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November 18, 2024

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PJM Operating Committee Briefs: March 10, 2022

Reliability Products and Services Assessment

PJM wants the Resource Adequacy Senior Task Force (RASTF) advance discussions to evaluate the RTO’s need for procuring additional reliability-based generation as more intermittent resources are integrated into the grid.

Chris Pilong and Alex Scheirer of PJM provided a first read at last week’s Operating Committee meeting of a proposed “initial direction” regarding reliability products and services required in the RASTF charter.

Pilong said stakeholders began looking at the list of generator “reliability attributes” at the beginning of the year, examining PJM’s renewable integration studies and papers to determine the recommendations for addressing potentially new reliability services and next steps in the process at the RASTF and other committees and task forces.

Chris Pilong-2018-12-11-(RTO Insider LLC) FI.jpg

Chris Pilong, PJM

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© RTO Insider LLC

Pilong said stakeholders will discuss reactive capability and supply issues in the Reactive Power Compensation Task Force to make sure PJM is able to “utilize, measure and compensate the full reactive capability of synchronous and non-synchronous generators independent of their power output.” The issue also calls for discussions on the ability of all resources to follow voltage schedules and demonstrate performance.

From a regulation perspective, Pilong said, stakeholders recommend reviewing existing regulation market signals and considering future system needs as part of the regulation market redesign issue charge approved by the Market Implementation Committee. (See “RTO to Propose Review of Regulation Market,” PJM MIC Briefs: Nov. 3, 2021.)

“If the signals are going to be reviewed and looked at, we should be looking at what are the right signals for the future,” Pilong said.

Members recommended that the Energy Price Formation Senior Task Force consider how to value flexibility of generation within the existing or modified ancillary services, Pilong said, while another recommendation would have RASTF explore how to value fuel assurance for all resources that can be relied upon for “unexpected system conditions.”

Pilong said PJM and stakeholders may evaluate methods for data submission and review the existing penalty structure if data reporting requirements in PJM manuals are not followed. He said a potential problem statement and issue charge could be brought to the OC to examine manual language changes.

“We do see, in some instances, the data is not as accurate as we need it to be, especially as the fleet of inverter-based resources begins to grow,” Pilong said. “We really need to make sure we have accurate forecasts.”

Stakeholders will vote on the recommendations at the April 14 OC meeting.

UFLS Requirements Applicable to EKPC

Denise Foster Cronin of the East Kentucky Power Cooperative (EKPC) provided a first read of a problem statement and issue charge to appropriately document EKPC’s under frequency load shedding (UFLS) requirements in PJM.

Foster Cronin said EKPC is seeking stakeholder approval of limited PJM Operating Agreement, tariff and Manual 36 changes to document the UFLS.

The purpose of the UFLS requirement is to avoid an uncontrolled loss of load situation, Foster Cronin said, and the requirements establish a total percentage of load shed that must be achieved when the system frequency drops to a certain level to maintain the system.

All electric distributors must comply with the UFLS requirement established by their respective NERC region. When EKPC integrated into PJM in 2013, the cooperative was in the SERC region of the ERO.

Before EKPC’s integration, PJM’s OA documented a UFLS requirement for entities in the “PJM Mid-Atlantic Region,” the “PJM West Region” and the “PJM South Region.” But the OA was not changed with EKPC’s 2013 integration to incorporate the cooperative’s applicable UFLS requirement, and it wasn’t included in any of the regions.

In 2018, EKPC was added to the PJM West Region when the RTO worked with stakeholders to clarify the region definitions in its governing documents. However, other entities included in the PJM West Region are in the ERO’s ReliabilityFirst region, while EKPC remained in SERC, which has slightly different UFLS requirements.

Forster Cronin said a recent review of the region revisions “highlighted a potential confusion” of EKPC’s appropriate UFLS requirement. She said the oversight did not create a reliability problem or a “compliance vacuum” for the cooperative.

“There hasn’t been any gap with respect to the actual compliance and reliability,” Foster Cronin said.

Foster Cronin said EKPC has been working with PJM on the language correction issue.

The OC will be asked to approve the issue charge and endorse the proposed solution at the April meeting. The Markets and Reliability Committee and Members Committee will ultimately endorse and approve the solution and corresponding OA revisions.

“We’re hoping the committee agrees this is a pretty straightforward item and only impacts East Kentucky Power Cooperative,” Foster Cronin said.

Manual 1 Updates

Bilge Derin, PJM senior engineer, reviewed changes to Manual 1: Control Center and Data Exchange Requirements as a part of the periodic review.

Derin said the manual changes partially resulted from revisions in NERC standards CIP-012, COM-001 and EOP-008.

Minor changes were made throughout the manual, Derin said, including removing revision numbers from where NERC standards are referenced and replacing the term “member” with “PJM member” where applicable to keep the term uniform throughout the manuals.

In Section 2.5.6: Recovery Procedures, PJM clarified the loss of control center functionality procedures and documentation relating to EOP-008 and TO/TOP Matrix.

In Section 3.2.1.1: PJMNet Communications System, the language was clarified to ensure PJM is responsible for protecting all real-time assessment and real-time monitoring data through the PJMNet private network as the data is “in transit” between the PJM control centers and its routers. The RTO must also make sure all data is encrypted.

The committee will be asked to endorse the changes at its April meeting.

Manual Changes Endorsed

Several manual changes resulting from the periodic review were unanimously endorsed by stakeholders, including:

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Conn. Lawmakers Revisit Need for Direct EV Sales Model

Lawmakers in Connecticut are taking another look at legislation that would allow auto manufacturers with an exclusive electric vehicle strategy to circumvent franchise law and sell directly to consumers in the state.

The bill (SB.214) “allows Connecticut to join 22 other states that allow all-EV-only, non-franchised manufacturers, like Rivian (NASDAQ:RVIN), Lucid (NASDAQ:LCID) and Tesla (NASDAQ:TSLA), to invest in brick-and-mortar dealerships in Connecticut,” said Kaitlin Monaghan, manager of public policy and senior counsel at Rivian.

EV-only companies would be subject to the same regulations as franchise dealers in the state under the law, if passed, according to Monaghan, who spoke Monday in support of the bill during a Transportation Committee hearing.

While current law in Connecticut requires auto manufacturers to sell their vehicles through a third-party dealership, the bill would allow the state to issue a dealer’s license to EV-only manufacturers. Under the bill, EV manufacturers would not be allowed to have a prior franchise agreement with a new car dealer or a controlling interest in or be owned by another licensed manufacturer.

“The bill allows Connecticut customers to choose the EV model and the EV purchasing experience they want,” Monaghan said. “A poll last year showed 83% of respondents support direct sales of EVs to consumers.”

A similar bill introduced in January 2021 gained some traction in the Connecticut legislature but did not pass the Senate before the end of the session. New York lawmakers are also considering a bill (S1763) that would alter dealer franchise law in the state in favor of EV manufacturer direct sales.

Recent auto sales statistics show that the presence of EV manufacturers with a direct sales approach is not hurting franchise dealerships, according to testimony by Daniel Witt, director of state and local public policy at Lucid.

“Dealers have been more profitable in the last two years than ever before,” Witt said. “That’s as Rivian and Lucid have started producing and delivering cars and as Tesla has sold more cars than ever before, globally.”

States that have allowed direct sales to customers have not lost jobs at dealerships, Kenneth Gillingham, a professor of economics at Yale University, said in testimony. “If there’s any impact at all, it’s not statistically distinguishable from zero.”

Connecticut EV owners, however, will have more money “in their pockets” because of lower costs on fuel and maintenance than for internal combustion vehicles, he said. That money, he added, will go toward in-state purchases that drive tax revenue.

Opponents of the bill in Connecticut say allowing the direct-sales model would establish two sets of rules for automobile competitors within the same market.

There is no law prohibiting Tesla, Rivian and Lucid from selling their vehicles in the state, as long as they “follow the same rules on automobile distribution that every other automaker is required to follow by law,” said Wayne Weikel, senior director of state affairs at the Alliance for Automotive Innovation, in testimony.

The franchise dealer model, however, does not work with Tesla’s approach to sales, according to testimony by Tesla Senior Policy Adviser Zach Kahn.

“By utilizing the direct-to-consumer sales model, Tesla has created a sales experience completely unlike the typical car buying experience in a dealership,” Kahn said. “We spend the time to educate our customers on the technology, answering countless questions about charging, battery performance and the like, and prepare them for electric vehicle ownership.”

Tesla’s call to change dealership laws was founded originally on its claim that the company was too small and its technology too new to compete in the existing market. But Weikel says that’s no longer the case.

An estimated 130 new EV models are due to hit the market by 2026, he said, and more companies are following in Tesla’s footsteps.

“Rivian and Lucid are asking for the same special treatment, but understand that there is a line of other startup companies right behind them,” he said.

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Maryland Senate Sets 2045 Net-Zero Target

The Maryland Senate late Monday approved legislation increasing the state’s greenhouse gas emission reduction goal to 60% below 2006 levels by 2030 — up from the current 40% target — and setting a 2045 deadline for reaching net-zero emissions (SB 528).

The Climate Solutions Now Act of 2022, which must also be approved by the House of Delegates, would target landfill methane emissions, set new energy conservation standards for buildings and require the purchase of zero-emission vehicles (ZEVs) for public school buses and the state fleet.

The bill, sponsored by Sen. Paul G. Pinsky (D), chair of the Senate Education, Health and Environmental Affairs Committee, cleared the Senate on a 32-15 vote, with all Republicans opposed.

The vote came after Pinsky last week withdrew a requirement that all new buildings use electric power, rather than fossil fuels, for space and water heating by 2024 and a mandate that new buildings be equipped to install solar energy systems and electric vehicle charging. Instead, the legislation requires the Public Service Commission to report to the legislature by September 2023 whether the electric grid can support an all-electric building code in the future.

MD GHG Emissions (Maryland Department of the Environment) Content.jpgMaryland GHG emissions and targets by year | Maryland Department of the Environment

Pinsky tweeted that the bill was “a major step forward but weakened by the utility industry that placed their profits ahead of people & the environment.”

Last year, negotiations to increase the state’s emissions-reduction target collapsed after the Senate rejected House revisions that would have set the state’s 2030 goal at only 50% of 2006 levels. (See Md. Climate Bill Dies in House-Senate Standoff.)

Among other provisions, SB 528:

      • Requires the Maryland Department of the Environment to adopt standards for methane emissions for municipal solid waste landfills by 2024 that are at least as stringent as those adopted by California.
      • Creates a Climate Justice Corps Program for 18- to 25-year-olds to work on clean energy or climate mitigation projects.
      • Requires a transition to zero-emission school buses: Beginning in fiscal 2024, county school boards would be prohibited from signing contracts to purchase or use any school bus that is not a zero-emission vehicle (ZEV) unless the school board is unable to obtain federal, state, or private funding to cover the “incremental costs” of ZEVs or there are no available ZEVs to meet the district’s performance requirements.
      • Transitions the state vehicle fleet to ZEVs: The bill sets a goal that all passenger cars in the state vehicle fleet be ZEVs by 2030 and that other light-duty vehicles in the fleet be ZEVs by 2036. It would require the state to make ZEVs 25% of all passenger cars purchased in fiscal 2023, rising to 100% beginning in fiscal 2027. Beginning in fiscal 2024, any passenger car purchased for the state fleet that is not a ZEV must be a hybrid vehicle.
      • Creates the Climate Catalytic Capital Fund, administered by the Maryland Clean Energy Center to promote environmental justice and to leverage private capital investment in technology development and deployment, including project planning. Minimum annual funding for fiscal 2024 through 2026 would be $5 million.
      • Requires annual funding of $12 million from fiscal 2024 through 2032 to help school systems cover the cost difference between meeting basic high-performance building requirements and net-zero energy requirements. Subject to funding, at least one of the schools constructed in each school system from July 2023 through June 2033 would be required to meet net-zero energy requirements. During the same period, districts would have to consider including rooftop solar panels on new schools.
      • Requires funding of $5 million annually in fiscal 2024-26 for projects to reduce direct GHG emissions from multifamily residential buildings.
      • Requires development of performance standards for “covered” buildings (non-school or historic buildings of at least 25,000 square feet) owned by the state: a 50% reduction in net direct GHG emissions by January 2030 compared with 2025 levels and net-zero direct GHG emissions by 2035. For covered buildings not owned by the state it requires a reduction of at least 30% in GHG emissions by 2035 and net-zero emissions by 2040.

The House of Delegates has been considering SB 528’s provisions in three bills heard by separate committees.

“It’s my understanding that the House is actually going to work off the Senate bill versus those three independent bills,” Kim Coble, co-chair of the Greenhouse Gas Mitigation Working Group, told a working group meeting Tuesday.

She said the Senate Budget and Tax Committee on Monday endorsed the funding for implementing the Pinsky bill. “So that is embedded in the budget at this point in time,” said Coble, who represents the Maryland League of Conservation Voters.

Working group member Sandy Hertz, of the Department of Transportation, noted that the bill passed by the Senate struck a provision making the state fleet EV targets “subject to the availability of funding.”

The bill said that “it will be done, regardless of whether or not you have the funding set aside for it,” Hertz said. “That was one thing that stood out to me as fairly impactful to us at the state level.”

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After Bills Fail, New Mexico Reforestation Program Looks for Funding

Partners in a recently formed New Mexico Reforestation Center are seeking roughly $80 million in federal funding to reach the goal of producing 5 million seedlings a year to plant in wildfire burn areas.

The Reforestation Center was created in January through an agreement among the New Mexico Energy, Minerals and Natural Resources Department (EMNRD) and three state universities: New Mexico Highlands University, New Mexico State University and University of New Mexico.

Two bills in the New Mexico legislature this year — HB101 and SB145 — would have allocated $4.6 million to the Reforestation Center. Neither bill passed.

The center’s collaborators now plan to apply for a federal grant to fund their activities.

The U.S. Department of Agriculture in February announced $1 billion in funding through its Partnerships for Climate-Smart Commodities opportunity. The funding is offered to farmers, ranchers and forest landowners to implement climate-smart production practices on working lands. Recipients are asked to quantify the greenhouse gas benefits of those practices and develop markets for the resulting climate-smart commodities.

Proposals ranging from $5 million to $100 million will be considered in the first funding pool. The application deadline is April 8.

Growing Capacity

The state needs more than 300 million seedlings for a backlog of burned areas, according to EMNRD, but the current tree nursery capacity is 300,000 seedlings per year.

The New Mexico Reforestation Center’s goal is to grow 5 million seedlings per year. And the seedling production will be “climate smart,” to increase the odds that trees planted now will survive in future climate conditions.

“The new Reforestation Center will increase the number of acres planted each year, which in turn contributes to healthy watersheds and climate change resiliency,” EMNRD Secretary Sarah Cottrell Propst said in a release.

Joshua Sloan, associate vice president of academic affairs, Forestry and Reforestation Center at New Mexico Highlands University, told NetZero Insider that two steps are being taken to produce climate-smart seedlings.

The first is to collect seeds from trees that, through natural selection, have shown that they can handle heat and drought.

The next step focuses on how the seedlings are grown. Rather than watering them regularly, Sloan said, water is limited so that the seedlings begin to adapt to drought conditions. The idea is to prevent the transplant shock that seedlings grown in conventional ways often experience.

In another part of the project, researchers at the University of New Mexico will be working on forest climate modeling and quantifying carbon capture by trees.

“Every seedling we put on the landscape is a carbon sink,” Sloan said.

The Reforestation Center also includes a workforce development component.

“A skilled forestry workforce is necessary to plant the seedlings grown by the Reforestation Center,” New Mexico Highlands University President Sam Minner said in a statement. “Our students and faculty will be training the next generation of tree planters and foresters.”

Funding Sources

The reforestation team is still working on its application for USDA funding, but Sloan said the request would likely be for about $80 million. The funding would cover the costs to build the new, high-capacity nursery and keep it running for five years.

Meanwhile, Sloan said, the reforestation efforts have received some smaller contributions, including a private donation and in-kind support. The funds are enough to jump-start the seed collection project, he said.

Although the bills requesting $4.6 million for the Reforestation Center failed, the state legislature approved an $80,000 annual appropriation to EMNRD for reforestation projects, department spokeswoman Susan Torres said.

The legislature also approved a new full-time reforestation coordinator in EMNRD’s Forestry Division. The employee will be responsible for statewide seed collection and planting coordination.

Statewide Strategies

Reforestation is one of 10 strategies outlined in New Mexico’s Forest Action Plan, and it’s also discussed in the state’s 2020 Climate Strategy.

“Our forests, grasslands, and agricultural lands have a large part to play in absorbing CO2 as we work towards fewer emissions,” the climate strategy said in a section on natural and working lands.

The climate strategy calls on the Forestry Division to develop a plan for incorporating drought-tolerant plants in reforestation efforts. In addition, the division will use research on wildfire burn areas to identify microsites where seedlings are more likely to survive.

The approaches to tree-planting will be shared with other state divisions and agencies. For example, EMNRD’s Mining and Minerals Division could use the Forest Division strategy in its mine reclamation reforestation work.

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MISO Sees Chance of Emergencies This Spring

In a now-familiar refrain, MISO is warning stakeholders of possible maximum generation emergencies should high load and high outages collide this spring.

Under probable load scenarios with expected outages, MISO expects to have:

  • 99 GW of available capacity in March to cover an 88-GW peak demand estimate;
  • 91 GW of available capacity in April to cover an 83-GW peak; and
  • 101 GW of available capacity in May to cover a 91-GW peak.

However, the RTO said should elevated load and excessive outages enter the picture, it could find itself declaring an emergency to access its emergency-only resources in April and May. MISO said it doesn’t see itself exhausting its 12 GW of load-modifying resources and operational reserves, even in the direst situations.

In a worst-case scenario, the grid operator would have just 79 GW of non-emergency capacity in April should demand reach 88 GW. Under the same scenario in May, MISO would have 95 GW of capacity to handle a 104-GW demand peak. In both cases, staff would be forced to access emergency supplies.  

MISO set its all-time spring peak of 111 GW in May 2018.

Over the past five years, the RTO has experienced an average 36.3 GW of forced and planned outages during spring monthly peaks. It saw its highest on-peak spring outages at 54.2 GW in April 2019.

MISO did not alter this year’s spring reliability outlook to include the loss of its firm contract path linking its Midwest and South regions through June 30. Staff said it wasn’t necessary to factor the line loss into its forecasts because it was unlikely to cause any operational impacts. (See MISO Midwest-South Transfer Service on Outage until July.)

The National Oceanic and Atmospheric Administration predicts higher-than-average temperatures for MISO South and a chance at higher temperatures across most of the Midwest, except for the northernmost portion of the footprint. NOAA also expects much of the Midwest to experience more precipitation than usual.

MISO ended winter without the serious reliability event it was steeling itself for. The grid operator had a 100.2-GW winter peak on Jan. 21, 2022, about 9 GW short of the all-time winter peak set in early 2014 during a polar vortex.

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FERC Allows Quicker MISO Interconnection Queue Option

FERC on Monday granted MISO’s request to give generator interconnection customers an opportunity to reduce their time in the interconnection queue from more than 500 days to a single year.

In a letter order issued Monday, the commission said MISO could offer interconnection customers a faster finish time in return for proceeding without definitive network upgrade cost information (ER22-661).

The grid operator is hoping to whittle about 140 days from its generator interconnection process by cutting the days allotted for interconnection agreement negotiations and study and performing some study aspects simultaneously. (See Shorter Interconnection Queue Coming, MISO Says.)

Interconnection customers in the final phase of MISO’s three-part definitive planning process will now have a choice to spend 60 days in the stage without waiting on a network upgrade facilities study before proceeding to generator interconnection agreement (GIA) negotiations. Their other options is to spend about 150 days in a holding pattern while they wait on a final upgrade report.

GIA negotiations will be condensed from about 150 days to around 108 days under MISO’s plan.

FERC said the reductions stand to improve the interconnection queue’s efficiency.

The commission said it was appropriate for MISO to offer “each interconnection customer a choice between a timelier path to GIA negotiations with less cost certainty or a less timely path with more cost certainty entering into GIA negotiations, based on its preferences.”

FERC said generation developers that opt for the shorter path will do so with the “understanding that their assigned costs may be refined in the final interconnection facilities study report.”

MISO has said shortening the queue timeline will help it better align network upgrade planning with its transmission expansion plan, which is conducted on an annual basis.

For years now, the RTO has placed an emphasis on accelerating hold times for generation waiting for system access in its interconnection queue. Last month, the queue held 133 GW of projects, comprising mostly renewable generation.

Some stakeholders have expressed concerns that MISO can accomplish its goal. They say the real slowdown lies in the RTO’s notoriously time-consuming affected system analyses with its neighbors. Staff have said that if the new changes don’t meaningfully shorten queue wait times, MISO will pursue additional changes.

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FERC Accepts PJM ARR/FTR Market Changes

FERC on Friday accepted PJM’s revisions intended to increase transparency into and the efficiency of the RTO’s auction revenue rights (ARR) and financial transmission rights markets (ER22-797).

The commission’s decision marks a milestone for PJM after it and its stakeholders spent several years discussing changes to the markets after the GreenHat Energy default in 2018.

PJM filed the proposal in January after stakeholders endorsed the revisions at the Markets and Reliability Committee and the Members Committee in the fall with majority support. The FTR portion of the tariff revisions will take effect on Sept. 1, and the ARR portion on Feb. 1, 2023.

“We find that PJM’s proposal is just and reasonable because it enhances hedging opportunities for load and helps enhance market liquidity and future price discovery,” the commission said.

PJM’s proposal included revisions to its tariff and the Operating Agreement that were guided by the findings of a report developed by London Economics International (LEI).

PJM-ARR-FTR-market-design-(London-Economics)-Content.jpgProposed enhancements to PJM’s current ARR/FTR market design. | London Economics

 

The RTO said its proposal aimed to recognize recommendations made in the LEI report and address concerns raised by the Independent Market Monitor and stakeholders. The proposal also sought to maintain the consultant’s conclusion that the existing FTR product is “reasonable and generally achieving the intended purposes” of serving as a financial equivalent to firm transmission service and to ensure “open access to firm transmission service by providing a congestion-hedging function.”

“The LEI report found that PJM’s FTR/ARR market design is achieving its dual purposes of facilitating the return of congestion charges to load and enabling hedging and supporting forward market activity, and overall is ‘creating overall positive value for load,’” the commission said. “However, the LEI report outlined potential enhancements to PJM’s FTR/ARR market design, focused on the themes of equity, efficiency and transparency, which PJM reflected in the instant proposal.”

The revisions make it so ARRs are allocated based on 60% of network service peak load, rather than zonal base load. They also provide additional self-scheduling options for ARR holders; add new FTR class types for on-peak weekday, on-peak weekend and holiday, general everyday off-peak and 24-hour products; increase the bid limits in all FTR auctions from $10,000 to $15,000; and add a $1/MW-period class clearing price floor for all FTR option products.

Protests

Several stakeholders protested portions of PJM’s proposal.

A group of consumer advocates — including the D.C. Office of the People’s Counsel, the Citizens Utility Board, the Delaware Division of the Public Advocate, the Maryland Office of People’s Counsel, the New Jersey Division of Rate Counsel, the Pennsylvania Office of Consumer Advocate and the PJM Industrial Customer Coalition — said they supported PJM’s proposal but maintained that it “does not go far enough in some respects.”

The advocates argued that even though a more direct alignment of congestion revenues and costs is “undoubtedly a step towards a more efficient and equitable FTR/ARR market,” the change doesn’t address situations where surplus congestion or auction revenues occur and “should be returned to the load that paid for the transmission upgrades that made those surplus revenues possible.”

Dominion also expressed support for portions of the proposal, but it argued that the revisions don’t fully address the “under-allocation of congestion revenues” for load and an inability of certain load-serving entities to “come close to covering their congestion costs.” Dominion said PJM’s filing “does little” to address “disparate outcomes” under the current ARR/FTR construct that “persistently creates results where the congestion cost recovery by LSEs varies greatly.”

The Monitor alleged that PJM’s filing “perpetuates or worsens fundamental flaws in the existing PJM FTR/ARR market,” saying the current market design “consistently failed to return the congestion revenues to the load that paid it.”

It also argued that the total congestion offset paid to load is “inequitable and varies by zone,” with some zones receiving more in offsets than the total congestion payments and other zones receiving less in offset. The offsets “are a function of the assignment of ARRs and the valuation of ARRs in the FTR auctions” and that the expansion or modification of the path-based rights available to load and the market will “simply change the arbitrary allocation of congestion among ARR holders and participants in the FTR market and will not correct the arbitrary allocation of congestion.”

FERC Determination

The commission said it determined the ARR market construct were just and reasonable and that the expansion of the source/sink combinations of the ARR allocation process “provides load the first rights to the transmission system before FTR holders can purchase such rights and, therefore, increases the network capacity allocated to load.”

“While not the sole purpose, one of the purposes of the FTR/ARR market is to return congestion charges to load, and this proposed change is consistent with that purpose,” FERC said.

FERC said the proposal’s call to replace zonal base load “protects zonal native load hedging ability by increasing up-front capability to load.” The commission said PJM’s selection of the 60% standard was a “reasonable limit at which additional value could be guaranteed” without significantly increasing violations or producing additional transmission constraints.  

It also said that “PJM’s proposal to not award FTR options with a market-clearing price of less than $1 mitigates risk-free profit by ensuring all FTR options that clear have, at least at the time they were bid and awarded, actual value,” the commission said. “We also find that PJM’s proposal to create new FTR class types provides more flexible hedging opportunities.”

The commission said it disagreed with the challenges to how congestion surplus is allocated and the “fundamental nature” of a path-based FTR/ARR construct. It said the protests citing concerns regarding provisions of the existing FTR/ARR market construct were outside the scope of the proceeding.

FERC also disagreed with the Monitor’s argument that the revisions in the proposal do not return “sufficient” congestion revenue to load, saying it rejected the “foundational argument” that the “sole purpose of FTRs is to return congestion revenue to load and the market should therefore be redesigned to accomplish that purpose.”

“PJM’s proposal is not rendered unjust and unreasonable simply because the IMM thinks a further allocation to load would be desirable,” FERC said. “Consistent with commission precedent, we reiterate that ‘the purpose of FTRs to serve as a congestion hedge has been well established.’ FTRs were designed to serve as the financial equivalent of firm transmission service and play a key role in ensuring open access to firm transmission service by providing a congestion-hedging function.”

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ERCOT Seeks Greater Transparency into Gas Market

ERCOT interim CEO Brad Jones last week continued his push for a Texas gas desk in testimony before state legislators, who are toying with the idea creating a gas market monitor after disruptions in fuel supplies nearly collapsed the grid during last winter’s major storm.

Appearing Wednesday before the Senate Business and Commerce Committee, Jones compared ERCOT’s lack of transparency into the state’s natural gas system with looking through a peephole in the front door.

“We see images, we see shapes, but we don’t necessarily see the full picture of what we need to see. We don’t have a full view of the reliability situations in the gas market,” he said. “This is important today in our market as we try to assess the reliability of natural gas generators to get the fuel they need to produce the generation we need.”

Jones told the committee that ISO-NE, NYISO and PJM all have gas desks manned by staff 24/7. He has for several months pitched the grid operator’s board and stakeholders on the idea of having staff who “can gather that information and make sure we have the situational awareness we need at ERCOT.”

“We don’t know when a pipeline is out for maintenance or a compressor station on outage for something that is broken,” Jones said.

Brad Jones Testifies (Texas Senate) Content.jpgERCOT’s Brad Jones (right) testifies before a Texas Senate committee as (left to right) Division of Emergency Management chief W. Nim Kidd, Railroad Commissioner Wayne Christian and PUC Chair Peter Lake listen. | Texas Senate

In October, he said staff “discovered by happenstance” that one generator it was counting on for power during a future low-wind day would not be able to operate because its gas supply transportation system would be undergoing maintenance. After a few calls and with the regulators’ help, staff was able to identify the transportation company and have the maintenance outage rescheduled “in a very cooperative way.”

“It was very helpful they did that, but the key is we didn’t know the information we needed to know,” Jones said.

For the moment, Jones believes the grid operator can get the information it needs through “voluntary cooperation,” but with the Texas Energy Reliability Council’s lead. The agency is made up of leaders from ERCOT, state regulators and industry. It has been meeting once or twice a month lately, helping improve coordination between the electric and gas sectors.

Asked whether Jones needed anything from legislators to make the gas desk a reality, he said not for the time being.

“The TERC has the capability to work through these issues,” he said. “Absent a cooperative environment, which I fully believe we have with the gas companies, TERC has the ability to make those recommendations to the legislature for the next legislative session.”

Increasing Oversight

The back-and-forth revealed that legislators may be conflating an operations desk like some gird operators have with the market monitors that keep an eye on wholesale electricity markets.

However, the gas industry is commonly seen as the weak link in ERCOT’s ability to meet demand with supply. While the grid operator’s generation and transmission facilities were required to be winterized and inspected before this winter, gas facilities don’t have to meet the same requirements until next winter.

The Railroad Commission (RRC), which regulates Texas’ intrastate oil and gas industry, is seen as being too chummy with the industry it regulates and has been accused of slow-walking regulatory changes. The commission’s first winterization rules allowed companies to opt out for a $150 fee, but that was changed after political pushback. (See Texas Senators Call for New RRC Weatherization Rules.)

A joint report by FERC and NERC pointed to the lack of consistent natural gas supplies to power plants as among the major causes for the widespread outages that followed last year’s winter storm. Natural gas supplies again dropped this year during several cold fronts, indicating shut-in production at Texas natural gas facilities, Bloomberg said.

“We need to continue our oversight responsibilities,” Committee Chair Charles Schwertner (R) said. “I think what happened last February has in some part the responsibility and blame of the legislature for lack of oversight.”

RRC Chair Wayne Christian was evasive in several of his responses to the committee. He told the committee there is “no state, nation, anything” that has daily monitoring and reporting of the gas supply.

Christian, who faces accusations of ethics violations, is in a Republican primary runoff with oil and gas attorney Sarah Stogner, who gained attention with a racy video involving her riding a pumpjack.

“I hesitate to add another layer of government regulation to the free market natural gas system.” Christian said.

He may not have a choice. Sen. Donna Campbell (R) said she might file legislation to gain greater transparency into the natural gas market when the 88th Texas legislature goes into session next January.

“I haven’t heard of any agency that wants more regulation by the legislature, but I will take that up,” Campbell said.

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New York Bight Winners Talk Supply Chain at NECA Renewables Conference

Offshore wind developers and experts, including representatives of three of the six winning bidders in last month’s federal New York Bight auction, see robust supply chain opportunities growing in the Northeast.

Jordan Shoesmith (NECA) Content.jpgJordan Shoesmith, Copenhagen Offshore Partners | NECA

There is $500 million of state funding available in New York for supply chain infrastructure, including ports, manufacturing and other types of investment, with a potential of $2 billion in total investment, said Jordan Shoesmith, head of business development in the U.S. for Copenhagen Offshore Partners.

The Danish company owns the southeasternmost lease area off Massachusetts and won the smallest lease area in the New York Bight auction in February. Six companies offered more than $4 billion for leases representing 5.6 GW of offshore wind capacity in the New York Bight. (See Fierce Bidding Pushes NY Bight Auction to $4.37 Billion.)

The public funding is not only “a lot of money, but also a huge opportunity to deliver the kind of real supply chain that’s going to last for generations,” Shoesmith said during the Northeast Energy and Commerce Association 2022 Renewable Energy Conference Thursday.

Carrie Cullen Hitt (NECA) Content.jpgCarrie Cullen Hitt, NOWRDC | NECA

Supply chain issues are challenging for everyone in the business, and increasingly, both from a regional and international perspective, leadership from the federal administration and even the states could be quite helpful, said panel moderator Carrie Cullen Hitt, executive director of the National Offshore Wind Research and Development Consortium.

The consortium recently selected six organizations to receive a total of $3.4 million for projects related to supply chain efficiency, asset monitoring and inspection.

“New innovation is happening really quickly in terms of the materials that will be used and where and how they will be produced, so it’s really great to see some response from industry now that we actually see real commitments and deployments start to occur,” Hitt said.

Nabil Hitti (NECA) Content.jpgNabil Hitti, National Grid Ventures | NECA

With the “obvious” scaling of OSW in the U.S., “it’s crucial to get the supply chain … moving in the right direction urgently,” said Nabil Hitti, head of U.S. offshore wind at National Grid Ventures, which launched a joint venture, Community Offshore Wind, with RWE Renewables on Wednesday.

The partnership secured the largest lease area in the recent auction, nearly 126,000 acres, where it plans to develop up to 3 GW of capacity.

State solicitations are tending to put more weight on environmental benefits and economic investments that a project will bring, including the developer’s willingness to invest in supply chain development and jobs programs, said Christen Wittman, project director at Attentive Energy, provisional winner of the second-largest lease in the recent auction and a subsidiary of TotalEnergies.

“You’ll see developers submitting into New York, New Jersey and other states really full packages of what the project will look like and what commitments we would intend to make for the full structure and supply chain … but also incorporating elements of demonstrating project viability [and] risk mitigation,” Wittman said.

New Jersey is pushing its next solicitation back to early next year while the state considers an independent, coordinated transmission buildout, and New York released a draft OSW renewable energy certificates solicitation on Friday for comment. The state has not set a date for the official release of the solicitation.

New York’s strategy “is about being savvy with the investments in order to accelerate deployment,” said Adrienne Downey, principal engineer and U.S.-Canada manager at Sweden-based floating project developer Hexicon. Downey served previously as principal engineer for OSW at the New York State Energy Research and Development Authority (NYSERDA), which manages the state’s solicitations.

“We know that we achieve cost benefits if we work on deployment … but also that the Public Service Commission has taken a very enlightened and nuanced view that now we can create and cultivate a self-fulfilling prophecy of a declining cost curve by investing strategically in the supply chain,” Downey said.

Transmission Choices

States and RTOs are taking a more proactive approach to transmission, and in addition to the PJM-New Jersey state agreement approaches, there is also NYSERDA’s approach with the mesh-ready system design, which is also trying to solve these issues with innovative policy choices, Shoesmith said. “I think more and more we’ll see policymakers heading that direction.”

There’s legislation in Massachusetts (H.4515) to include a requirement for a transmission-only solicitation to occur this year, he said.

“We’ll see if it actually gets passed in time for that to happen, but I think it is something we have to think about very proactively,” Shoesmith said.

Al McBride (NECA) Content.jpgAl McBride, ISO-NE | NECA

ISO-NE has been working in partnership with the transmission owners and distribution companies to identify how interconnection studies and cluster studies are done, said Al McBride, director of transmission services and resource qualification at ISO-NE, speaking on a panel about state goals and grid policy.

“That’s in the near term, and in the longer term we’re also undertaking a 2050 study looking at what the transmission system might need to look like after all of these resources have entered and the system is changed to more transportation and heating being provided by electricity,” McBride said.

The grid operator is working to update how resources are accredited for the full capacity market to capture the balance between intermittent and baseload generation, according to McBride.

Others just want to get going with their projects.

“Put turbines in the water and let people see what the actual implications are and the actual benefits, and I think it becomes a lot less intimidating,” Wittman said. “To kick off site investigations by the end of the year is key for us.”

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FERC Again Rejects Invenergy’s SPP Waiver Request

FERC on Thursday modified its discussion of a previous order rejecting Invenergy’s request to waive SPP’s financial security posting requirements, denying a rehearing request by operation of law.

The commission said in a letter order that it continued to find Invenergy’s waiver request does not address a concrete problem, as required under FERC’s four-part waiver criteria (ER21-2807).

Invenergy Wind Development and Invenergy Solar Development asked for the rehearing after the commission in December found that developer did not demonstrate that its potential loss of posted financial security “is a concrete problem that warrants waiver.” (See FERC Splits on Waivers from SPP IC Process).

The renewable developer said it had eight interconnection requests pending in the same SPP queue cluster as another developer. It alleged that the RTO said the study would need to be redone because requests higher in the queue were withdrawn from an earlier cluster. Invenergy said a discussion with SPP staff about the upgrades and assigned cost allocations left its questions unresolved.

Invenergy said that, faced with the choice of withdrawing its requests or posting a third financial security to preserve its option to stay in the queue and avoid losing previously paid security amounts, it chose to post security under protest for three of its eight projects.

FERC said Invenergy’s waiver request would address the potential to lose its posted financial security if it were to withdraw from the queue with a corresponding impact on the cost and timing of the remaining and lower queued interconnection customers.

“We continue to find that this potential loss is not a concrete problem that warrants waiver of the tariff as Invenergy has not been confronted with forfeiture of its financial security at this time,” the commission said.

Commissioner Mark Christie, who dissented from the previous order, concurred this time, saying it “represents the least bad alternative at this time.”

“It is undeniable that the commission’s ‘case-by-case’ implementation of its waiver policy has allowed it to, in this instance, provide undue preference for one interconnection customer over another without adequate justification,” Christie said. “Here, however, my colleagues have taken advantage of this discretion to reach outcomes that are both arbitrary and unduly discriminatory, and in doing so have undermined whatever value remained of the commission’s four-pronged waiver ‘test.’

“I hope going forward, we can reexamine the commission’s waiver policies to provide clear guidance that can be consistently and fairly applied going forward,” he said.