FERC on Tuesday conditionally granted Rockland Electric Co.’s request for a new base return on equity (ROE) of 10.54% and a 50-basis-point ROE adder for its continued participation in PJM (ER22-910).
The commission also accepted Rockland’s proposed updated annual transmission revenue requirement (TRR) under PJM’s tariff, suspending it for five months to become effective Aug. 30, subject to refund.
Both the ROE and TRR will be subject to review in hearing and settlement judge procedures established by the commission.
Rockland’s service territory includes parts of three counties in New Jersey that border New York — Bergen (eastern division), Passaic (central division) and Sussex (western division). The company said it turned over operational control of its eastern division transmission assets to PJM in 2001, while Rockland’s central and western divisions, along with Orange and Rockland Utilities (O&R), are members of NYISO.
According to Rockland, New Jersey law does not mandate that it maintain membership in PJM or any other transmission organization. Rockland said its transmission systems with O&R have historically been operated as a single system, “irrespective of state geographical boundaries or regional operating authority jurisdiction,” and O&R “continues to design and operate them as a single integrated system.”
“Prior to joining PJM, Rockland contends that it did not have its own annual transmission revenue requirement or transmission rates on file with the commission,” FERC said in its order. “However, upon joining PJM, Rockland separated its annual transmission revenue requirement for its eastern division from O&R’s transmission rate.”
Rockland said it conducted a “variety of transmission projects to expand and improve the safety, reliability, and capacity” of the integrated transmission system from 2016-2020 that “justifies” it updating its transmission rates. The company said it derived its updated annual transmission revenue requirement by:
calculating the 2020 annual revenue requirement for the integrated transmission system of $73,637,503 and
multiplying it by the ratio of the 2020 Rockland system peak load of 395 MW to the 2020 integrated transmission system peak load of 1,416 MW.
Rockland said it applied the calculation with a reduction of $187,217, which “accounts for the annual passback of net excess accumulated deferred income taxes (ADIT),” coming up with an updated annual transmission revenue requirement of $20,354,318, equating to $51,530 per MW/year.
The company said the updated rates were just and reasonable because they are “derived from a methodology the commission has already approved” and “reflect a composite fixed charge rate composed of reasonable factors derived from reasonable calculations.”
Rockland also requested a 50-basis-point adder to its base ROE for continued participation in PJM, saying the commission approved the participation adder in its 2017 rate case. The company said its PJM membership “continues to be voluntary.”
The New Jersey Division of Rate Counsel argued that Rockland “improperly proposes to include the costs of facilities that are physically located within the footprint of and under the control of NYISO and are not available for use by PJM transmission customers.” The Rate Counsel also argued that Rockland’s load ratio share methodology “leads to a result in which a PJM transmission customer physically located in the PJM footprint is paying a portion of the costs of O&R facilities located within the NYISO footprint that NYISO operates and controls.”
“Rate Counsel argues if the combined O&R and RECO transmission facilities are an integrated transmission system, then the customers on the two systems are similarly situated and it would be unduly discriminatory for customers on an integrated transmission system to pay different rates as a result of where on the overall system they connect,” FERC said in its order.
Rockland responded by saying the Rate Counsel attempted to “inaccurately paint a picture that the integrated transmission system consists of two separate and distinct pieces that are operated and controlled by two different regional transmission organizations.”
The company also said that if the commission adopted the Rate Counsel’s rationale, it “may have widespread dramatic impacts on transmission ratemaking with respect to any transmission system that is owned by more than one utility.”
Commission Finding
FERC conditionally granted the request for a 50-basis point adder, saying it was consistent with Section 219 of the Federal Power Act and commission precedent.
“Rockland is a member of PJM, and there is no evidence in the record suggesting that its membership is not voluntary, such as evidence suggesting New Jersey law mandates Rockland maintains its membership in an RTO,” FERC said.
The commission conditioned its approval on the adder being applied to a base ROE shown to be “just and reasonable,” with the resulting ROE required to fall within “the applicable zone of reasonableness,” to be determined in the settlement judge procedures. Approval of the incentive was further conditioned on Rockland’s continued membership in PJM.
The commission found that its preliminary analysis suggested the proposed rate changes “may be substantially excessive” and would be “more appropriately addressed in the hearing and settlement judge procedures.”
FERC suspended the rates for five months and encouraged the parties to the proceeding to “make every effort to settle their dispute” before hearing procedures begin.
Commissioner Mark Christie issued a concurrence, saying an ROE “should reflect the market cost of equity capital, no more and no less, to the best of the regulator’s ability to determine, including pricing in risk.”
“An ROE adder, by definition, awards the utility more than the market cost of equity capital,” Christie said. “An ROE adder is literally an involuntary gift from consumers to a monopoly provider. While I recognize that ROE adders for RTO membership reflect current commission policy dating back several years, it is my hope we will finalize our proceeding initiated last year. This is particularly salient at a time when transmission charges are among the fastest growing components of consumers’ bills.”
Reaching President Joe Biden’s goal of putting 30 GW of offshore wind off the Atlantic and Pacific coasts by 2030 will require a supply chain capable of producing more than 2,100 wind turbines and more than 6,800 miles of cables, according to a report released Monday by the National Renewable Energy Laboratory (NREL).
And most of the components for those turbines and cables must initially come from Europe, even though “it is unlikely that the international suppliers will have sufficient throughput to support construction of both European and U.S. offshore wind projects,” the report says.
“If a domestic supply chain is not developed in time, bottlenecks in the global supply chain will present a significant risk to achieving the national offshore wind energy target,” the report says.
But Ross Gould, vice president of supply chain development at the Business Network for Offshore Wind (BNOW) sees such supply chain challenges in terms of economic development and job growth. “We know that there is a wide range of opportunities for manufacturing companies in the U.S. to participate in the offshore wind supply chain,” said Gould, who worked with NREL on the report. “These offshore wind projects have the capability of creating tens of thousands of jobs.”
By 2028, offshore turbines using 100% American-made components could create up to 62,000 jobs, the report says, and even turbines with only 25% domestic content could generate about 15,500 jobs, the report says.
But the path to hitting any of those numbers, as laid out in the report, is daunting. For example, while plans are underway to build 11 new OSW manufacturing facilities that can produce major components, such as turbine blades and towers, major gaps exist in the domestic supply chain for the components those factories will need.
Offshore turbines contain around 8,000 components, many of them much larger than similar components for onshore turbines, Gould said.
Offshore turbine blades are as long as a football field, “significantly larger than their onshore relatives,” Gould said in an interview with NetZero Insider. “And so, while we have the capabilities to produce [blades] for onshore, those companies would need investment to upgrade their equipment, as well as potentially training [employees] on the new equipment.”
Other components are not being produced, or produced at scale, in the U.S., the report says. For example, the permanent magnets used in offshore turbine generators require rare-earth metals that are not mined and cannot, at present, be processed in the U.S.
Still another obstacle, the huge size of some offshore components may also mean they can’t be transported by highways, Gould said. They will need to be built near a body of water and port facilities large enough and deep enough for the wind turbine installation vessels (WTIVs) and other ships used to build and operate offshore projects ― which brings up additional supply chain gaps, the report says.
Of the 22 ports on the Atlantic Coast, the Portsmouth Marine Terminal in Virginia is the only one that currently has the capacity to accommodate WTIVs, the report says. Others, such as the New Bedford Marine Commerce Terminal are not large enough but can serve as marshalling areas, using smaller “feeder barges” to ferry components out to installation vessels.
Such workarounds may be less expensive, the report says, but “they also introduce additional risk and logistic complexity to transfer components from the barge to the WTIVs at sea.”
These installation vessels must also comply with the provisions of a 1920 federal law known as the Jones Act, which requires that ships carrying goods between U.S. ports be American built, owned and operated. The report estimates that at least five such ships will be needed, but only one is currently under construction, for Dominion Energy’s Coastal Virginia Offshore Wind project.
Estimated cost per WTIV ranges from $250 million to $500 million, the report says, and each ship could take up to three years to build.
The Next BOEM Auction
The study is the first of two reports NREL and other industry stakeholders, including BNOW, will be producing on the offshore wind supply chain. The first part is intended to set out the scope of the needed buildout and the challenges ahead, Gould said. The second, to be published later this year, will look more closely at the kinds of investments and other support that will be needed to reach Biden’s 30 GW goal.
The push for getting an offshore supply chain up and running as quickly as possible is being driven by the growing number of offshore projects in development up and down the East Coast.
In February, the Bureau of Ocean Energy Management (BOEM) held a record-breaking auction for six offshore leases in the New York Bight, pulling in bids totaling $4.37 billion. If fully developed, the six auction sites could produce more than 19 million MWh of electricity per year, enough to power close to 2 million homes, based on BOEM’s estimate of 3 MW/sq km. (See Fierce Bidding Pushes NY Bight Auction to $4.37 Billion.)
The next BOEM auction, announced Friday, will be held on May 11, for two offshore leases in the Carolina Long Bay, off the coasts of North and South Carolina. According to the BOEM announcement, the two sites, totaling 110,091 acres, could produce up to 1.3 GW of energy, enough to power 500,000 homes. The final sales notice for the auction lists 16 eligible bidders, including Duke Energy Renewables, Ørsted North America and Shell New Energies.
With thousands of megawatts to be built in less than a decade, Matt Shields, senior offshore wind analyst at NREL, estimates that two or three manufacturing plants will be needed for each major offshore wind component, such as blades and cables. Costs per facility could range from $200 million to as high as $900 million, he said.
“These figures typically don’t include additional investments in port capabilities to support these big facilities,” Shields said in an email to NetZero Insider. “We can safely say that, if we do build all these facilities, it will be in the billions of dollars and will require a mix of public [and] private investment.”
While the current report does not address policy, Shields said, “There are a lot of nuances about what exactly is needed. … The most important thing is certainty about projects actually getting built so that OEMs can have low-risk return on investment.”
FERC on Monday approved an agreement between Dynegy and its Office of Enforcement that will have the company pay more than $569,000 to settle allegations that it violated the PJM tariff by misrepresenting the ramping levels of 10 of its combined cycle combustion turbines in 2017 (IN22-3).
Enforcement found that the units’ real-time energy market offers misrepresented that they could “ramp to their maximum oil-based output attained during their summer capacity tests (ICAP) while running on gas.” The office also alleged that Dynegy failed to comply with the requirement that each unit be able to “change output at the ramping rate specified in the offer data.”
Dynegy stipulated to the facts in the agreement but neither admitted nor denied the alleged violations. The company agreed to pay disgorgement plus interest, totaling $119,425 and a civil penalty of $450,000 to the U.S. Treasury and to submit two annual compliance monitoring reports identifying “any known violations” regarding the PJM units identified in the investigation.
“The PJM market and its market participants bore the cost of Dynegy’s violation,” FERC said. “The commission directs PJM to use its best efforts to allocate the disgorgement funds on a pro rata basis to affected market participants.”
Background
The commission said the 10 units identified in the investigation were split among three facilities in PJM: Pleasants Power Station in West Virginia; Armstrong Power Station in Pennsylvania; and Troy Energy Facility in Ohio.
FERC said during PJM’s capacity auctions for the 2016/17 and 2017/18 delivery years, the previous owner of the units offered and cleared capacity “at a level that would require the units to run on oil” to meet their ICAP during a capacity test, with Dynegy inheriting an “oil-based” ICAP for each unit for both delivery years when they were acquired.
“However, these units were unlikely to be able to reach their oil-based ICAP when the units were already running on gas on summer days in 2017 consistent with the ramp rate that Dynegy entered for these units’ real-time offers,” FERC said.
In the summer of 2017, Dynegy’s real-time offers represented that the units could attain oil-based ICAP “in less than a minute if dispatched from a unit’s maximum output on gas that day to the higher oil-based ICAP.”
FERC said for the units to achieve maximum output after starting on gas in the summer months, they would “likely have to switch to oil” by ramping down to about 20 MW and then ramping back up after the fuel changeover was completed. The process would take about 28 minutes to go from the unit’s daily maximum output on gas to the oil-based ICAP.
The investigation found the real-time offers “misrepresented the ramping rate for the segment of the real-time offer curve that could only be reached on oil” and that Dynegy submitted “false or misleading information” to PJM that the units could ramp upward to the oil-based ICAP in one minute.
Dynegy calculated each combined cycle’s maximum generation using a formula incorporating the next day’s forecasted ambient conditions under both gas and oil, the commission said, and the calculations were used to determine the unit’s day-ahead and real-time offer curves and economic maximum for the day.
“In the summer months of 2017, the oil-based ICAPs were generally too far above the daily predicted gas max for Dynegy to reasonably expect that the units could reach their oil-based ICAP on gas alone,” FERC said.
Dynegy sold the Troy and Armstrong facilities in July 2017 to LS Power. Vistra (NYSE:VST) acquired Dynegy, including the Pleasants units, in April 2018.
Constellation NewEnergy (CNE) has agreed to pay $4.7 million in penalties for violating CAISO tariff provisions related to the treatment of imports intended for resource adequacy.
FERC on Tuesday issued an order approving a settlement in which the company will pay a $2.4 million civil penalty to the U.S. Treasury Department for violating the RA rules and associated FERC regulations. The company must also disburse $2.3 million in funds to CAISO, which will be distributed to network load (IN22-4).
A subsidiary of Constellation Energy (NASDAQ:CEG), CNE describes itself as “a full-service energy company that provides comprehensive and innovative solutions to meet the energy needs of governmental, large commercial, institutional and industrial customers.”
At issue in Tuesday’s order was CNE’s past practice — until 2017 — of not sourcing electricity for import before selling energy into CAISO’s day-ahead and real-time markets.
“CNE did not have a specific source of power linked to a specific RA import prior to submitting offers and instead intended to rely on the bilateral spot energy market if needed,” the commission wrote. “As a part of this business practice, CNE regularly offered its import capacity into the CAISO day-ahead market at $399/MWh. If those day-ahead offers cleared, CNE would reoffer the import capacity in the real-time market at either $899/MWh or $999/MWh.”
In June and August 2017, CNE failed to meet RA-related dispatches in California because it could not secure electricity in the bilateral market, prompting it to end the practice.
But FERC’s Office of Enforcement found that CNE’s practice violated the commission’s market behavior rules — specifically 18 C.F.R. section 35.41(a) — and sections 4.2.1, 37.2.1.1, and 37.3.1 of the CAISO tariff.
The commission explained that section 35.41(a) states that “where a seller participates in a commission-approved organized market, seller must operate and schedule generating facilities, undertake maintenance, declare outages, and commit or otherwise bid supply in a manner that complies with the commission-approved rules and regulations of the applicable market.”
Enforcement determined that CNE violated that rule by violating sections of the CAISO tariff that require market participants to follow the ISO’s dispatch instructions when the company could not respond to the RA-related dispatch signals in June and August 2017.
FERC found that CAISO’s tariff “requires that market participants have a ‘reasonable expectation’ of being ‘available and capable of performing at the levels specified in the bid’ at the time it is placed in the day-ahead market. Enforcement determined CNE lacked a sufficiently reasonable basis for its expectation that it would be able to wait to secure electricity in the spot market to support its RA imports during times when the market was constrained.”
Enforcement also pointed out that it was “unreasonable” for CNE to expect that electricity would be readily available in the spot markets when CAISO prices were reaching or exceeding $999/MWh, “because such prices usually reflect an environment in which it is difficult to secure sufficient supply to meet demand,” the commission said.
“In particular, we note that CNE’s conduct went against the purpose of RA, which is to ensure that firm resources are available to address supply shortfalls,” FERC concluded.
In addition to paying the penalties, CNE also agreed to only use specific generation sources or firm contracts with respect to importing RA in the future.
The Vermont Senate passed a bill 28-1 Tuesday that would, for the first time, legally define what environmental justice means in the state.
“We are among a handful of states left that have not passed an EJ bill because we long thought this is an urban issue or this is a Black and white issue,” Sen. Kesha Ram Hinsdale, sponsor of the bill, said during a March 25 floor debate.
The bill (S.148) provides a framework to ensure Vermonters “don’t experience the rural isolation of poverty and pollution without also experiencing the political power needed to remedy their situation,” Hinsdale said.
Hinsdale first introduced an EJ bill for the state 14 years ago but has yet to see the policy make it to law. She introduced the current version last April, and it did not move out of the Senate Natural Resources and Energy Committee before the end of the legislature’s first biennium session.
The bill received a significant boost of support in December with the release of the Vermont Climate Council’s Initial Climate Action Plan, which called for adoption of a statewide EJ policy to inform the work of state agencies and departments. And in February, a group of 33 advocacy organizations wrote to the Senate asking for passage of the bill.
Upon passage of the second reading of the bill in the Senate Friday, Vermont Lt. Gov. Molly Gray called the legislation an “important first step” in putting EJ into the workings of the government.
“We know from Hurricane Irene [in 2011] and other extreme weather events, that there are individuals and communities in Vermont who are disproportionately impacted by climate change,” Gray said in a statement. “If we are going to reach our climate goals and protect the environmental health and well-being of all communities, every Vermonter must be able to fully participate.”
With the bill’s passage in the Senate, it now moves to the House Natural Resources, Fish and Wildlife Committee, which has already reviewed the bill and will consider it for recommendation to the full House, Hinsdale told NetZero Insider.
Bill Provisions
The bill would set an EJ policy that says environmental burdens and benefits must be distributed equitably among Vermont’s communities. In support of that policy, the state would review past investments to determine which communities have received environmental benefits associated with those investments. And starting in 2024, nine government entities, including the Public Utility Commission, would coordinate investments in a way that ensures EJ populations receive at least 55% of the benefits.
It also defines an EJ population as a census group in which:
the annual median household income is less than 80% of the state median household income;
Persons of Color and Indigenous Peoples represent 6% or more of the population; or
1% or more of households have limited English proficiency.
To help state agencies and departments collaborate on EJ efforts, the bill would establish a 12-member interagency EJ committee, comprising government officials and a diverse, 17-member advisory council consisting of community members. At least half of the advisory council members would have to reside in an EJ population.
In addition, the bill would allocate funds for the Agency of Natural Resources to create a state mapping tool that identifies EJ populations and measures environmental burdens “at the smallest geographic level” possible.
The Senate passed an amendment March 25 that reduced a $3 million appropriation for the bill to $700,000, of which $500,000 is allocated to the mapping tool. Sen. Richard Westman, in recommending the amendment, said that the Appropriations Committee sought to move “non-immediate spending” for later consideration in its work developing the full state budget.
MISO will promote and install new officers of its executive management effective April 1.
The grid operator announced last week that it will add three vice presidents and promote three current vice presidents to the senior level.
New senior vice presidents will include current Vice President of System Planning Jennifer Curran, General Counsel and Corporate Secretary Andre Porter and Chief Digital Officer Todd Ramey. Curran and Ramey have been with MISO for about 20 years apiece; Porter joined the RTO in 2016.
New vice presidents will include Executive Director of System Operations Renuka Chatterjee, Executive Director of System Planning Aubrey Johnson, and Melissa Seymour, executive director of external affairs for MISO’s Central region.
Chatterjee is a 21-year veteran of MISO. Johnson and Seymour joined MISO in 2017 and 2013, respectively.
CEO John Bear said the Board of Directors was fully supportive of the promotions. In a press release, he said the six “have individually and collectively made exceptional contributions to MISO’s history by sharing their expertise and consistently demonstrating our core values.”
A New Jersey Board of Public Utilities (BPU) study into the contentious question of how much ratepayers will end up paying in 2030 for the state’s transition to clean energy faces a multitude of concerns from opponents and supporters who fear the proposed study will miss key costs and benefits.
More than two dozen speakers offered suggested improvements at a three-and-a-half-hour online public hearing Friday at which the BPU’s consultant, The Brattle Group, laid out the framework for the study and sought public input on its design and input assumptions — to little commendation from speakers and a wealth of criticism.
The study is designed to evaluate the cost to ratepayers in 2030 if the state implements the policies in its 2019 Energy Master Plan (EMP). The plan calls for the state to reach 100% clean energy by 2050, mainly by improving energy efficiency and shifting to clean energy generation, mainly wind and solar. (See Lawmakers Back Putting NJ’s Clean Energy Plan into Law.)
Supporters of the plan argued at the hearing that a focus only on the cost to ratepayers would be too narrow and leave important costs uncounted. Missing from the assessment, speakers argued, would be the expected, massive costs that would result from not addressing climate change and coping with storms, excessive wind, flooding and other natural disasters. Also unaddressed would be the impact to resident health resulting from failing to cut emissions, speakers said.
“The bottom line here is you need to change your goals for this study,” said Ken Dolsky, a steering committee member for Empower New Jersey, a coalition of more than 120 environmental, citizen, faith and progressive groups.
“The goal of the EMP is to significantly reduce greenhouse gases in order to avoid or reduce the impacts of climate change, not just ratepayer cost of energy,” he said. “Therefore, if you’re addressing the EMP, this cost analysis must include some portion, if not all, of the total expected costs of climate change in New Jersey.”
From the opposite direction, the Chamber of Commerce Southern New Jersey argued that the study would miss key costs, especially the expense to property owners and businesses required to meet the plan’s demand to switch from natural gas to electricity for furnaces, hot water boilers, transportation and in other areas.
Hilary Chebra, a lobbyist for the chamber, said the study, as outlined by Brattle, “falls short” in giving the business community “a more comprehensive assessment of the actual cost associated with implementing the EMP.”
“Energy costs impact competitiveness, and they’re a key factor in a business’s decision on locations and their profitability,” she said. “So, the costs of the EMP that are real expenses to the business community — that they will have to incur with the implementation — should be really thoroughly examined.”
Rate Impacts and Energy Burden
Murphy, a Democrat who instigated the EMP, wants the state to cut greenhouse gas emission levels to 80% below 2006 levels by 2050. The governor’s initiatives to help reach that goal include: a major offshore wind program that aims to generate 7.5 GW of electricity by 2035; reshaping the state’s solar incentives; introducing new rules to curb emissions from building heating and hot water systems; and developing a raft of programs aiming to get more electric vehicle chargers installed around the state and more EVs on the road.
Business groups, and some Republicans, have long expressed concern about the cost of the shift to low-emission energy sources, especially the focus on electrification as opposed to other clean energy alternatives, such as hydrogen and low-emission natural gas. In response, the BPU in May approved the hiring of Brattle to study the cost. The BPU expects to release the final report in the second or third quarter of this year.
The study is “is aimed at understanding the impact of the EMP on customers’ energy bills through a comprehensive analysis of rate impacts and overall energy burden as of 2030,” according to the BPU announcement of the hearing.
“The first question is, let’s just figure out the total costs of implementing these programs as of 2030,” Sanem Sergici, a Brattle principal, told the hearing. “Then, we will quantify the economic benefits and savings to the customers because, as I mentioned, these programs will lead to potentially reduced gasoline expenses [and] reduced natural gas usage.”
The study, according to the BPU, will look at:
the gross costs in 2030 of implementing the plan;
reductions in energy consumption driven by increased efficiency;
shifts in energy consumption in heating and transportation toward increased electricity usage;
changes to electricity and natural gas rates as costs are applied across changing electricity and gas volumes; and
shifts in energy burden from gasoline toward electricity consumption, alongside advances in EV adoption and heating electrification.
Brattle said it will use three scenarios: a continuation of the state’s current energy strategy; the pathway advocated by the EMP to reach 100% clean energy by 2050; and an “ambitious pathway” of reaching 100% clean energy by 2035.
The study will also look at the economic benefits and savings to consumers as a result of reduced gasoline, natural gas and electricity consumption, according to the BPU. And it will show the impact of the three policy scenarios on net consumer costs, in the form of total energy bills, and on different customer segments, such as low-income consumers.
Shaping the Study
Barbara Blumenthal, clean energy policy consultant for the New Jersey Conservation Foundation, said that by looking at the impact in 2030, the study would catch all the costs but not all the benefits because they take longer to develop.
“The investments come first, and the benefits in terms of emissions reductions in the health impacts and all of the other economic benefits lag,” she said. “So, it’s a little odd to cut off a study in 2030 after a period of investment, where the actual benefits in terms of emissions reductions are not yet cumulatively very significant.”
The New Jersey Division of Rate Counsel, however, said the study should focus on the costs to ratepayers, especially the impact on low-income ratepayers who could struggle to pay any increases.
“Rate Counsel believes that the focus of this analysis should be costs,” Sarah Steindel, assistant deputy rate counsel, told the hearing. “To the extent benefits are addressed, they need to be reported separately so that the board and the public can clearly see the cost customers will be paying. Any analysis of the benefits, like the analysis of costs, should consider how they are allocated among different ratepayer segments, including low-income ratepayers.”
Dolksy, of Empower New Jersey, expressed concern that the study as planned would fail to take into account the cost that would not be incurred as a result of the state pursuing a carbon-free policy. He cited the examples of treatment for people suffering from the effects of air pollution, increased health insurance costs and the loss of employment productivity from “people [who] cannot work because they’re sick due to related heat and unhealthy air effects.”
Tracy Carluccio, deputy director of the Delaware Riverkeeper Network, urged the BPU to expand the scope of the study.
“While we understand the significance of BPU assessing the effects to ratepayers of policy changes that address climate change, the assessment must be performed in the context of the impacts to the human and natural world,” she said. “And these costs must be considered in the study. This context is a world of disasters that will cause increasing damage, health harms, economic hardship and loss of life if we do too little too late.”
Chebra, of the Chamber of Commerce, said the proposed study would not catch the expenses to businesses such as the plan’s call to cut energy consumption and emissions in buildings. She questioned whether, for example, the study would reflect the thousands of dollars it would cost a building owner or manager to switch from a natural gas furnace to an electric heat pump.
Another concern, she said, is whether the study’s estimate of the costs of pursuing clean energy would include the amount spent to modernize the grid to handle the heightened volume of electricity flowing through the system. The BPU is at present soliciting proposals on how to implement that upgrade. (See Fierce Competition in Plans to Upgrade NJ Grid.)
“That is, again, a cost that ratepayers will have to bear,” she said.
Stakeholders last week urged PJM to hold its ground on proposed collateral requirements for FTR traders, saying it should offer more support for a formula FERC rejected in February.
FERC on Feb. 28 rejected PJM’s proposal to modify the FTR credit requirement with an initial margin calculation from a historical simulation (HSIM) model using a 97% confidence interval. The commission said PJM failed to support its proposal because its independent auditors validated the model at a 99% confidence interval rather than the 97% confidence interval proposed.
The commission directed PJM to make a filing within 60 days to show cause why its existing FTR credit requirement remains just and reasonable or explain what tariff changes will remedy the commission’s concerns (ER22-703). (See FERC Rejects PJM’s FTR Credit Requirement Proposal.)
In a sector-weighted vote at the March 23 Members Committee meeting, stakeholders endorsed a motion for PJM to refile the original proposal “accompanied by some new supporting rationale.” The motion received a sector-weighted vote of 3.9 out of 5 (78%).
A second motion calling for PJM to file the FTR credit requirement revisions with a confidence interval of 99% received a sector-weighted vote of 2.25 (45%). A third motion that called for instituting the 97% confidence interval, and then moving to the 99% within one year, received a sector-weighted vote of 3.01 (60%).
Dave Anders, director of stakeholder affairs for PJM, said the RTO’s technical and legal staff “values the feedback it received” and would assess the next steps in the filing process. Anders said “no firm decision” has been made by PJM on the filing, but the RTO will notify stakeholders of a decision within a week. The PJM Board of Managers have the final say on what the RTO files with the commission.
PJM Perspective
PJM’s Chief Risk Officer Nigeria Bloczynski presented the RTO’s perspective on the FTR filing, saying FERC’s order “appears to provide support” for moving to the 99% confidence interval.
The proposal resulted from a two-year stakeholder process at the Financial Risk Mitigation Senior Task Force (FRMSTF), an effort to strengthen PJM’s FTR credit and collateral rules in response to a report by independent consultants on the 2018 GreenHat Energy default. PJM said the proposal addressed one of the last recommendations in the report yet to be implemented: “eliminating the undiversified adder.”
Much of the stakeholder debate in October centered around the confidence interval, with some advocating for 95% and others for 99%, ultimately settling on 97% as a compromise. The confidence interval refers to the “statistical certainty that a given value will exceed the range of possible outcomes (i.e., the losses in portfolio value over the margin period of risk) produced by the HSIM model,” according to PJM.
In its order, the commission said it agreed with arguments made by the Organization of PJM States Inc. (OPSI) and PJM’s Independent Market Monitor that the record “fails to support” a 97% interval.
In the December filing, PJM argued that imposing a 99% confidence interval instead of 97% might “force some market participants to unwind market positions or to decide not to continue participation in the FTR auctions and FTR markets entirely.”
Bloczynski said PJM is now recommending moving toward the 99% confidence interval because using a higher confidence interval “provides more coverage of tail events” to protect PJM members and ratepayers in a default. She said the 99% confidence interval “brings PJM closer to the standards generally used in other commodity markets.”
PJM “stands behind” its original December filing, Bloczynski said, but the RTO doesn’t believe there is a “high probability of success” with a refiling that includes additional support if there continues to be protests by stakeholders against the 97% confidence interval. She said having a filing that includes a transition from 97% to 99% could have more “success” with the commission.
Stakeholder Perspectives
Steve Lieberman, vice president of transmission and regulatory affairs for American Municipal Power, presented the motion for alternatives in the PJM filing.
Lieberman argued that PJM should continue to support the 97% confidence interval in its filing and demonstrate to FERC that other changes included in the proposal “mitigate the risk of the riskiest market participants.” He said if PJM decides to move forward with the 99% confidence interval in a Section 205 filing, the process could be complicated through stakeholder protests.
“My crystal ball isn’t very clear, but I do believe we’ll see a very contentious docket at FERC, and I’m not sure that will get us the most expeditious path forward,” Lieberman said.
Jason Barker of Constellation Energy said his company was “disappointed” that PJM provided “insufficient analytical support” in its December filing to FERC on the 97% confidence interval. Barker said PJM could have done a more thorough cost-benefit analysis between the 97% and 99% confidence intervals.
“We’re disappointed that PJM doesn’t seem to express any concern for the cost of collateral,” Barker said.
Greg Poulos, executive director of the Consumer Advocates of the PJM States, said the most important part of PJM’s proposal for the advocates was to have some sort of confidence interval in place. Poulos said if PJM goes again to FERC advocating for the 97% confidence interval, it will create the “most uncertainty” on the issue and stall the adoption of other aspects of the proposal.
Market Monitor Joe Bowring said the IMM supports PJM’s position on moving to the 99% confidence interval because it allocates the costs to those that are imposing risks on the market.
Gregory Carmean, executive director of OPSI, said his organization agreed with PJM making a Section 205 filing with the 99% confidence interval. Carmean said other institutions responsible for regulating financial trading require a 99% confidence interval level.
“There’s no reason that the financial traders in PJM should be subject to less of a standard,” Carmean said.
Responsibly sourced natural gas (RSG) is now a “sizeable” and “growing” market, according to Andrew Swinick, commercial director at Kinder Morgan (NYSE:KMI).
The market is “driven by voluntary efforts to do better when it comes to our business practices,” he said Tuesday at the Northeast Gas Association’s Regional Market Trends Forum. “In 2018, we had only five companies that had committed volumes to RSG, and today we’re looking at 28.”
RSG, also called producer-certified gas, is a third-party-certified product based on a supplier’s ability to demonstrate it has reduced environmental impacts from its product and operates under best practices of environmental, social and governance (ESG) criteria.
“Right now, the goal of RSG is to minimize emissions along the natural gas value chain and to continuously look at ways to reduce those emissions levels,” he said. More suppliers are turning to RSG in response to end-user demand that Swinick says “is growing radically and dramatically.”
The three major certifying entities in operation currently are the nonprofits Equitable Origin and MiQ, and TrustWell by data analytics company Project Canary.
Certification is based on an ISO-like framework that “provides verification of responsible practices through rigorous independent audits, like emission reductions, no flaring and methane monitoring,” said Jeff Formica, vice president of environmental, safety, health and quality at Seneca Resources.
Seneca achieved Equitable Origin certification for 100% of its Appalachian assets in December 2021, according to Formica. The facility-level certification, he said, ensures that companies are always working to improve their ESG practices.
MiQ, which is also a facility-level certification, targets methane-intensity reduction by understanding how much methane a producer’s facilities emit versus the amount of natural gas they produce. It also ensures certified entities have comprehensive monitoring technologies in place to detect unintended emissions, Formica said.
The TrustWell certification works at the level of the gas well to reduce greenhouse gas emissions, set responsible water stewardship plans, mitigate operational risks and understand community needs, he said.
Growth Opportunity
Kinder Morgan, the largest U.S. gas pipeline company, could receive approval from FERC in the coming weeks for a new market mechanism that would support expansion of RSG.
The company filed a tariff, via its Tennessee Gas subsidiary, with FERC in December that would allow it to secure contracts specific to transporting RSG on its pipelines (RP22-417-001). Suppliers would need to demonstrate that they meet a predetermined, methane-intensity level certified by TrustWell to qualify for the tariff.
If FERC allows the company to move ahead with the new service, it would “encourage the transportation and trading on the Tennessee system of RSG supply from producers,” Kinder Morgan said in its tariff filing.
The company’s customers have shown broad support for the concept, according to Swinick, who said that Kinder Morgan expects to see an order from FERC in the coming weeks allowing service to begin May 1.
Producers see the offering as an “attractive” option, he said.
The Environmental Defense Fund asked FERC to “carefully consider” the program in a Jan. 24 filing and called for a technical conference.
“As the first request for FERC approval of an RSG-type program, Tennessee’s filing has the potential to create a significant precedent for the pipeline industry more broadly,” EDF said.
Consolidated Edison (NYSE:ED) commended Kinder Morgan in a Feb. 22 filing for taking a step that it said will allow customers to procure RSG, and the utility encouraged other interstate pipelines to provide a similar option.
The service will “aid natural gas distribution companies … in their efforts to reduce upstream greenhouse gas emissions associated with production or gathering of natural gas,” Con Ed said.
PJM detailed changes in a proposal to update the process timing for generation deactivations at last week’s Markets and Reliability Committee meeting after some stakeholders previously requested that the RTO slightly modify the language.
David Egan, manager of PJM’s system planning modeling and support department, reviewed the proposal, presenting the revisions to Manual 14D and the tariffin a first read at the MRC. Stakeholders previously gave near unanimous support of the issue charge at the March 8 Planning Committee meeting. (See “Deactivation Process Timing Update Endorsed,” PJM PC/TEAC Briefs: March 8, 2022.)
Egan said current language in the tariff provides 90 days advance notice and 30 days to complete deactivation studies, which is causing “insufficient and unsustainable” time for PJM staff to determine adverse impacts on reliability if more than one deactivation notice is made in a single study period. Industry trends and state energy policies are increasing the number of deactivation notices, Egan said, putting even more pressure on staff to finish studies in a timely manner.
“Thirty days to perform what is the equivalent in the interconnection process of a system impact study leads to overly conservative assumptions, which generally lead to inaccurate results,” Egan said.
The issue charge calls for changes to the tariff and manual to “provide more time to complete analyses, allow additional and improved studies, and provide the ability for more efficient work control and consistency regarding timing of deactivation studies,” Egan said.
The proposed deactivation process establishes quarterly study times for requests, with periods beginning Jan. 1, April 1, July 1 and Oct. 1. PJM staff would study deactivations “holistically” as a batch, Egan said, providing more accurate study results for impacts on the system.
The quarterly schedule would allow enough time for additional required seasonal, interim year and short-circuit analyses, scheduling upgrades, and cost estimates, Egan said, and for PJM operations to identify additional needed operational measures.
A series of 11 deactivation requests in July of 2021 prompted PJM to seek solutions to the review schedule for the RTO’s staff. | PJM
Egan said PJM is a “significant outlier” compared to other RTOs and ISOs in the deactivation process. MISO requires advance notice of 26 weeks for a deactivation, and the studies include 75 days to identify issues and 26 weeks to complete the deactivation study. NYISO requires advance notice of 365 days for deactivation, and studies are conducted in the subsequent quarter.
PJM granted a stakeholder request to insert tariff language that doesn’t constrain a generator to a specific time frame for deactivation and to create exemptions if a unit is forced to deactivate through state legislation or actions by the federal government.
Jason Barker of Constellation Energy asked how a generator that experiences a catastrophic failure will be studied or considered by PJM. He requested that PJM provide an opportunity for an expedited review so that owners don’t undertake carrying costs for waiting to decommission a unit that is “clearly not going to be operating any longer.”
Egan said the impact from a unit that has a catastrophic failure “doesn’t really change anything” because it will still have market obligations and have to look for alternative sources to fulfill the obligations.
“This whole process requires coordination with both transmission owners and generation owners to make sure we are able to mitigate problems on the system,” Egan said.
PJM will move conforming Manual 14D language through the Operating Committee and the Systems Operation Subcommittee if stakeholders endorse the proposal at the April 27 MRC meeting and the final tariff language endorsement at the May 17 Members Committee meeting.
Dave Anders, director of stakeholder affairs for PJM, reviewed a proposed issue charge from the Resource Adequacy Senior Task Force (RASTF) addressing the procurement of clean resource attributes and the creation of a new senior task force.
Anders said the first key work activity in the RASTF’s own issue charge was to determine whether the “forward procurement of clean resource attributes” should be pursued by stakeholders and to examine the inclusion of the social cost of carbon in PJM markets.
After discussions in the task force over the last few months, Anders said, stakeholders recommended a new issue charge for continued discussions and the development of potential market rules to implement the “preferred” design for clean resource procurement. Anders said 70% of RASTF members endorsed pursuing a new issue charge.
Anders said the new issue charge calls for a “comprehensive discussion of market enhancements” that would enable states and other buyers to procure clean resource attributes “on a voluntary basis, through a regional and centralized procurement or market.”
Walter Graf, PJM | FERC
Walter Graf, PJM’s senior director of economics and market services, provided details about the issue charge. Graf said stakeholders expressed interest in having a forum for a “comprehensive discussion on enhancements to the PJM markets.”
Work would start with education on the procurement of clean resource attributes, including defining clean resource attributes across jurisdictions, markets and procurement mechanisms. The second step calls for discussing the objectives of a market construct to enable voluntary procurement of clean resource attributes.
Graf said PJM and stakeholders will determine an approach to conduct analysis and select one or more market design solutions for further development.
The expected deliverables in the issue charge include the education and analysis identified in the scope of work and any proposed market rules to implement the preferred design if one is found.
Discussions would take place in a new Clean Attribute Procurement Senior Task Force reporting to the MRC, and work would continue through the second quarter of 2023.
Denise Foster Cronin of East Kentucky Power Cooperative asked if PJM anticipates moving forward with some type of market change even if the analysis resulting from the new task force doesn’t fully satisfy stakeholders.
Graf said PJM is initiating the conversation “with the hope that we would get something useful out of it.” He said PJM is looking to come to a consensus or compromise on the issue, but endorsing a solution is not necessary.
The committee will be asked to approve the recommendation at its April meeting.
CCSTF Sunset Endorsed
Members unanimously endorsed the sunset of the Capacity Capability Senior Task Force (CCSTF), bringing the work of the group to a close after nearly two years of discussions.
Melissa Pilong of PJM reviewed the sunset proposal and also presented the final report of the work completed by the task force. The CCSTF was originally created in March 2020 to consider using effective load-carrying capability (ELCC) to set the capacity value of limited-duration resources such as battery storage.
Stakeholders endorsed a joint proposal in September 2020 to use the ELCC method to calculate the capacity value of limited-duration, intermittent and combination (limited-duration plus intermittent) resources. FERC approved PJM’s proposal in August. (See FERC Accepts PJM ELCC Tariff Revisions.)
Pilong said work originally endorsed by stakeholders for a second phase of discussions at the CCSTF was moved to the RASTF. The additional work includes a discussion of other rules or rule changes that may be necessary for limited-duration resources to participate in energy and ancillary service markets.
Calpine’s David “Scarp” Scarpignato asked if work by stakeholders to examine using ELCC for all resources and evaluate its usefulness should be done at the CCSTF in the future rather than the RASTF because of the amount of detail needed to be discussed on the issue.
“It’s a ton of work, and I think it would take awhile to do,” Scarp said.
Anders said two different key work activities in the RASTF issue charge relate to the ELCC issue, including activities dealing with the risks and drivers and their relationship to accreditation of resources.
“There would be no reason to keep this CCSTF open to deal with that issue,” Anders said.
Max Emergency Changes Endorsed
Stakeholders unanimously endorsed PJM’s proposal to extend a temporary change to the maximum emergency status for gas combustion turbines and steam generators and an issue charge to look at a long-term solution.
Chris Pilong, of PJM’s operations planning department, reviewed the revisions to Manual 13: Emergency Operations in a problem statement and issue charge. Pilong said PJM made a temporary change to section 6.4 of Manual 13 in a “note” to modify the remaining hours under which a resource may be offered as maximum emergency generation to address recent concerns with fuel security and new emission standards in states.
The changes, which were endorsed in October, said PJM may request a generation owner to move steam units, which are mostly coal-fired, into the maximum emergency category if their remaining run time falls below 240 hours, or 10 days. The units could be restricted from operating during that time unless required to meet reliability needs for the grid. (See Global Fuel Supply Prompts PJM Manual Changes.)
Pilong said units could remain in maximum emergency status until their fuel inventory rose above 21 days, or 504 hours, and the designation would only be implemented to address concerns with local or regional reliability resulting from fuel supply shortages. The previous run-hour threshold for a maximum emergency was 32 hours.
Pilong said the manual change was set to expire April 1, but it needed to be extended to give PJM and stakeholders more time to work on a permanent solution.
The work on the long-term solution was requested to take place under a new problem statement and issue charge titled “Max Emergency Changes for Resource Limitations,” which stakeholders unanimously endorsed at the MRC.
The issue charge calls for reviewing and modifying existing rules in response to concerns with the fuel and non-fuel supply chain, as well as the increasing environmental restrictions on generators that are creating challenges with managing run hours. Pilong said key work activities include examining the hours remaining at which max emergency can be used on a unit, along with the procedures and communications associated with a max emergency event.
The expected deliverables include education on unit eligibility and the opportunity cost calculator, as well as potential revisions to Manual 13 and “enhancements” to existing processes.
Pilong said PJM wants to spend four months working on the issue in the Operating Committee and have a solution before the summer 2022 peak period.
Combined Cycle Minimum Run Time Guidance Endorsed
Members unanimously endorsed a proposal and manual revisions that have been discussed for several months in committees to address pseudo-modeled combined cycle minimum run time guidance.
Hauske said market sellers can model a combined cycle generation unit as multiple “pseudo units” that are made up of a single combustion turbine and a portion of a steam turbine. But he said the potential exists for one or more of the pseudo-modeled units to operate for a period beyond the minimum run time parameter limit compared to an identical non-pseudo-modeled combined cycle unit if the market units of a pseudo-modeled combined cycle unit are dispatched at different times because the steam turbine takes extra time to reach operative levels.
Hauske said the proposed solution calls for adding language to Manual 11 to require market sellers to update the minimum run time of any subsequent pseudo-modeled unit to remove the associated steam turbine start-up time included in the parameter limit when it’s dispatched.
PJM wanted to have the final endorsement in place at the March MRC meeting because the RTO’s unit-specific parameter adjustment process started earlier this month, and determinations on requests must be made by April 15.
Consent Agenda
Stakeholders unanimously endorsed four manual revisions as part of the MRC consent agenda. They included:
revisions to Manual 12: Balancing Operations resulting from a periodic review. The changes include attachment references and other minor revisions.
revisions to Manual 13: Emergency Operations resulting from a periodic review. The changes include new columns with winter values for estimated peak load and estimated load reduction in the voltage reduction summary table.
revisions to Manual 18: PJM Capacity Market to conform with several recent FERC orders, including those on the minimum offer price rule, the market seller offer cap and the removal of the 10% cost adder for the reference resource used to establish the variable resource requirement curve.
revisions to Manual 37: Reliability Coordination resulting from a periodic review. The language would properly label Silver Run Electric as a transmission owner in Attachment A of the manual.
Members Committee
Remote Voting for Annual Meeting
PJM wants to revise Manual 34 before the Annual Meeting on May 17, which includes the Board of Managers election and General Session, to allow for remote voting.
Michele Greening, manager of PJM’s stakeholder process and engagement department, reviewed proposed revisions to Manual 34: Stakeholder Process to update the ballot process during the Annual Meeting at last week’s Members Committee meeting.
Greening said Manual 34 includes language requiring written paper ballots for the elections of board members and the Members Committee vice chair. She said as the current remote meeting format has gone on for more than two years as a result of COVID-19 protocols, PJM identified the need to “exercise flexibility” to conduct the 2020 and 2021 board elections using an alternative to written paper ballots.
The 2020 board election was done remotely through the PJM Voting Application with special auditing provisions to “ensure ballot confidentiality,” Greening said, and the 2021 board election was conducted through a secure, third-party online election service, Survey & Ballot Systems.
Greening said PJM wants to continue to use a secure third-party voting system for stakeholders not attending the Annual Meeting in person. To make the change permanent, PJM is proposing to modify the current Manual 34 provisions requiring a written paper ballot by striking the language.
The committee will be asked to approve the proposed Manual 34 revisions at the April MC meeting.
