “relied on broad statements” concerning the amount of PJM’s “operational uncertainty,” the practice of “load forecast biasing” by its operators and the “prevalence of reserve market uplift” in determining that aspects of the RTO’s markets were unjust and unreasonable, including the “shape of its ORDCs beyond the minimum reserve requirements.”
“Upon reconsideration, we find that PJM failed to demonstrate that the operator bias it cited is caused by its currently effective ORDCs, and thus that the biasing data PJM provides does not demonstrate that its ORDCs are unjust and unreasonable,” FERC said.
FERC Directives
The commission ordered PJM to maintain its currently effective reserve penalty factors of $850/MWh for the synchronized reserve requirement and primary reserve requirement and $300/MWh for the extended requirements.
PJM argued that the $850/MWh factors were no longer just and reasonable because FERC Order 831 directed the RTO to increase its cost-based incremental energy market offer cap to $2,000/MWh, and thus “$2,000/MWh is the lowest reasonable level at which the penalty factor can be set and still be consistent with the actions that system operators are required to take to maintain reserves.” (See New FERC Rule Will Double RTO Offer Caps.)
The RTO proposed a replacement rate design that would establish reserve penalty factors of $2,000/MWh to align with the maximum price-setting energy offer cap of $2,000/MWh. But FERC said it disagreed with the RTO’s arguments as to the necessity for the change.
“The costs of a resource providing reserves are mainly based on that resource’s lost opportunity costs: the difference between the prevailing locational marginal price and its energy offer, i.e., its foregone net energy market revenues,” FERC said. “Thus, even when LMPs in the PJM region exceed $1,000/MWh, there is usually reserve capacity available at a cost much less than $1,000/MWh.”
The commission also reversed its decision on PJM’s forward-looking energy and ancillary services (E&AS) offset, a key variable in calculating the net cost of new entry (CONE) for resources in capacity auctions. The RTO must now revert to the previous, backward-looking offset.
FERC said PJM’s failure to demonstrate that its reserve penalty factors and ORDCs were unjust and unreasonable “undermined the fundamental basis” for the commission’s determination that the backward-looking offset is unjust and unreasonable.
“Without these fundamental changes to the reserve market, there is insufficient evidence in the record to find that E&AS revenues will increase to such an extent that the backward-looking offset does not reasonably reflect future E&AS revenues and is therefore unjust and unreasonable,” the commission said.
Auction Delay
The commission said it recognized PJM will need to delay the BRA for the 2023/24 delivery year currently scheduled for Jan. 25 to implement the revised E&AS offset. FERC previously approved PJM’s request in October to delay the BRA in response to the commission’s order in September revising the RTO’s market seller offer cap (MSOC). (See FERC Accepts PJM BRA Delays.)
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.
The commission said it will not require PJM to rerun capacity auctions that utilized the forward-looking offset because doing so would “undermine the expectations of the parties who are making commitments for the 2022/23 delivery year.” Capacity prices fell sharply in the last BRA held in May, the first capacity auction held since a delay in 2018. (See Capacity Prices Drop Sharply in PJM Auction.)
PJM spokeswoman Susan Buehler said the RTO was still reviewing the FERC order and examining next steps.
FERC Commissioner Mark Christie said in a concurring opinion that certain changes in PJM’s reserve market construct proposal represented an “unacceptable risk that hundreds of millions of dollars of additional costs could be placed on consumers without a conclusive demonstration, in my view, of a commensurate increase in reliability.”
Christie said he agreed with the majority of commissioners that PJM “failed to meet its demanding burden” under FPA Section 206 to show that aspects of its currently effective reserve construct were unjust and unreasonable. He also agreed that because the replacement ORDC construct and reserve penalty factors “formed the bases” of challenging the E&AS offset from backward-looking to forward-looking, it too was unjust and unreasonable.
Christie said the order does not prevent PJM from seeking the approval of a forward-looking offset in the future if a proper case can be made, and he said it also doesn’t prevent the RTO from proposing other modifications to the reserve market construct.
Kent Chandler, Kentucky PSC | AWEA
“Consumers deserve a reliable supply of power at the least cost (consistent with applicable laws),” Christie said in his concurrence. “The issues implicated by PJM’s proposal to make major changes to its reserve market construct involve both reliability and consumer costs. Achieving the right balance is always the challenge in utility regulation.”
In a Twitter thread published on Dec. 23, Kentucky Public Service Commission Chairman Kent Chandler gave praise to FERC for “rethinking a prior decision.” Chandler said the previously approved ORDC “would have raised electricity prices by hundreds of millions of dollars, with little increase in resource availability or reliability.”
“The real win for consumers from this order is the reduced risk of extended periods of high prices that don’t increase reserves during emergency events,” Chandler said. “Without a circuit breaker, the ORDC posed a risk of high prices that look to bring on new generation, even if no one can show up.”
New York enters 2022 having greenlighted the state’s largest transmission projects in 50 years, with its first offshore wind project ready to put steel in the water and with officials having approved a plan for reaching emission limits set by the Climate Leadership and Community Protection Act (CLCPA).
The 2019 CLCPA and other statutes set high clean energy targets staggered every five years from 2025 to mid-century, with strict emissions limits that regulators cited in October when denying air quality permits to proposed gas-fired generators in the Hudson Valley and New York City. (See NY Regulators Deny Astoria, Danskammer Gas Projects’ Air Permits.)
Here’s a roundup of some of the biggest developments of 2021 and a look ahead to the new year.
Transmission to Deliver Renewable Power
The New York State Energy Research and Development Authority (NYSERDA) in November signed a contract for the 174-mile Clean Path New York transmission line being developed by a joint venture of Invenergy, EnergyRe and the New York Power Authority to bring solar and wind energy from upstate to New York City (15-E-0302).
Map shows the full length of the Champlain Hudson Power Express transmission line from Quebec to New York City. | HQUS
The contracts are subject to approval by the Public Service Commission, which will accept public comments through Feb. 7.
Some environmentalists oppose the developers’ plan to lay the Canadian line’s cable along 200 miles in Lake Champlain and the Hudson River. Environmental organization Riverkeeper said that process could churn up long-dormant contaminants such as polychlorinated biphenyl (PCBs), which were dumped into the Hudson by General Electric between 1947 and 1977.
The Clean Path line runs from Delaware County, in New York’s Southern Tier economic development region, through the Mid-Hudson region to New York City. A majority of the transmission line will be built on existing rights of ways already used by roads and transmission lines, developers said.
Construction could begin this year for the 1,250-MW Champlain Hudson, which is targeting a 2025 commercial operation date. The 3,800 MW Clean Path project is expected in service by 2027.
OSW Turbines for Downstate
The U.S. Bureau of Ocean Energy Management (BOEM) in November approved the construction and operations plan for the 132-MW South Fork Wind Project being built for the Long Island Power Authority, the second major offshore wind project in the country to move forward following the 800-MW Vineyard Wind I project. (See Interior Greenlights South Fork Wind Project COP.)
A joint venture between Ørsted and Eversource Energy (NYSE:ES), South Fork will be located approximately 19 miles southeast of Block Island, R.I., and 35 miles east of Montauk Point, N.Y. The developers say they hope to begin construction on the project’s underground transmission line this month. Commercial operation is expected by the end of 2023.
Last year, New York said it had selected Equinor and its partner BP to build 2.5-GW of offshore wind: an additional 1,260 MW for their Empire Wind project in the New York Bight, and 1,230 MW for Beacon Wind, to be situated 60 miles east of Montauk. The state, which has targeted 9 GW of offshore wind for construction by 2035, previously selected the 816-MW initial phase for Empire Wind. Beacon Wind could add up to 1,170 MW in the future. (See NY Awards 2.5-GW Offshore Deal to Equinor.)
Equinor has begun constructing the port facilities needed to build and operate their projects, using the Port of Albany for tower manufacturing, the nearby Port of Coeymans for turbine foundation manufacturing, and turning the South Brooklyn Marine Terminal into an assembly and operations and maintenance hub. (See NY Builds OSW Ports in Brooklyn, Albany, Long Island.)
Without coordinated planning, NYISO says transmission congestion around New York City could increase after the first 6,000 MW of offshore wind is interconnected.
In a NYSERDA-commissioned study released in November, The Brattle Group concluded that high voltage alternating current (HVAC) would be better than high voltage direct current (HVDC) for a cost effective meshed offshore grid. Because most of the offshore wind lease areas are close to shore, distance constraints associated with HVAC will not be an issue, the study said.
“Most lease areas up for auction are within 20 miles from each other. At this distance HVAC is a much more suitable option,” the study said. “HVAC also allows for less expensive upfront costs and technology risks to developers, which will enable higher degrees of cooperation and acceptance of a meshed solution.”
Climate Scoping Plan
In March, the state’s Climate Action Council will begin holding at least six regional public hearings on the draft scoping plan it approved in December for meeting the state’s climate goals. (See NY Officials Approve Draft Climate Action Plan.)
The scoping plan incorporated recommendations from the Climate Justice Working Group, the Just Transition Working Group and seven advisory panels: Transportation; Agriculture and Forestry; Land Use and Local Government; Power Generation; Energy Efficiency and Housing; Energy Intensive and Trade Exposed Industries; and Waste.
Climate projections for New York state. | NYSERDA
The public will have at least 120 days to submit comments on the plan, and the Council will incorporate the feedback over the course of the new year before issuing a final plan by Jan. 1, 2023.
New York officials in December also announced the release of a roadmap outlining expanded programs to achieve 10 GW of distributed solar in the state by 2030 (Case No. 21-E-0629).
The state defines distributed solar as projects under 5 MW, including rooftop installations and community solar projects. The new framework builds on New York’s solar energy progress so far, with installed distributed solar and projects under development already totaling 95% of the state goal of 6 GW by 2025.
NYSERDA and the Department of Public Service (DPS) submitted the roadmap to the Public Service Commission for public comment, which is due March 7. (See New York Issues 10 GW Solar Roadmap for 2030.)
The expanded NY-Sun initiative aims to encourage the construction of at least 1,600 MW of new solar capacity to benefit disadvantaged communities and low-to-moderate income New Yorkers. It proposes that at least 450 MW be built in Con Edison’s service territory covering New York City and parts of Westchester, which would increase solar capacity in the ConEd region to more than 1 GW by the end of the decade.
NYSERDA also proposes that at least 560 MW of new solar generation be built on Long Island through the Long Island Power Authority.
NYISO Market Changes
NYISO last month updated stakeholders on several wholesale market changes it is making to accommodate the thousands of megawatts of state-solicited renewable resources coming online in New York over the next decade. (See NYISO Updates Grid in Transition Work and Plan for 2022.)
The measures range from carbon pricing — which has not been endorsed by the governor or the legislature — to buyer-side mitigation reforms and distributed energy resource participation models, including for storage, hybrid and co-located resources, all part of the ISO’s Grid in Transition initiative announced in 2019. The Grid in Transition initiative is focused on aligning New York’s competitive markets with the state’s clean energy objectives, valuing reserves for resource flexibility, and improving capacity market valuation.
In addition to working on buyer-side mitigation tests and capacity accreditation, the ISO expects to complete development and deployment of the remaining software for its distributed energy resources (DER) participation model in 2022.
The ISO also posted the final version of its 2022 Master Plan for changes to the energy, ancillary services and capacity markets.
In addition to addressing climate change, state officials hope offshore wind and other clean energy policies will have an economic payoff: A study commissioned by New York officials predicts that clean energy employment in the state will increase by at least 211,000 jobs this decade and by nearly 350,000 by mid-century. (See NY Predicts 200K+ New Clean Energy Jobs by 2030.)
ERCOT broke a three-month silence on social media Wednesday when it tweeted the release of its semiannual report that provides a 10-year forecast of its planning reserve margins.
It was the Texas grid operator’s first tweet since Sept. 13, when it said it was preparing for Tropical Storm Nicholas. The storm eventually made landfall in Texas the following day as a Category 1 hurricane, bringing heavy rainfall and storm surge before quickly falling apart quickly and dissipating on Sept. 18.
On Thursday, ERCOT also issued its first press release since Sept. 13, a sunny report that most of the generation and transmission facilities it had inspected in December were “ready” for the winter.
The burst of activity doesn’t necessarily mark ERCOT’s return to social media or sending out press releases. The Capacity, Demand and Reserves (CDR) report was dropped without the accompanying media briefing staff used to hold for both the CDR and the seasonal assessments of resource adequacy.
With the exception of the Sept. 13 notices, ERCOT’s external communications have all but dried up ever since a pair of ordinary conservation alerts in April and June spooked Texans scarred from the devastating February winter storm. A Dec. 8 press conference with Public Utility Commission Chair Peter Lake and interim ERCOT CEO Brad Jones ended abruptly before trade media calling in could ask questions, but not before Lake promised “the lights will stay on” this winter. (See Texas PUC Chair Lake: ‘The Lights Will Stay On’.)
ERCOT officials have said they are focused on “making the necessary changes to protect Texans against the next winter storm” in explaining the lengthy radio silence. Jones has put a public face on the grid operator with his Listening Tour of Texas. (See Jones Working to Restore Confidence in ERCOT.)
According to The Texas Tribune, Gov. Greg Abbott, who is up for re-election next year and is fighting off Republican primary challengers and dismal favorability numbers (with only 18% of Texas voters approving of how state leaders have handled the winter storm and its aftermath), has taken control of ERCOT’s public messaging since the storm. The Tribune said the grid operator needs approval from the governor’s office for most of its public communications, a report confirmed by people familiar with the directives coming from Abbott’s office.
Indeed, Abbott wasted no time in retweeting a Bloomberg story that picked up the winterization readiness press release. “Texas power plants have made the upgrades needed to protect against cold weather. … They are good to go,” he said.
Doug Lewin, Stoic Energy | New West Communications
“As has been a pattern lately, the communications with the public about issues of widespread concern is sorely lacking,” tweeted Doug Lewin, president of Stoic Energy and close observer of ERCOT and the PUC.
Lewin poked holes in both announcements. He complimented the inspection program for getting power plants ready for the winter, but he has frequently noted the weatherization standards won’t apply to natural gas facilities until 2023. Industry reports have been unanimous in blaming the gas industry’s failure to supply gas plants before and during the storm as being primarily responsible for the storm’s outages.
“If you can’t get fuel to it, that gas plant isn’t very useful during a cold snap,” Lewin said.
He said the latest CDR, which shows ample capacity for the grid well into the future, bases its projections on normal weather and not the freezing conditions of 2011 or 2021. He pointed out the report’s highest winter peak demand for the next five years is about 10% lower than it was under the storm’s conditions.
“To say we have enough power in normal weather is not helpful,” he said in another Twitter thread. “We should at least plan for a winter as bad as the last one. And why do we assume that we could never have a winter worse than 2021? If these reports don’t take into account extremes, they’re mostly useless.”
John Raymond Hanger, who once sat on the Pennsylvania Public Utility Commission, said he was shocked by ERCOT’s assumptions that demand won’t again reach what it did last February.
“February 2021 is now the historic winter peak within ERCOT,” he tweeted. “But in reliability planning, instead of meeting historic peak demand, ERCOT assumes such demand won’t happen during next five years. Wow!”
Inspections Find Generation Fleet ‘Ready’
ERCOT said that its system’s generation fleet and transmission companies are ready for winter weather following its on-site inspections of mandatory winterization efforts at 302 generating units and 22 transmission facilities.
ERCOT said only 10 generators, accounting for 2.1 GW (1.7% of the total fleet), had items requiring corrective measures on the day of their inspection. It said many of those items had since been completed and noted that all 10 units are still operational.
“Texans can be confident the electric generation fleet and the grid are winterized and ready to provide power,” Woody Rickerson, ERCOT vice president of grid planning and weatherization, said in a statement.
The inspections of transmission facilities found only six minor “deficiencies,” most of which have since been corrected. They focused on resources that accounted for 85% of the megawatt-hours lost during the storm. Staff plan to file a final report with the PUC on Jan. 18 for review and any potential enforcement action. Violators of the new weatherization rules face penalties of up to $1 million per day per violation. (See ERCOT Generators Near 100% Winter Readiness Compliance.)
ERCOT will conduct follow-up inspections on those generation and transmission facilities with potential identified issues. Staff and contractors have already spent more than 3,600 hours on inspection-related activities.
Final 2 Board Members Appointed
Peggy Heeg | University of Texas School of Law
The PUC said Wednesday it has filled the last two vacancies on ERCOT’s Board of Directors, completing a total makeover in the wake of the February storm.
The commission said a three-man board selected by the state’s political leadership had appointed Julie England and Peggy Heeg as ERCOT’s final two independent directors. They are also the only women on the board. A previous appointee, Elaine Mendoza, resigned in November over an apparent conflict of interest. (See Twitter Blows up over ERCOT Communications.)
England, a former senior executive with Texas Instruments, currently serves on the boards of TTM Technologies, a global technology solutions and printed circuit board fabrication company, and engineering and construction firm McMillen Jacobs Associates. She previously served as a director of the Federal Reserve Bank of Dallas from 1997 to 2003.
Julie England | Crunchbase
Heeg advised companies on energy, regulatory and corporate governance matters as an attorney before retiring. She also served on the Texas Lottery Commission and has been a director on numerous boards in the energy sector.
“This completely independent board marks a new era of reliability and accountability in ERCOT governance and leadership,” PUC Chair Lake said in a statement.
Legislation passed during the summer replaced the previous board’s five unaffiliated directors and eight market segment representatives with eight independent directors chosen by the selection committee. The ERCOT CEO, the PUC chair and the Texas Office of Public Utility Counsel’s CEO sit on the body as non-voting members.
As it heads into 2022, MISO‘s to-do list is dominated by getting major transmission built and crafting a seasonal capacity auction, direct responses to an increasingly renewable fleet and intensifying weather events.
“Don’t rest — or maybe you should rest — because we have a lot to do in the new year,” MISO CEO John Bear told stakeholders at the December board meeting, referencing the RTO’s work on its long-range transmission plan, seasonal capacity market, ongoing market platform replacement and dynamic transmission line ratings.
“I think we put MISO in a much, much better place than we were 12 months ago,” Bear said.
Seasonal Capacity on the Way
Though climate change is rarely mentioned in meetings by politically adverse MISO staff, the footprint was roiled by extreme weather in 2021, leading the RTO to conclude that a suite of resource adequacy solutions is needed for a fleet that’s either aging or has its output dictated by weather.
MISO Senior Director of Operations Planning J.T. Smith said it’s no longer surprising for the RTO to issue seasonal warnings and that it will find itself relying on non-firm imports from neighbors if outages are high when devastating cold snaps or heat domes strike.
“It’s not a new situation; it’s something we’ve reported out over the last couple of years,” Smith said in mid-December.
In February, an unprecedented winter storm forced load shed in MISO South. The RTO said the widespread artic blast gave it further justification to revise its capacity market. (See MISO: Wintry Weather Vindicates RA Changes.)
But the cold snap seemed tame in comparison to the havoc Hurricane Ida doled out to MISO South in late August. After the storm struck, MISO South stayed in conservative operations from Aug. 29 to Sept. 10 to allow for restoration. The hurricane cut through a significant transmission corridor, slashing ties from MISO into most of the Amite South and all of the Downstream of Gypsy — or metropolitan New Orleans — load pockets. MISO reported 233 transmission lines lost and 6.4 GW of generation knocked offline during the storm. (See Entergy Touts Restoration; NOLA Leaders Question Lack of Blackstart Service.)
Hurricane Ida damage in New Orleans on Aug. 30 | Entergy
“We’re still suffering down there. A lot of recovery has to happen,” Louisiana Public Service Commissioner Lambert Boissiere said at an Entergy Regional State Committee meeting Nov. 9.
In all, MISO declared conservative operations instructions for 29 days in 2021, 13 of them from Ida. The remaining days were devoted to managing intense heat or cold.
MISO recently requested FERC approval of a four-season capacity auction and corresponding reserve margin targets. That design will accompany a new capacity accreditation based upon generators’ recent availability, especially during tight conditions. The RTO has also filed separately to create a minimum capacity obligation, in which a load-serving entity must demonstrate that at least 50% of the capacity required to meet their peak load is secured ahead of the voluntary capacity auction. (See FERC Grants Comment Extension for MISO Capacity Filing.) The pair of filings pending at FERC is all but certain to attract protests from generation owners that stand to have lower capacity credits.
The RTO said it will dedicate 2022 to furthering decisions on how its markets must change to accommodate more actively managed load and a more intermittent and varied resource fleet.
Reconstruction of an Entergy tower after Hurricane Ida | Entergy
In early December, MISO’s Jordan Bakke said the current market construct will gradually become less adept at serving load. He said local power imbalances will multiply, and MISO must be able to transport power for longer distances as more wind and solar generation is built in pockets around the footprint.
MISO has said that it expects wind and solar generation to reach 30% of its total load as early as 2026, straining the system and threatening reliability. It set a new, all-time wind output record of 22 GW on Nov. 12, with wind serving 29% of total load.
Winter Apprehension
MISO is steeling itself for a reserve shortage over the winter.
RTO staff over 2021 repeated that they must make more long-lead commitments and issue maximum generation warnings more frequently as surpluses disappear under even normal weather conditions throughout the year and the bulk electric system gets more complex to manage.
Days under a maximum generation alert, warning or event in the last eight years | MISO
The grid operator has said it will likely move up instructions for members to make public appeals for energy conservation earlier in its emergency process. It’s also collecting weekly winter fuel surveys through the end of February from about 400 generators to gauge natural gas and coal fuel security. (See MISO Sounds Alarm on Potential Winter Fuel Scarcity.)
Some generation owners have criticized the weekly survey fill-in as onerous. MISO staff say they need the information to assess reliability risks this winter.
“Given the potential upside of protecting the reliability of MISO and the downside of the administrative burden, I think the upside really outweighs [the downside]. … I really appreciate MISO as a proactive manager of this situation,” Minnesota Public Utilities Commission staff member Hwikwon Ham said at the Reliability Subcommittee’s meeting Dec. 10.
MISO has estimated through an internal survey that about 11 GW of coal generation is at risk of outage this winter because of fuel supply issues.
Addressing the winter worry, Michelle Bloodworth, CEO of coal trade group America’s Power, said MISO should “reconsider how far [the coal] fleet should be allowed to shrink.” She said some coal generation can temper the “inherent risks of an overreliance on natural gas and intermittent generation for electric generation.”
“Each coal plant that retires increases MISO’s exposure to fuel assurance risk,” Bloodworth said during MISO’s Board Week in mid-December.
But the coal exodus continues unabated.
Ameren Missouri (NYSE:AEE) announced Dec. 14 that it would accelerate the retirement of its coal-fired, 1.2-GW Rush Island Energy Center to 2024. The new retirement date coincides with a deadline to install new emissions controls imposed by the U.S. District Court for Eastern Missouri. Ameren’s 2020 integrated resource plan envisioned the plant running through the end of 2039.
“Potential grid stability and reliability impacts and other downstream effects must be evaluated, and those issues that are identified must be addressed,” Ameren noted in a Dec. 14 filing. Rush Island supports voltages in the St. Louis area.
NERC estimated that MISO faces a loss of more than 13 GW in capacity by 2024, comprising 10.5 GW of coal-fired generation and 2.4 GW of gas generation. If MISO doesn’t get replacements online soon, the footprint could suffer from a combined 560-MW shortfall, NERC concluded.
New generation is clamoring in MISO’s interconnection queue. In September, generation developers’ requests to join the system pushed the queue to a 153-GW high, shattering all previous records. (See MISO Warns Queue Won’t Stay at 150-GW High.)
Historically, MISO interconnects about a fifth of the generation projects that enter the queue. MISO executives have warned that much of the new generation won’t be able to connect to the system without substantial transmission expansion.
RTO leadership has said it could advance several billions in transmission expansion for Board of Directors approval over the next few years. So far, the RTO is only prepared to propose select projects located in MISO Midwest in late spring.
MISO plans to finish an initial cost allocation design in early 2022. The allocation prescribes a separate but equal postage stamp allocation to MISO Midwest and South. The design is based on MISO’s hypothesis that benefits from long-range projects built in either Midwest or South won’t cross its subregional transmission constraint. (See MISO to Test Long-range Tx Allocation Benefits.)
Some MISO members — especially environmental proponents — have suggested that Entergy (NYSE:ETR) is opposing major transmission expansion, hoping to stave off democratization of access to its system.
MISO also faces outside pressure to get transmission towers erected.
Former FERC Commissioner John Norris — who voted in 2013 to approve Entergy’s integration into MISO to mollify a Department of Justice investigation into the company’s anticompetitive behavior — has expressed regret at his vote and admonished Entergy and its regulators’ efforts to stall the RTO’s long-range transmission planning. He asked the MISO board to intervene in what he said was the RTO’s tendency to “yield to parochial interests.”
“I did not, nor did I suspect any of my colleagues at FERC, would have thought that by late 2021, no advancement in regional transmission planning and building would have taken place. At a minimum it would’ve seemed reasonable to assume that the north-to-south interconnection issue would’ve been addressed and resolved. Without the ability to transfer substantial amounts of electricity from north to south begs the question: What’s the point?” Norris told the board in September.
Norris said MISO’s lack of regional planning means it’s “already behind in its abilities to meet the needs for 2030 and beyond.”
“Given the increase in [maximum generation] events, one could argue that MISO is not even meeting the needs of today,” he added.
SPP said last week it was once again delaying in-person meetings and staff’s return to the office because of rising COVID-19 infections and flu cases.
In a Dec. 28 message to stakeholders, CEO Barbara Sugg said SPP is cancelling the in-person option for the Jan. 10-11 Markets and Operations Policy Committee and Jan. 12 Strategic Planning Committee meetings in Oklahoma City. Those meetings will revert to the virtual format of the last two years.
The Jan. 24 Regional State Committee and Jan. 25 Board of Directors/Members Committee meetings are still planned to be held at SPP’s headquarters in Little Rock, Ark., although attendance will be limited for social distancing.
“I know this means that I will not get to see many of you in-person as soon as I hoped, but I’m confident our team will continue to facilitate virtual meetings with their usual standard of excellence,” Sugg wrote. “Be well and stay safe.”
Sugg cited a “dramatic trend” in COVID-19 infections and flu cases. She said daily new COVID cases have nearly doubled in Oklahoma since Dec. 18 and recent hospitalizations in Arkansas increased 7% in a day.
“Although early data seems to show the Omicron variant is unlikely to severely affect healthy, boosted people, we still do not know what its impact will be on older, at-risk colleagues, friends and family,” Sugg said.
The grid operator is also delaying the fourth phase of staff’s return to the Little Rock offices until at least Jan. 18 while it continues to monitor community COVID cases. It warned its plans may undergo additional modifications “to appropriately respond to changing conditions.”
California’s hydrogen fueling network serving heavy-duty trucks needs to be expanded beyond seaports to sites throughout the state and even into neighboring states if California wants to meet its zero-emission vehicle goals, speakers said during a workshop.
Ports, where heavy-duty drayage trucks pick up containers for transport to nearby locations such as rail facilities or distribution centers, are seen as a good starting point for zero-emission heavy-duty trucks. (See Decarbonizing America’s Ports Could be 1st Step for Hydrogen Adoption.)
And hydrogen fuel cell electric trucks are being introduced at the Port of Los Angeles. In June, the port announced a demonstration project that will include 10 hydrogen fuel-cell heavy-duty trucks and two hydrogen fueling stations. The trucks will be used for local pickup, delivery and drayage near the port and short regional trips in the Inland Empire. (See Fuel Cell Semis Get Road Test at Port of Los Angeles.)
But the movement of goods doesn’t stop with drayage, and some say planning must include hydrogen fueling for heavy-duty trucks at sites farther afield.
“Focusing on California only initially may be a good thing for drayage,” said Nico Bouwkamp, technical program manager for the California Fuel Cell Partnership (CaFCP).
But freight operators “frequently have opportunities to move their freight out of state,” Bouwkamp said. “They need to be able to do that … otherwise they will not invest as much in the zero-emission trucks as they are expected to.”
The comments came during a California Air Resources Board (CARB) workgroup meeting on Dec. 16 that was held as part of the process for developing the Advanced Clean Fleets regulation. The meeting focused on issues related to hydrogen, including station location planning and timing.
In developing a hydrogen-fueling network for heavy-duty trucks in California, the report says, initial efforts should focus on major freight hubs such as seaports, airports and large warehouse districts.
“The larger share of captive fleets with return-to-base operations in freight hubs will help optimize the utilization of hydrogen infrastructure, lowering fuel costs,” the report said.
The network can then be expanded by connecting the freight hubs along major corridors. California has about 500 public truck stops where some of the fueling stations could potentially be converted to hydrogen, the report said. Yet to be decided is which truck stops should be targeted first.
Working with neighboring states is also key “to reach[ing] high levels of zero-emission truck penetration in California and beyond,” the report said.
“The ports are … obviously a useful place for hydrogen,” Tim Sasseen, market development manager for Ballard Power Systems, said during the CARB workgroup meeting. “And the 5, 10, and 15 highways are going to be long-distance corridors as well. And mapping those out to existing commercial truck stops I think makes a heck of a lot of sense.”
Another meeting participant suggested looking at the West Coast Clean Transit Corridor Initiative, a partnership among electric utilities and agencies that studied how Interstate 5 from Mexico to the Canadian border could accommodate electric trucks.
The group’s report identified conceptual locations for 27 charging sites, spaced about 50 miles apart, for medium- or heavy-duty trucks. Perhaps some of those locations could also be hydrogen-fueling sites, the CARB workgroup participant said.
A California Transportation Commission representative noted during the workgroup meeting that the CTC is leading an assessment of freight corridors that would be good locations for zero-emission vehicle infrastructure, as well as potential projects to help transition to zero-emission freight. The assessment, which is a requirement of Senate Bill 671 of 2021, is due to the legislature by Dec. 1, 2023.
Advanced Clean Fleets
The Dec. 16 workgroup meeting was the second in a series of four sessions related to CARB’s Advanced Clean Fleets regulation.
The goal of the regulation is to accelerate the adoption of zero-emission trucks and buses by requiring fleets that are well-suited for electrification to transition to ZEVs where feasible.
According to CARB, the regulation would help reach the goals in Gov. Gavin Newsom’s 2020 executive order that calls for 100% zero-emission drayage trucks by 2035; and 100% zero-emission medium- and heavy-duty vehicles by 2045 where feasible.
CARB released an informal discussion draft of the regulation in September. Under the preliminary proposal, cities, counties, special districts and state agencies would be required to buy ZEVs when they add new vehicles to their fleets.
Starting in late-2023, CARB would allow only zero-emission drayage trucks to be added to its drayage truck registry. And by 2035, all drayage trucks would be required to be zero-emission.
Under the proposal, fleets designated as high-priority would be required to hit percentage-ZEV targets, starting with vehicle types that are most suitable for electrification. High priority fleets would include those of 50 or more vehicles, or those whose owner has $50 million or more in gross annual revenue.
The regulation would apply to vehicles weighing more than 8,500 pounds.
CARB has scheduled additional workgroup meetings for Advanced Clean Fleets on Jan. 12 and Jan. 19. The first of those sessions will focus on electricity and the grid; the second will focus on costs and funding.
Reversing FERC, the D.C. Circuit Court of Appeals ruled Dec. 28 that developers of the abandoned Potomac-Appalachian Transmission Highline (PATH) transmission project must refund $6 million spent to influence public officials to approve the project (20-1324).
The $2.1 billion, 765-kV “coal by wire” PATH project was approved by PJM in 2007 to run from American Electric Power’s (NASDAQ:AEP) John Amos coal generator in St. Albans, W.Va., to New Market, Md.
By 2011, however, PJM said the need for the line had moved several years beyond 2015 because of reduced load growth following the Great Recession. After ordering transmission owners to suspend work on the line pending a more complete analysis, the PJM Board of Managers terminated it in 2012. PATH’s developers, AEP and FirstEnergy’s (NYSE:FE) Allegheny Energy, sought to recover $121.5 million they spent on the abandoned project.
At issue was $6 million that PATH passed on to customers in 2009-2011 for public relations and advocacy activities related to its effort to win certificates of public convenience and necessity to build the line.
After denying recovery of the expenses in 2017, FERC reversed itself in a ruling in January 2020 (Opinion 554-A, ER09-1256, et al.). (See FERC Grants Recovery on PATH Project Costs.) FERC later rejected a rehearing request by PATH opponents Keryn Newman and Alison Haverty of West Virginia (Opinion 554-B), prompting them to file a pro se petition with the D.C. Circuit.
PATH booked the expenses in accounts designated for “Outside Services Employed” and “General Advertising Expenses.”
But Judge Cornelia “Nina” Pillard, writing for a three-judge panel, agreed with the petitioners that the expenses belonged in Account 426.4 for “Expenditures for Certain Civic, Political and Related Activities,” which would exclude them from being passed through to ratepayers.
FERC’s instructions state that 426.4 “shall include expenditures 1) for the purpose of influencing public opinion with respect to the election or appointment of public officials, referenda, legislation or ordinances (either with respect to the possible adoption of new referenda, legislation or ordinances or repeal or modification of existing referenda, legislation or ordinances), or approval, modification or revocation of franchises; or 2) for the purpose of influencing the decisions of public officials.”
PATH contended that account was intended only for expenses made to directly influence the decisions of public officials but that the spending was for “indirect” influence.
FERC agreed, saying the spending was more like an “operating expense” because it related to “general promotional efforts” on behalf of a line that had already been approved by PJM.
The commission said the spending would have belonged in Account 426.4 if it was intended to win “a franchise application — in which the utility competes for a potentially lucrative status for itself” — rather than an application “in service of an RTO-approved project — in which the utility represents not only its own interests but those of the RTO as a whole.”
But the court said FERC’s reasoning was “unpersuasive,” noting that PATH’s own internal statements confirm that the spending was intended to influence the decisions of public officials.
“FERC clearly erred in reading Account 426.4’s second clause as implicitly limited to expenditures for the purpose of directly influencing the decisions of public officials,” Pillard wrote. “We hold that the official-decisions clause includes expenditures for the purpose of indirectly as well as directly influencing the decisions of public officials. … Because indirect influence of state officials responsible for certification decisions was the undeniable purpose of the expenditures at issue here, they should have been assigned to Account 426.4.”
The court vacated FERC’s opinions and remanded the case to the commission.
ISO-NE took several important steps to demonstrate its “alignment” with state climate policies in 2021. But the RTO’s stakeholder meetings remain closed to the public, and its board elections remain secret, falling short of calls for increasing transparency. And this spring, the states and the RTO will be debating differing market proposals for accomplishing the states’ clean energy goals.
Which design will prevail is just one of the questions facing New England in 2022, starting with whether it will have enough natural gas to keep the lights on through the winter. Among the others: whether Maine voters’ rejection of the New England Clean Energy Connect (NECEC) transmission line will stick, and whether the 650-MW gas-fired Killingly plant in Connecticut will get built.
Here’s a look back at the big issues of 2021 and what to expect in 2022.
Resource Adequacy Concerns
On Dec. 6, ISO-NE officials gave a sobering press briefing, warning that limited natural gas pipeline capacity and global supply chain issues put the New England grid at heightened risk of load sheds this winter.
The RTO said it can meet forecast peak demand of 19,710 MW during average winter weather conditions of 10 degrees Fahrenheit and 20,349 MW if temperatures reach below-average conditions of 5 F. But ISO-NE CEO Gordon van Welie said uncertainty over fuel supplies “could put the region in a more precarious position than past winters and force the ISO to take emergency actions up to and including controlled power outages.” Van Welie said the outages would be a last resort “to prevent a regionwide blackout, which would take many days or weeks to restore.” (See ISO-NE: New England Could Face Load Shed in Cold Snaps.)
Resource adequacy has been a recurring winter concern in New England because of difficulty siting new natural gas pipelines and electric transmission. The state-RTO tensions were on display at FERC’s technical conference on modernizing electricity market design in ISO-NE in May (AD21-10).
Katie Dykes, commissioner of Connecticut’s Department of Energy and Environmental Protection, complained that the RTO had failed to prevent the premature retirement of the Millstone nuclear plant, leaving her state to “shore up the reliability of the [ISO-NE] grid and the market” by approving subsidies funded by ratepayers.
Van Welie told the conference that markets are “never going to work very well” with inadequate infrastructure supporting them “or if policy objectives are not aligned.”
“We have to design the markets around those [pipeline and transmission] constraints,” he said. “That’s just where we ended up because of the choices we made over the last two decades.
“Until the region figures out how it wants to socialize some of these costs for reliability that are outside of the market, we’re going to stay stuck in that situation,” he added. “There’s no market design that will solve the problem that Commissioner Dykes wants us to solve.” (See Regulators, ISO-NE Discuss Market Changes at FERC Tech Conference.)
Progress on States’ Wish List
ISO-NE took several steps in 2022 to address the states’ demand for changes to the RTO’s wholesale market design, transmission planning and governance. The demands, first spelled out in a joint statement by five of the region’s governors in October 2020, was updated by the New England States Committee on Electricity (NESCOE) last August in its “Advancing the Vision” report.
ISO-NE’s priorities for 2022 | ISO-NE
ISO-NE’s Board of Directors responded to the states’ demands in September, saying it was “pursuing targeted governance and communications enhancements, consistent with its independence and oversight role.” It assured NESCOE that it is “aligned with the states on the clean energy transition,” citing a list of transmission planning and market rule initiatives that it was pursuing to enable the transition.
In November, ISO-NE presented the scope of its work for the 2050 Transmission Study, which will examine ways to incorporate clean energy and distributed energy resources beyond the RTO’s standard 10-year planning horizon. The study will seek to determine what transmission is needed to serve load while satisfying reliability criteria for 2035, 2040 and 2050, including high-level cost estimates to help the states evaluate different transmission options. The study was requested by NESCOE, which also was responsible for many of the study assumptions. (See ISO-NE Presents Preliminary 2050 Tx Study Scope.)
Work is expected to continue on the study throughout 2022. As also requested by NESCOE, ISO-NE on Dec. 27 filed proposed tariff changes to permit future state-led, scenario-based transmission planning as routine practice (ER22-727).
In addition, ISO-NE expects to release a report this spring on the RTO’s Future Grid Reliability Study (FGRS), which will identify potential reliability gaps in 2040 based on current state laws and policies. The FGRS, which is not a detailed transmission study, is largely based on assumptions developed by NEPOOL stakeholders, with input from NESCOE. A draft of the FGRS is expected to be presented at the Planning Advisory Committee in April and discussed at NEPOOL’s Markets Committee/Reliability Committee meeting in May.
The RTO also is conducting cluster studies to interconnect offshore wind on Cape Cod and a pilot study to proactively plan for growing levels of DERs, renewables, imports and energy storage.
Wholesale Market Design
In April, the RTO is expected to release its Pathways to the Future Grid study, which will evaluate alternative market frameworks for adapting to state energy policies. The analysis will include a forward clean-energy market (FCEM): a centralized, forward auction favored by states in which buyers (states, cities, retailers, companies and utilities) could voluntarily purchase clean energy attribute credits.
The study also will examine the RTO’s net carbon pricing proposal, which would require suppliers pay for each unit of carbon they emit to generate electricity, as a supplement to the Regional Greenhouse Gas Initiative.
Stakeholders and ISO-NE staff spent many meetings during 2021 discussing the RTO’s Order 2222 compliance filing and eliminating the minimum offer price rule (MOPR).
In December the NEPOOL Markets Committee approved ISO-NE’s proposed set of market rules to implement Order 2222 — which requires RTOs to allow DER aggregations to provide all wholesale services that they are technically capable of providing — and rejected several amendments opposed by the RTO.
The compliance filing passed the MC with unanimous support from the Generation, Transmission and Publicly Owned Entities sectors and most Suppliers. Alternative Resources were split, and End Users, who had supported unsuccessful amendments by Advanced Energy Economy, were unanimously opposed.
Assuming that FERC accepts the compliance filing by the fourth quarter, distributed capacity resources will be able to participate in Forward Capacity Auction (FCA) 18 in February 2024. The RTO proposed a fourth-quarter 2026 effective date for the energy and ancillary services markets.
The Participants Committee is scheduled to vote on the Order 2222 changes Thursday. The filing is due Feb. 2.
Meanwhile, the Markets Committee is scheduled to vote on the RTO’s proposal to eliminate the MOPR at its first meeting of the new year, Jan. 11-12.
NESCOE, FERC Chair Richard Glick and Commissioner Allison Clements all favored eliminating the MOPR, which they said was undermining state decarbonization efforts. Stakeholders approved the change in November, despite warnings from merchant generators and ISO-NE’s Internal Market Monitor that it will suppress capacity prices. Other stakeholders debated whether the implementation of the RTO’s plan should be delayed until it approves long-term market rule changes on capacity accreditation and reserves. The MOPR would be eliminated beginning with FCA 17 in 2023. (See Monitor, Merchants Challenge ISO-NE Plan to Eliminate MOPR.)
State-RTO Communications
ISO-NE’s September response to NESCOE said the RTO’s board is “making changes that are consistent with the ISO’s core requirement for independence and its role as an oversight board.”
It pledged the board will hold an annual open meeting beginning in 2022 — focused on the electricity markets on even-numbered years and transmission planning in odd-numbered years — in addition to meetings the board holds with the states and NEPOOL sectors throughout the year.
The board said it would hold other meetings as needed to discuss consumer implications of its proposals and that if the states have a majority position on an RTO proposal, “management will include consideration of a state majority position in filings to FERC.”
It also noted that the CEO’s monthly board reports — which summarize recent board and board-committee meetings — are public and that states can question van Welie about board activities at NEPOOL Participants Committee meetings.
But the board did not take action on NESCOE’s request to establish a standing board committee on state and consumer responsiveness. “The board is continuing discussions with the states about this request,” ISO-NE said in an email to RTO Insider. “The board and several of its committees already review state and consumer issues in various ways, and the board is continuing to consider other targeted enhancements.”
Nor were there any changes to how ISO-NE selects its board members. NESCOE had called on FERC to revise Order 719 to ensure “that states and consumers in New England are meaningfully represented” in the composition of the board and the Joint Nominating Committee process that governs board nominations. State officials have only one vote on the 14-member committee, through the New England Conference of Public Utilities Commissioners.
“The Joint Nominating Committee is governed by the Participants’ Agreement between the ISO and NEPOOL stakeholders,” the RTO said. “The board cannot make unilateral changes to the process for selecting new members. Any changes would need to be pursued through the NEPOOL stakeholder process and approved by FERC.”
In September, ISO-NE announced the election of four board members for three-year terms: incumbent Michael Curran and newcomers Caren Anders, Steve Corneli and Catherine Flax. The board also elected former FERC Commissioner Cheryl LaFleur as its chair, replacing the retiring Kathleen Abernathy.
Transparency Still Lacking, Critics Say
Critics were unimpressed with the RTO’s modest changes on transparency, noting that New England remains the only region in the U.S. whose RTO/ISO stakeholder meetings are closed to the public.
ISO-NE and NEPOOL have “essentially privatized public policymaking,” Tyson Slocum, director of Public Citizen’s energy and climate program, said at the RTO’s quarterly Consumer Liaison Group meeting in September. “There is inadequate transparency and accountability in these institutions that don’t reflect the public interest nature of what they’re doing.”
Rebecca Tepper, chief of the Energy and Telecommunications Division in the Massachusetts Attorney General’s Office, also lamented the lack of progress. “I think it would be good to see that move forward and have some real dialogue about how the governance process can be more accommodating to people.” (See Stakeholders Still Seeking Transparency from ISO-NE, NEPOOL.)
FCA 16
In the near term, capacity market watchers are waiting for a FERC ruling on ISO-NE’s request to prevent the 650-MW natural gas-fired Killingly Energy Center in Connecticut from participating in FCA 16 in February and to terminate its capacity supply obligations (CSO). Killingly, which initially secured a CSO in 2019’s FCA 13 for the 2022/23 capacity commitment period, failed to meet its development milestones, the RTO said (ER22-355).
Developer NTE Energy responded that ISO-NE made an incorrect assumption regarding a financing milestone date, claiming that its financing is “imminent.” In its Dec. 3 protest to FERC, NTE called the RTO’s action “premature” and said it had kept the project moving despite “challenges beyond its control, including the COVID-19 pandemic and an ultimately unsuccessful 29-month challenge to its state siting certificate.” ISO-NE responded on Dec. 20, saying the only question facing FERC was whether the plant can reach commercial operation by June 1, 2024. “The answer … is ‘no,’” said the RTO.
“There is also no dispute that to terminate Killingly’s capacity supply obligation — a valuable asset worth hundreds of millions of dollars — ISO-NE’s tariff requires the ISO to prove that Killingly would not enter service before the June 1, 2024 deadline,” NTE responded Dec. 28. “Despite its burden, to date, the ISO has offered only speculation about what might happen — repeating in its answer that it just ‘lost confidence’ in the project.”
FCA 16 also will see the end of the seven-year price lock for new entrants. FERC ruled in late 2020 that the rules, which had been in effect since the FCA began in 2006, resulted in “unreasonable price distortion” and that locked-in prices are “no longer required to attract new entry.” (See FERC Orders End to ISO-NE Capacity Price Locks.)
Prices in FCA 15 cleared at $2.48 to $3.98/kW-month — the high in Southeast New England nearly doubling 2020’s record-low figure.
Turbulent Year for Avangrid
2021 was a turbulent year for Avangrid (NYSE:AGR), the parent of Central Maine Power (CMP) and United Illuminating in Connecticut.
In May, the Bureau of Ocean Energy Management approved the final permit for 800-MW Vineyard Wind I, a joint venture of Avangrid Renewables and Copenhagen Infrastructure Partners. The first commercial-scale offshore wind project in the U.S., Vineyard Wind broke ground in November and is expected to begin commercial operation in 2023. In December, Massachusetts said it would purchase 1,200 MW of OSW from Vineyard Wind’s Commonwealth Wind project. (See Mass. Adds 1,600 MW to OSW Portfolio in Latest Procurement.)
Avangrid faced two setbacks late in the year, however.
In November, CMP halted construction on the NECEC transmission project in response to Maine voters’ approval of a referendum to block it. Avangrid filed a lawsuit challenging the constitutionality of the referendum. On Dec. 16, a judge rejected the company’s request for an injunction to block the impact of the referendum.
Central Maine Power halted construction on the New England Clean Energy Connect transmission line in November following Maine voters’ approval of a referendum to block the project. | New England Clean Energy Connect
In December, New Mexico regulators rejected Avangrid’s proposed $8.3 billion acquisition of PNM Resources (NYSE:PNM), citing Avangrid’s “demonstrated record of poor performance” in other states, including its stewardship of CMP.
The New Mexico Public Regulation Commission’s 5-0 vote also followed allegations by a former cybersecurity contractor that the company conspired with suppliers to buy “tens of millions” in overpriced and unnecessary security equipment and services to boost profits. (See NM Regulators Reject Avangrid-PNM Merger.)
Regulators in Connecticut and Maine said they would review the allegations, which came six months after Maine Gov. Janet Mills vetoed legislation to create a publicly owned utility to replace CMP and Versant Power, calling it “hastily drafted.” (See Mills Tells Maine Legislature to Slow Down on Plan to Replace IOUs.)
Annual Work Plan
ISO-NE’s Annual Work Plan lists several additional projects and timelines for 2022:
The RTO is expected to file a proposal with FERC by the end of 2022 revising resource accreditation in the capacity market, to be effective in FCA 18, with a second filing by the end of 2023, targeting FCA 19.
The RTO will focus in 2022 on proposals to co-optimize reserves in the day-ahead energy markets.
Beginning in the first quarter and extending into 2023, the RTO will work with stakeholders and the Electric Power Research Institute on ways to model high-impact reliability risks (tail risks) related to extreme weather events, an initiative prompted by the outages in Texas during the February 2021 winter storm.
The RTO expects to file changes with FERC in 2022 allowing solar resources to take electronic dispatch instructions in the real-time energy market under the Do-Not-Exceed model currently used by wind resources. The change would be effective in the second quarter of 2023.
ISO-NE plans to begin discussing tariff changes in the first quarter to allow storage-as-transmission solutions for needs assessments or public policy transmission studies.
It also hopes to complete its two-year nGEM Day-Ahead Market Clearing Engine Implementation project this year. The day-ahead clearing engine is expected to be in-service Q1 2023.
The RTO will complete three projects in 2022 concerning identity and access management; security information and event management; and a refresh of the hardware and software supporting the collection of network traffic data that feed the Network Intrusion Detection system and the Security Information and Event Management analysis system.
