FERC staff expressed confidence Thursday that the North American bulk power system has sufficient reserves to make it through the winter comfortably.
But they also said utilities must be prepared for further impacts from the COVID-19 pandemic and constraints on the availability of natural gas and fuel oil.
Winter 2020/2021 temperature forecasts | National Oceanic and Atmospheric Administration
Presenting FERC’s 2020/2021 Winter Energy Market and Reliability Assessment, Louise Nutter of the Office of Electric Reliability told the commission that the impact of the pandemic in winter is hard to judge in advance. While many of the worst disruptions — natural gas and crude oil prices, and electric load reductions because of stay-at-home orders — have eased since spring, further impacts depend “on whether COVID-19 cases rise across the United States and whether states increase mitigation measures.”
Staff highlighted several areas in which the pandemic appears to have brought lasting, or at least ongoing, change. The first is the shape of the daily demand curve, with weekday loads peaking “later in the morning and earlier in the afternoon compared to before the pandemic” — a phenomenon already noted by NERC regional entities earlier this year. (See Sagging Demand Cushions NPCC’s Summer Outlook.)
Utilities are also continuing to take the coronavirus into consideration in the form of new procedures to keep their personnel safe from infection through, for example, guidelines requiring social distance during operations and expanding stocks of personal protective equipment. These have been in place for many entities since before summer; however, with no firm idea of when the crisis will end, utilities are having to adjust what most assumed to be temporary measures to last indefinitely. (See NERC Planning Lessons Learned on COVID-19 Response.)
Finally, these pandemic-related scheduling issues also caused many entities to forgo maintenance planned for spring until autumn. (See COVID-19, Hurricanes Among Biggest Summer Threats.) Most of this work has been completed during “a compressed fall maintenance season,” but utilities have expressed concern about the possibility of the remaining maintenance interfering with winterization activities, along with unforeseen complications from the delay.
Reference Margins Looking Good
Outside of potential coronavirus issues, FERC said all regions appeared set to meet their reference margin. SERC-E, representing North and South Carolina, had the lowest reserve margin; however, its expected reserves of 22% still comfortably exceed NERC’s reference margin of 15%.
Weather is the primary driver of confidence, with the National Oceanic and Atmospheric Administration predicting normal temperatures or higher for most of the U.S. aside from the upper Northwest and Upper Midwest, which were assessed a 33% probability of below-normal temperatures. The mild conditions are expected to drive down demand for natural gas for heating in most areas, freeing up stockpiles and pipelines to be used for power generation.
On the generation side, the report predicts current trends of “increasing gas and renewable capacity with decreasing net capacity of coal and nuclear plants” to continue, with solar, wind and natural gas-fired plants comprising nearly all the capacity to be added by February 2021. Even with these additions, the share of electric generation coming from gas nationwide in the winter is projected to decrease from 38% last winter to 34% this year; NYISO and PJM are the only regions expected to grow their shares of gas-fired generation.
Gas Bottlenecks Possible for New England
New England represents the area of greatest concern for FERC, holding “the greatest risk of fuel shortages and related market stress” because of the widespread use of natural gas for both heating and power generation, which can produce bottlenecks on cold days even in the milder conditions predicted for this winter. Peak load for ISO-NE is forecast to hit 23,373 MW in the 2020/21 winter season, higher than last year’s peak of 22,319 MW but still within the regional capacity of about 31,000 MW.
Strains on natural gas supply lines could be exacerbated this year because of decreased demand for oil, which has reduced the availability of natural gas derived from oil production. Gas is also expected to be even more prominent in the resource mix than usual this winter because of the recent retirement of two nuclear plants — the 680-MW Pilgrim facility in Massachusetts in May 2019 and New York’s 1,000-MW Indian Point Unit 2 in April 2020.
California, the only other region highlighted in FERC’s report, may see oversupply conditions when generation from hydro, wind and solar facilities exceeds load, a regular occurrence in late winter. In February, for example, CAISO curtailed 157 GWh of energy, 8% of which came from solar generation; by contrast, in July the ISO curtailed only 31 GWh.
Asked by Commissioner Richard Glick whether CAISO is taking steps to reduce curtailments so that renewable generation capacity is used as much as possible, a staffer from FERC’s Office of Energy Policy and Innovation said the ISO is looking at “a number of possible solutions, [including] increasing the flexibility of existing resources through enhancing demand response initiatives, reducing minimum operating levels for generators and greater regional coordination through the Western Energy Imbalance Market.”
More Findings
Additional significant conclusions from the report include:
Natural gas consumption by the electric power sector is expected to average 24 Bcfd, down 20% from winter 2019/2020. This represents a departure from the 5% average growth annually since winter 2015/2016 and is attributed to lower anticipated electricity production both from the mild weather and continuing coronavirus-related load decreases.
U.S. exports of LNG should average 9.4 Bcfd, up 22% from winter 2019/20 levels thanks to increased U.S. liquefaction capacity and rising international demand. Gross U.S. LNG imports are expected to average 367 MMcfd, a 13% year-on-year increase.
Natural gas storage inventories are expected to begin the winter withdrawal season at 3.95 Tcf, “the third highest inventory level in the past 10 years,” and end the season at 1.34 Tcf, representing the third-lowest level in the last decade.
FERC on Thursday approved most of PJM’s compliance filing on its expanded minimum offer price rule (MOPR) while reversing its position on state-directed default service auctions (EL16-49-003, et al.).
The commission said it agreed with PJM and commenters to exclude “independently evaluated, non-discriminatory, fuel-neutral, competitive state-directed default service auctions from application of the expanded MOPR.”
“Based on the record in this proceeding, we find that competitive and non-discriminatory state-directed default service auctions — i.e., those state-directed default service auctions that qualify to be excluded from the definition of state subsidy under PJM’s proposal — do not require mitigation at this time.”
The commission also rejected PJM’s proposed revisions to the market seller offer cap as beyond the scope of the compliance proceeding.
In March, PJM made a 683-page filing proposing Tariff revisions in response to FERC’s December order expanding the MOPR to new and existing state-subsidized resources. The order included exceptions for existing demand response, energy efficiency, self-supply and resources receiving payments under renewable portfolio standards. In June, PJM submitted proposed additional Tariff revisions to comply with the commission’s April 16 order on rehearing.
More than two dozen companies and coalitions had filed responses to PJM’s compliance filing, taking issue with the RTO on auction timing, floor prices, unit-specific rules and self-supply exemptions. (See Commenters Weigh in on PJM MOPR Compliance Filing.)
The order was supported by Chairman Neil Chatterjee and Commissioner James Danly, both Republicans, while Democrat Richard Glick issued a six-page dissent.
“At this point, there is not that much left to say,” Glick wrote. “This proceeding has been one of the commission’s all-time worst, both in the baffling decisions it reached and the bumbling way in which it got there. Today’s order only digs the hole deeper.”
| Richard Glick via Twitter
Glick said he was relieved that the commission had reversed its treatment of state default service auctions, calling its original position “a harebrained idea.”
“Even parties that have cheered on the commission’s general MOPR zealotry have balked at applying MOPRs to default service auctions,” he noted.
But he said the commission’s limited rehearing may be moot because of its suggestion that New Jersey’s default service auction would constitute a state subsidy based on the possibility that the auction winners would have to comply with the state’s renewable portfolio standard.
“The commission’s discussion of the [New Jersey] auction provides every reason to believe that the grant of rehearing on state default service auctions will end up being almost meaningless. Several other PJM states’ descriptions of their default service auctions also mention renewable portfolio standards or similar programs applying to entities that provide default service. Taken seriously, the commission’s discussion of the [New Jersey] auction would seem to suggest that payments from those other states’ auctions would also trigger the MOPR.”
Glick predicted “the PJM MOPR saga will ultimately be remembered as a model case of egregious commission overreach. The majority has taken MOPRs, already a controversial topic, and thoroughly weaponized them as a tool for increasing prices and stifling state efforts to promote clean energy. The result is an unsustainable construct that will eventually collapse under its own weight. The commission’s contortions on default service auctions and its failure to address the most important questions implicated by today’s order are just the latest indicator of that inevitable result. At this point, the only real question remaining is how much damage the commission’s arrogant approach to the states will do in the meantime.”
Chatterjee insisted the ruling was a “market protective reform.”
“I’m proud of the actions the commission has taken to protect the integrity of the PJM capacity market,” Chatterjee said. “Markets are, in my view, simply the best way to pave the way towards our energy future.”
He said that when renewable resources and new technologies are given the chance to compete, they can thrive in the marketplace, but there has to be transparent and efficient markets as a baseline. He said creating a baseline is the “core aim” of the MOPR.
Here is a summary of the commission’s 162-page order.
Resources Subject to the Expanded MOPR
FERC accepted PJM’s proposed Tariff revisions to apply the MOPR to any capacity resource that receives or is entitled to receive a state subsidy.
It accepted PJM’s position that sellers involved in bilateral transactions should be permitted to choose the competitive exemption in cases where the rights and obligations of multiple off-takers are in equal shares. “Consistent with the directives of the December 2019 order, we reiterate that only the portion of the resource receiving a state subsidy will be subject to mitigation,” FERC said.
It also accepted PJM’s proposal regarding resources not subject to the must-offer requirement. “We disagree with the Market Monitor that the entire capacity of such a resource must be offered into each auction, including incremental auctions, to maintain its status as an existing resource, because the rehearing order did not require that,” FERC said.
The commission also rejected the Monitor’s argument regarding fixed resource requirement (FRR) resources, approving PJM’s proposal that resources in FRR capacity plans will not lose their status as cleared capacity resources with state subsidies solely because they participate in such a plan instead of the Base Residual Auction (BRA) for a given auction.
Definition of State Subsidy
FERC accepted PJM’s proposed definition of state subsidy, which incorporated the commission’s definition. The commission rejected the Environmental Defense Fund’s complaint that the definition is vague and does not put market participants on notice of what is considered a state subsidy, calling it “essentially an out-of-time rehearing request of the December 2019 order,” which defined state subsidy.
General Industrial Development and Local Siting Support
The commission accepted PJM’s proposal to exclude generic industrial development and local siting support from what is considered a state subsidy, rejecting a proposal by Dominion Energy. “Dominion incorrectly suggests that any subsidy that is widely available would be exempt, regardless of whether it met the criteria for general industrial development or local siting support subsidies laid out in the December 2019 order,” FERC said. “The December 2019 order, as reiterated in the rehearing order, found that only payments which were designed to provide an incentive or promote general industrial development in an area or siting facilities in one locality over another are exempt.”
Bilateral Contracts with Self-supply
PJM’s proposal to exclude from the MOPR some voluntary bilateral contracts entered into by self-supply entities also won FERC’s approval.
“We agree that, where the otherwise unsubsidized resource contracts with a self-supply entity and the transaction meets the requirements under PJM’s proposal, the unsubsidized seller does not have the ability to enter into a contract below cost, nor would the unsubsidized resource have guaranteed cost recovery if it offered the capacity into the market below cost,” FERC wrote.
The commission rejected a proposal by American Electric Power and the Organization of PJM States Inc. (OPSI) to include an exemption for all bilateral transactions as “unnecessary.”
“The commission expressly found in the December 2019 order that private, voluntary bilateral transactions did not need to be mitigated.”
It also disagreed with the contention by some intervenors that energy-only bilateral sales to self-supply entities cannot convey a state subsidy. “Rather, if an energy-only bilateral contract entered into by a self-supply entity meets the requirements set forth in PJM’s proposal, then that contract is excluded from the definition of state subsidy. Otherwise, as the rehearing order found, the expanded MOPR applies to bilateral contracts entered into by self-supply entities. The record provides no basis for generally distinguishing bilateral contracts for energy from other bilateral contracts entered into by self-supply.”
It also rejected requests to require PJM to allow a competitive exemption for self-supply transactions that are shown to be competitive or that the RTO and the Monitor review self-supply contracts and determine whether the contract conveys a subsidy.
“If a state-subsidized resource is truly competitive, the resource can use the resource-specific exception to offer less than the default offer price floor, thereby permitting resources to show they are truly participating competitively and protect market integrity,” FERC said.
FRR Revenue
FERC approved PJM’s proposal that any revenue for providing capacity as part of an FRR capacity plan or through bilateral transactions with FRR entities will not be considered a state subsidy.
It disagreed with the Monitor’s contention that any FRR revenue should be considered a subsidy even if it does not meet the definition.
Market Seller Offer Cap Provisions
FERC rejected PJM’s proposed revisions to the market seller offer cap, saying the cap has “never been a subject of this [Federal Power Act] Section 206 proceeding.”
“Neither the December 2019 order nor the rehearing order directed changes to the market seller offer cap provisions or found that sellers should be able to offer above the default market seller offer cap without a resource-specific review, as currently required by the Tariff.”
The commission said it understood PJM’s concern that sellers may be left without a valid offer under potentially conflicting Tariff provisions when the default or resource-specific offer price floor for a resource is higher than the cap for such a resource. “In such a circumstance, we find that the resource should submit an offer using the resource-specific review process,” FERC said.
Self-supply Exemption
FERC accepted PJM’s proposal regarding the self-supply exemption. It rejected a request for clarification by Southern Maryland Electric Cooperative, saying “an executed bilateral contract alone is not one of the eligibility criteria for the exemption.”
RPS Exemption
The December order, as modified by the rehearing order, directed PJM to include an exemption for renewable resources receiving support from state-mandated or state-sponsored RPS programs.
PJM’s proposed RPS exemption was accepted in part, with the commission requesting a modification directing the RTO to modify Tariff language related to eligibility for exemptions to state that “a capacity resource may qualify for the exemption if it is the subject of an interconnection service agreement that is executed by the interconnection customer on or before Dec. 19, 2019.”
DR/EE/Storage Exemption
FERC directed PJM in the December order to include a DR, energy efficiency and storage resource exemption that would meet at least one of three criteria to be eligible: have successfully cleared an annual or incremental capacity auction prior to Dec. 19, 2019; have completed registration on or before Dec. 19, 2019; or have a measurement and verification plan approved by PJM for the resource on or before Dec. 19, 2019.
The commission mostly accepted PJM’s proposal, directing further compliance on the RTO’s proposal regarding utility-based residential load curtailment programs. FERC directed PJM to remove a parenthetical statement “(or for utility-based residential load curtailment program, based on the total number of participating customers)” from Attachment DD, section 5.14(h)(7)(a).
“The rehearing order requires aggregators and curtailment service providers (CSPs) to be considered to have previously cleared a capacity auction only if all the individual resources within the offer have cleared a capacity auction either on their own (i.e., individually) or as part of an offer from an aggregator or CSP,” the commission said.
Competitive Exemption
The December order directed PJM to include a competitive exemption for both new and existing resources, other than new gas-fired resources, that certify to the RTO that they will forego any state subsidies. The rehearing order further clarified that the competitive exemption is available to state-subsidized resources “receiving or entitled to receive a state subsidy that certify they will forego the state subsidy,” noting that all resources seeking to use the competitive exemption must certify whether or not they receive, or are entitled to receive, a state subsidy.
FERC ordered PJM to submit an additional compliance filing, directing the RTO to modify its proposal regarding the gaming provisions that dictate “under what circumstances a resource that elects the competitive exemption and then accepts a state subsidy will forfeit its capacity revenue.”
The commission also rejected PJM’s proposal that, going forward, any capacity resource that cleared an auction before it received or became entitled to receive a state subsidy shall be deemed a cleared capacity resource with state subsidy, rather than a new capacity resource with state subsidy.
Default Offer Price Floors
FERC approved PJM’s proposed gross cost of new entry (CONE) values except for the energy efficiency value, which it deferred to a separate proceeding on reserves, in which the commission found the RTO’s methodology for calculating the energy and ancillary services offset (E&AS) unjust and unreasonable (EL19-58). A compliance filing that includes a new proposal for EE gross CONE in that docket is pending before the commission.
FERC accepted PJM’s proposed gross avoidable-cost rate (ACR) values and its proposal to adjust the Tariff-stated gross CONE values for combustion turbine and combined cycle resources annually using the applicable Bureau of Labor Statistics Composite Index.
The commission accepted in part, and rejected in part, PJM’s proposal regarding default offer price floors for generation-backed DR. Specifically, FERC accepted PJM’s proposed gross CONE and ACR values for generation-backed DR diesel resources but rejected the RTO’s proposal to use those values for other types of behind-the-meter generation because it was not consistent with prior orders.
“We have already found that behind-the-meter generators should have the same costs as front-of-meter generators of the same type,” the commission said. “The rehearing order found that behind-the-meter generators should not receive special treatment and that parties failed to present evidence ‘why a specific type of generator should have fundamentally different going-forward or construction costs depending on whether it exists behind or in front of the meter.’”
Resources not Subject to the Must-offer Requirement
FERC directed PJM in the December order to propose default offer price floors for all other types of resources that participate in the capacity market, with the rehearing order clarifying specifically that the RTO should propose default offer price floors for seasonal resources.
The commission approved PJM’s proposal that the offer price floor should be applied regardless of the actual sell offer quantity or the resource’s status as a seasonal Capacity Performance resource, for both the default offer price floors and the resource-specific offer price floors.
“We agree with PJM to base the offer price floor on the capacity resource’s full capacity capability ensures cost recovery, and no more, for each megawatt-day offered and cleared,” the commission said.
The December order directed PJM to maintain the “resource-specific exception,” expanding it to cover existing and new state-subsidized resources of all resource types and to permit “any resource that can justify an offer lower than the default offer price floor to submit such offers for review.”
PJM proposed two options for sellers seeking the resource-specific exception: an offer that considers only costs related to participating in the capacity market and meeting a capacity commitment, and an offer that considers all costs and permissible revenues.
“The first option is not consistent with the rehearing order, which found that behind-the-meter resources should not be treated differently solely because they are behind-the-meter and directed that all resources of a particular technology type should be treated the same,” the commission said, approving the second option.
Certification
PJM proposed that each seller inform the RTO whether its resource is state-subsidized during the pre-auction registration process. It included provisions that the information must be provided no later than 120 days prior to the annual capacity auction for each seller other than DR and EE resources, which would have a 30-day deadline.
The commission accepted PJM’s certification proposal in part, approving the RTO’s proposed deadlines, but created a stipulation that if any changes in a state subsidy status occurs within 30 days of the auction, sellers will have five days to notify the RTO of the change.
Fraud or Material Misrepresentations
PJM proposed that if it or the Monitor suspects “misrepresentation or omission in the relevant certification,” either entity may request additional information to be provided within five business days.
The commission accepted PJM’s proposal and declined to direct the RTO to remove Tariff references describing the Monitor’s role as “advice and input.”
“Contrary to the Market Monitor’s contention, stating that the Market Monitor will provide advice and input to PJM does not mean that the Market Monitor’s role as independent evaluator is diminished or change the fundamental roles between PJM and the Market Monitor related to the capacity market,” the commission said.
Waiver Request and Auction Schedule
The December order directed PJM to provide revised dates and timelines for the BRA associated with delivery year 2022/2023 (2019) and related incremental auctions, along with revised dates and timelines for the BRA associated with delivery year 2023/24 and related incremental auctions, as necessary.
The commission granted PJM’s waiver allowing the pre-auction process to begin two weeks after FERC issued the order, with the next annual capacity auction to be conducted in six and a half months.
Replacement Capacity
The rehearing order clarified that capacity from state-subsidized resources cannot serve as replacement capacity “bilaterally procured to fulfill a capacity commitment for an unsubsidized resource.”
The commission determined that it’s not consistent with prior orders to allow a state-subsidized resource to evade the MOPR through a bilateral transaction, regardless of the term of the transaction. The order acknowledged PJM’s concern that the change “would inhibit the ability for capacity market sellers of jointly owned resources to replace resources within their own portfolios.”
But the order said the modified provision that removed the phrases “short term” and “one year or less” from Attachment DD section 4.6(e) was just and reasonable and followed the Monitor’s position that this provision should extend to replacement capacity within portfolios as well.
“It is not consistent with the prior orders, or just and reasonable, to allow a supplier to game the expanded MOPR by switching the capacity obligations within its portfolio to alternative resources,” the commission said.
The commission accepted only the proposed changes to existing Attachment DD section 5.14(h), which are related to the replacement rate, and accepted PJM’s proposal to change the name of the section to “Minimum Offer Price Rule for Certain New Generation Capacity Resources that are not Capacity Resources with State Subsidy.” All other changes in the section were rejected as being outside of the scope of the filing.
The rehearing order clarified that the December order did not direct any changes to PJM’s pre-existing MOPR and that the RTO’s compliance filing “should not contain any substantive changes to that section unrelated to the replacement rate.” But the rehearing order explained that state-subsidized resources should be subject to the MOPR regardless of their location with respect to the expanded MOPR.
When the governors of Connecticut, Maine, Massachusetts, Rhode Island and Vermont released a joint statement Wednesday calling for reforms to ISO-NE, it read less like an olive branch and more like a precursor to a seismic shift in relations between the states and the RTO.
The governors said they “require” changes to market design, transmission planning and RTO governance, which they said are stunting their efforts to reduce economy-wide greenhouse gas emissions. The New England States Committee on Electricity (NESCOE) will specify the reforms in a soon-to-be-released document. (See related story, New England Governors Call for RTO Reform.)
“I think it’s clear that the governors are saying what’s happening right now can’t and won’t persist. ‘We will change it,’” said Theodore Paradise, senior vice president of transmission strategy and counsel at Anbaric. “‘Let’s try to work together to change it,’ but sort of the next step — hidden or embedded in this language — is ‘we will get there, one way or the other.’ This is really not an optional conversation or a request. This is more of a directive of what we as a region are going to do.”
Katie Dykes, commissioner of Connecticut’s Department of Energy and Environmental Protection, said, “The best path for us is one that centers on coordination and cooperation with our neighboring states,” and the governors’ statement speaks with “a unified voice” about what states expect from the RTO in the future.
Dykes said the federal government “unfortunately” has taken a step back on climate change leadership, leaving New England states on “the front line for combating climate change.”
“It’s very important that states have appropriate involvement in the design of market-based mechanisms to achieve our decarbonization policies,” Dykes said. She added that “ratepayers are being saddled with duplicative costs. We have a market design that is actively preventing our state from getting credit for clean energy resources that we have had to procure outside of this market because the market is not designed to incentivize investment in the resources that we need. It’s inefficient. It’s unnecessarily costly. It cannot continue.”
Dykes said the nonpublic NEPOOL stakeholder process needs to be open to state lawmakers so that “very knowledgeable folks who participate in the NEPOOL discussions engage with some of the policymakers at the state level who have concerns and preferences around what our grid should look like and what value should be provided for our ratepayers.”
Ari Peskoe, director of the Harvard Electricity Law Initiative, said the statement was “a long time coming.”
“It was good to see a real strong statement from the governors about what they do want to see and what they think the future of the sector should look like,” Peskoe said. “I thought that was a real positive step forward that five governors were willing to sign on to this.”
As for New Hampshire not being a signatory, Peskoe said it “is the clear laggard state in terms of clean energy ambitions” and that Republican Gov. Christopher Sununu “has, at best, been lukewarm on clean energy.” The five other governors lead states with “aggressive, clean energy targets.”
“What I’ve seen from NESCOE in the past was wanting to reach consensus before issuing any sort of statement, and that had the effect of weakening the group’s ambitions,” Peskoe said. “I thought it was interesting that this time [NESCOE] decided they weren’t going to wait for New Hampshire to call for the regional clean energy solution.”
Advanced Energy Economy Director Caitlin Marquis, whose work in part focuses on ISO-NE, said she is “cautiously optimistic that this is a positive development, and that the ISO will be similarly willing to work constructively with the states to address some of the concerns.”
Marquis added that there is a carrot-and-stick aspect to it.
“I think it’s an ask that the ISO engage and the states get a bigger role,” Marquis said. “If they’re able to come to some alignment on the concerns the states have on clean energy, there could be a constructive path forward there. I think the New England states have been clear that they don’t have an issue with a carbon price but want an economy-wide solution. There are some specific concerns with an ISO carbon price, and I do think there’s frustration that that message has not gotten through.”
The governors of Connecticut, Maine, Massachusetts, Rhode Island and Vermont released a joint statement Wednesday calling for reforms to ISO-NE, saying the RTO is frustrating their efforts to reduce economy-wide greenhouse gas emissions.
“Here in Rhode Island, we’re committed to reducing our greenhouse gas emissions and decarbonizing our future. I’m proud that we’re on track to achieving 100% renewable energy by 2030,” Rhode Island Gov. Gina Raimondo (D) said. But “in order to meet our shared clean energy goals and aggressively combat climate change, it’s clear we need to take a regional approach.”
The statement — signed by Raimondo, Connecticut Gov. Ned Lamont (D), Maine Gov. Janet Mills (D), Massachusetts Gov. Charlie Baker (R) and Vermont Gov. Phil Scott (R) — calls for reforms to ISO-NE’s market designs, transmission planning process and governance. New Hampshire Gov. Christopher Sununu (R) did not join in the statement.
A document outlining specific areas for reform will be released later this week through the New England States Committee on Electricity (NESCOE).
In this photo from 2015, clockwise from bottom left: Meredith Hatfield, director of the New Hampshire Office of Energy and Planning; Massachusetts Gov. Charlie Baker; former Vermont Gov. Peter Shumlin (hidden); Rhode Island Gov. Gina Raimondo; former Connecticut Gov. Dannel P. Malloy; and former Maine Gov. Paul LePage | Rhode Island Gov. Gina Raimondo
The governors said ISO-NE’s market design is “misaligned” with the states’ clean energy mandates and “fails to recognize the full value of our states’ ratepayer-funded investments in clean energy resources.”
They also said it lacks “a proactive transmission planning approach” to facilitate the increase in renewable and distributed resources.
Finally, they criticized the RTO’s governance structure, saying it “is not transparent to the states and customers it serves, with a mission that is not responsive to states’ legal mandates and policy priorities.” Unlike the other FERC-regulated grid operators, meetings of New England’s stakeholders, run by NEPOOL, are closed to the public.
“We have received the governors’ statement and look forward to engaging with the states and our stakeholders on these issues,” ISO-NE spokesman Matt Kakley said in response. “ISO New England, the New England states and market participants have a long history of working together to tackle the challenges facing the power system, and we expect that to continue.
“Maintaining reliable, competitively priced electricity through the clean energy transition will require broad collaboration, and the common vision of the New England governors will play an important role in the discussions currently underway on the future of the grid. We appreciate the New England governors sharing their regional vision to achieve a shared clean energy future and reaching out to ISO New England to help them achieve their goals.”
Mid-century economy-wide GHG emission reduction targets in New England | E3/EFI
Their attack on ISO-NE’s market design is also an implicit criticism of FERC’s regulation, which state officials say have hamstrung the ability of state-subsidized resources to compete in the capacity market. In March, ISO-NE CEO Gordan van Welie responded to criticism by several members of New England’s U.S. Senate delegation by backing carbon pricing but saying state officials need to signal their support before the RTO could act. (See ISO-NE: States Must Lead on Carbon Pricing.)
Each of the governors weighed in with their concerns.
“When Connecticut deregulated our electricity sector, we were promised competition, lower risk for ratepayers, more affordable electricity and a system that respects and accommodates our clean energy mandates,” Lamont said. “What we got is a system that has actively hindered our efforts to decarbonize the grid and imposed burdensome costs on Connecticut ratepayers to fix market design failures. Working together with our neighboring states, I’m committed to achieving a regional electricity grid that provides the affordable, clean and reliable electricity that Connecticut families and businesses deserve.”
Added Mills: “It is far past time that New England reforms how its electric grid is managed. The wholesale electricity markets must advance and support clean energy laws and policies, as the states demand decarbonization and markets and consumers support more renewables. ISO New England must keep pace with state priorities, and it must be more transparent and accountable in its decision-making, broadening its focus to include consumer and environment concerns as well as reliability and cost.”
Baker said: “To meet to our administration’s goal of net-zero emissions in Massachusetts by 2050, the commonwealth needs a regional electricity system that can support the delivery of clean, affordable and reliable energy to residents and businesses. My administration looks forward to working with our partner states, ISO New England and stakeholders to build a more transparent, modern and cost-effective power system that will allow New England states to meet our ambitious climate change and clean energy goals while creating a better future for our residents.”
Scott concluded: “I’ve long said our work to address climate change can and must also work to make energy more affordable for Vermonters, so I’m pleased to be a part of this regional approach to achieving both of these priorities. With a strategic, multistate approach, we can have a greater impact on both climate change mitigation and energy affordability.”
The five states said they will convene open and accessible forums to ensure that all interested stakeholders have an opportunity to participate in further refinement of the principles of the shared NESCOE document.
The changes at the top of CAISO’s executive ladder that began last month with the installation of CEO Elliot Mainzer continued this week, as the ISO announced a new chief operating officer and the retirement of two veteran vice presidents.
Mark Rothleder, who has been with CAISO since its founding in 1997, will take the newly created No. 2 position as COO under Mainzer, who replaced Steve Berberich. (See CAISO Retiring, Incoming CEOs Field Questions.)
Rothleder currently serves as the ISO’s vice president of market policy and performance, a job in which he warned of potential summer shortfalls long before they occurred in August and September as California shifted from its reliance on natural gas to wind and solar. (See CAISO, CPUC Warn of ‘Reliability Emergency’.) Previously, a suite of vice presidents, including Rothleder, reported directly to the CEO.
Mainzer said in a news release that he looks forward to teaming up with Rothleder to “meet the company’s strategic goal of enabling a reliable transition to a clean energy grid.”
Petar Ristanovic, CAISO | CAISO
“Mark has been with the ISO since its inception, giving him immense and deep knowledge of our organization and the industry,” Mainzer said in the statement. “I know Mark will do an outstanding job in his new role as COO.”
Rothleder is the ISO’s longest-serving employee and previously held positions as executive director of market analysis and development, principal market developer and director of market operations.
“Since joining the ISO 23 years ago, Rothleder has worked extensively on implementing and integrating the approved market rules for California’s competitive wholesale energy and reserves markets,” the ISO said.
CAISO also said that Petar Ristanovic, vice president of technology, and Eric Schmitt, vice president of operations, are retiring at the end of the year.
Ristanovic, who has more than 35 years of experience in the electric industry, came to CAISO from Siemens Energy Automation, where he served as global innovation manager. Previously he worked at the University of Belgrade’s Nikola Tesla Institute of Electrical Engineering, developing and implementing advanced power system applications.
Schmitt, who also has more than 35 years of experience, oversees California’s bulk electric system operations, real-time engineering and market services. Before joining the ISO in 2011, he served as senior vice president at Science Applications International Corp. in Tysons, Va.
“Petar and Eric represent the gold standard in the energy industry, and both were instrumental in shaping the California ISO into the pioneering, modern power grid and electricity market of today,” Mainzer said.
CAISO has not announced plans to replace them and did not respond to an inquiry by press time.
Offshore wind advocates said Wednesday they are confident the industry will retain its bipartisan support regardless of the results of the U.S. elections this year.
“We are in a world now where utilities in Indiana are rushing forward building wind farms,” said Seth Kaplan, director of government and regulatory affairs for Ocean Winds, the joint venture between ENGIE and EDP Renewables that has partnered with Shell New Energies to sponsor Mayflower Wind.
“It’s a changed world, where there is a broad recognition that this is the kind of generation we are able to build now because of other concerns in terms of health, in terms of cost and such, that we are not seeing other types of large-scale generation getting built,” Kaplan told the American Wind Energy Association’s Offshore Windpower Virtual Summit.
Seth Kaplan, Ocean Winds | AWEA
As power plants retire, and as loads rise with new demand from electric cars and electrification of heating and cooling, “it is a truly bipartisan, across-the-board need for this large-scale generation source to move forward,” Kaplan said. “It is not wholly dependent on climate policy; it’s not wholly dependent on state policy. Those are all elements, but there is a unifying bipartisan need from the shipyards in Louisiana to the ports in Massachusetts to the folks who want new generation in New York City.”
Regulatory Push
Moderator Joshua Kaplowitz, senior counsel for GE Renewable Energy, noted that the federal regulatory regime governing offshore natural resources dates from nearly 100 years ago. Regulations specific to OSW have not been updated since the Bureau of Ocean Energy Management was created in 2011.
“We have come a long way — and I have been involved in this industry for 15 years now — but we continue to evolve. There is more work to be done,” said Geri Edens, counsel for Vineyard Wind, a joint venture between Copenhagen Infrastructure Partners and Avangrid Renewables.
Geri Edens, Vineyard Wind | AWEA
BOEM has done a “tremendous job” trying to make regulations largely modeled on those for the oil and gas industry fit the needs of OSW development, with little experience beyond the failed Cape Wind project, Edens said. “So, it’s time to move on and try to start thinking about how the regulatory process can be improved.”
Edens said she hoped the agency, which announced a rulemaking in 2014 to update the regulations and provide more flexibility, will make more progress under a new administration.
“Now you see developers have to request numerous departures from the regulations because … all the things that go into gathering that data are onerous and not always feasible to submit at the same time that you submit a COP [construction and operations plan],” Edens said.
Claire Richer, federal affairs director at AWEA, noted acting BOEM Director Walter Cruickshank testified Sept. 22 before the Senate Energy and Natural Resources Committee that Congress has provided sufficient funding needed to hire the staff to assess all new lease areas and OSW proposals.
Claire Richer, AWEA | AWEA
BOEM worked through the pandemic and held a series of public hearings over the summer on the 800-MW Vineyard Wind project and the 1-nautical-mile turbine spacing advocated by developers and recommended by the U.S. Coast Guard. (See Developers Seek 1-Mile Spacing for Vineyard Wind.)
Kaplowitz asked about BOEM’s authority under the Outer Continental Shelf Lands Act of 1953, “authority that was appended to Energy Policy Act of 2005 as a couple paragraphs to the end of one of the sections of a statute … that has primarily been an offshore drilling statute.” Are there changes that can be made to enhance BOEM’s authority with respect to offshore wind permitting? he asked.
“It’s really up to the developers to figure out what they want and what they think will be the best way forward,” Richer said. “A lot of folks in Congress want to help offshore wind. I think there’s a lot of bipartisan support. … If we want it, we need to push for it.”
Joshua Kaplowitz, GE Renewable Energy | AWEA
Kaplan advised being “extremely careful” with making changes to a complicated regulatory structure, likening it to a game of Jenga, where if you pull any piece out it can cause the blocks to fall.
“Predictability is better than unpredictability,” Kaplan said.
Almost four years after the first wind turbines began commercial operations in American waters, and three weeks before an election that could change federal policy on climate change, speakers at the American Wind Energy Association Offshore Windpower Virtual Summit said it is time to engage everyone in the need for an energy transition.
Ali Zaidi, New York state | AWEA
“We’ve got to scramble all the jets in terms of the talent we need to attack the climate challenge and unlock the climate opportunity,” said Ali Zaidi, New York Gov. Anthony Cuomo’s deputy secretary for climate policy and finance. “That means people from all disciplines joining us. It means people bringing a diversity of backgrounds and skillsets.”
East Coast offshore wind projects and lease areas | AWEA
Marine biologist Ayana Johnson, co-founder of the Urban Ocean Lab, which describes itself as a think tank for the future of coastal cities, sounded a similar message.
“I think this is a moment in human history where we all need to think really carefully about what we’re good at and what we can contribute to [climate] solutions. There are plenty of problems [and] plenty of work to be done. So, the question is, how are we each best suited to make things better,” she said.
For Johnson, the answers led her and journalist Alex Blumberg to launch a podcast on climate solutions, “How to Save a Planet.” She also co-edited an anthology of essays and poems, “All We Can Save.” And she helped craft Democratic presidential candidate Elizabeth Warren’s “Blue New Deal,” a plan for restoring ocean habitat and adapting to climate change.
Ayana Johnson, Urban Ocean Lab | AWEA
But while Johnson has found her place, she fears many others haven’t been engaged.
“The environmental movement and … renewables [supporters] haven’t done a great job of describing what the future looks like if we get it right,” she said. “We have tons of media about the apocalypse and the day after tomorrow and the uninhabitable earth, and the fire and brimstone. But we don’t have [a picture of] what if we do put offshore wind in all these places? What if we do have great public transit? What if we do transition to regenerative farming? What does that look like?
“And so a lot of my work right now is about how do we make more concrete what we’re working towards so we’re not just [saying] ‘Oh, I should run away from the apocalypse,’” she added. “We’re not running, honestly. We’re just kind of sauntering away from the apocalypse. And we need to pick up the pace.”
AWEA CEO Tom Kiernan said the offshore wind industry needs to speak as one voice to realize the potential of 83,000 new jobs and $57 billion in investments the organization estimated in its economic impact assessment earlier this year.
“We do now have lots of different organizations advocating for offshore wind, and we’re not always perfectly aligned,” Kiernan said. “By working more as one, we can help our government partners do what we are asking them to do. So, for example, we are asking the federal government to establish transparency and consistency in the regulatory process. … We’re asking them to finalize additional wind areas and subsequent lease areas that can be auctioned. And we’re asking them to continue engaging with the fishing industry to find solutions that work for all of us.”
AWEA CEO Tom Kiernan | AWEA
Kiernan said that was the motivation for AWEA’s decision to merge into a new group that also embraces solar power and storage, the American Clean Power Association. It is expected to launch in January.
“Working powerfully and at scale together, we can have a bigger influence with Congress, the administration and with state capitals throughout the country,” Kiernan said. “This is a once-in-a-generation opportunity to create a whole new energy industry for America.”
Among the companies that have agreed to join the new organization are EDF Renewables, Berkshire Hathaway and NextEra Energy. Notably, the Solar Energy Industries Association has declined to join, although it says it expects to work with the group.
State OSW targets | AWEA
Eric Thumma, who leads Avangrid Renewables’ U.S. OSW commercial activities, was also bullish on the economic impact of the new generation. “We’re talking about very large capital expenditures that are going to have significant multiplier impacts,” he said.
Thumma said Avangrid estimates its Kitty Hawk project off the coast of North Carolina and Virginia could produce 2.5 GW of power and $2 billion of benefits through the development and construction of the project through 2030. “That doesn’t count approximately $100 million annually of wage increases and jobs that we’ll have through the next 25 years of operations and maintenance,” he said. “These projects can be economic engines. [Combining the Kitty Hawk project and Dominion Energy’s 2.6-GW OSW project off Virginia], you have a pretty big amalgam of 5 GW of projects.
“What drives investments are the power purchase agreements and [offshore renewable energy credit] agreements. [States have] really laid out a schedule that we can have confidence in that there’s going to be solicitations. That allows us to start talking about our ongoing investments and give the supply chain some confidence that those [requests for proposals] are going to be there.”
Eric Thumma, Avangrid Renewables | AWEA
Thumma said states could do more, however, by working more closely together on their OSW plans.
“We’ve sort of seen these [procurements] as one-offs. … As a former state official, I understand the simplicity of it and the motivation to do it. But is there a way to further collectively rationalize and work together on these projects? And if you did that, would there be some spillover effects into other areas of policy, like transmission interconnection, where we know there’s going to need to be cooperation in order to enhance the industry? I set that forward as a charge to the states to see if we can have some additional state leadership and cooperation in those areas.”
Chris Hart, Atlantic Shores Offshore Wind | AWEA
Chris Hart, president of Atlantic Shores Offshore Wind, a joint venture of EDF Renewables and Shell New Energies that is developing an OSW project off of Atlantic City, N.J., said the industry’s success will depend on collaboration with fishing interests and other stakeholders. To that end, the company hired two lifelong New Jersey fishermen as liaisons to the recreational and commercial fishing industries.
“They really put their reputation as fishermen on the line by working with the offshore community. We don’t take that lightly,” he said. “We’re working with them to build a collaborative, respectful relationship with a very tightly knit community that makes up New Jersey fishermen.
“We have to listen more than we speak. … We don’t have all the solutions. We may not even have the right problems identified. We need to listen.”
MISO and SPP state regulators appear intent on completing their work to improve the RTOs’ interregional coordination before 2021 arrives.
The Seams Liaison Committee (SLC), comprising regulators from the Organization of MISO States and SPP’s Regional State Committee, met virtually and briefly Monday, deciding to develop a decision matrix to help them prioritize the various recommendations offered up for their consideration.
Admitting he may have had “reckless optimism about wrapping up at the end of the year,” Arkansas’ Ted Thomas, SLC co-chair along with Texas’ DeAnn Walker, said the matrix should “do good,” given the difficulty of holding in-depth discussions over the internet.
“The joy of virtual meetings,” he said.
Thomas, Walker and OMS Executive Director Marcus Hawkins will work together on the decision matrix. They hope to have a workable format that they can discuss with the full RSC and OMS on Oct. 26 and 29, respectively.
Walker said she wanted to have an “orderly way” to step through the recommendations made by the RTOs’ market monitors. That came into clearer focus, she said, as Hawkins went through a list of recommendations and the grid operators’ responses. (See MISO, SPP Respond to Monitors’ Studies.)
SPP responded to recommendations for coordinated transaction scheduling, interface pricing and the MISO Independent Market Monitor’s report on market-to-market (M2M) coordination. Staff added clarifying remarks and noted which recommendations are included in SPP’s 2020 Market Roadmap.
MISO detailed its responses to the same recommendations, noting whether they have been included in its Integrated Roadmap or the IMM’s 2019 State of the Market report.
NERC’s Reliability and Security Technical Committee (RSTC) held a special meeting Wednesday to wrap up unfinished agenda items from its last meeting in September, when it ran out of time because of an extended debate over a plan for taking over the work of the disbanded Planning, Operating and Critical Infrastructure Protection committees. (See NERC RSTC Briefs: Sept. 15, 2020.)
SITES Revisions Underway
The issue that caused the most contention at the September meeting was the scope document for the Security Integration and Technology Enablement Subcommittee (SITES), intended to recommend “practices for incorporating cyber and physical security aspects” into utilities’ business activities. Several participants expressed surprise at the focus on cybersecurity at the expense of transformative business applications, which they had understood to be the goal of the subcommittee. The document was tabled for further discussion.
RSTC Vice Chair David Zwergel, of MISO, asked for volunteers to help revise the document, with the goal of bringing it back to the committee for approval at its next meeting in December. Kayla Messamore of Evergy, ERCOT’s Christine Hasha and Carl Turner of Florida Municipal Power Agency agreed to take part in the revision process.
Consent Agenda Items Approved After Debates
The RSTC’s business for this meeting primarily consisted of items from the previous meeting’s consent agenda that were pulled for further discussion because of a motion by Brian Evans-Mongeon of Utility Services Inc.:
Standard authorization request (SAR) for MOD-025-2 — Unit verification and modeling.
SAR for revisions to PRC-023-4 — Transmission relay loadability.
Reliability guideline: Gas and electrical operational coordination considerations — posting for 45-day comment period.
Reliability guideline: Distributed energy resource verification — posting for 45-day comment period.
White paper on assessment of DER impacts on NERC reliability standard TPL-001.
All items passed, with the exception of the reliability guideline on gas-electric coordination. The guideline was remanded to the Operating Reliability Subcommittee on a motion by Evans-Mongeon, who argued that NERC’s Electric-Gas Working Group deserved a chance to provide input into the resolution before it was passed.
Another dispute emerged during the discussion on the SAR for MOD-025-2, when Duke Energy’s Greg Stone moved that a provision in the document’s scope section calling for data to be “analyzed and used properly by transmission planners and planning coordinators” be removed, on the grounds that the language was not clear. However, his motion was defeated, with several members arguing that editing a SAR is not the committee’s purpose and that if the wording was vague, then it could be addressed by stakeholder comments.
Evans-Mongeon also questioned the white paper on assessment of DER impacts to TPL-001, calling it premature in light of the fact that the System Planning Impacts from Distributed Energy Resources (SPIDER) Working Group is working on another white paper covering DER impacts to the rest of NERC’s standards that could be released as early as December. He moved for the paper to be held so that a more thorough evaluation of DER impacts to all reliability standards can be completed.
In response, SPIDER Chair Kun Zhu, of MISO, explained that the group had already done “thorough homework” on TPL-001 and felt there was no reason to delay its analysis until work on the other standards was completed, when releasing the results earlier might help achieve a more reliable system. This view was supported by most other members, and the white paper was endorsed by the committee.
Committee Feels Growing Pains
Part of Wednesday’s meeting was taken up with complaints about procedural quirks of the new committee. Several members expressed surprise upon learning that approval of motions required a two-thirds majority of all members present, as opposed to all members voting. Turner and Evans-Mongeon raised questions about whether votes at previous meetings had been recorded properly, as they had assumed that approval only required a simple majority.
Several members also said the procedure currently used for initiating debate on a proposal, which requires a motion and a second in favor of the proposal, is unnecessarily confusing as members may not be aware that the motion is opening debate rather than beginning a vote. Chair Greg Ford, of Georgia System Operations, promised that the committee would consider revising its procedures with an eye toward clarity.
An estimated 20,000 to 30,000 MW of offshore wind capacity representing a $28 billion to $57 billion investment in the U.S. economy will be operational by 2030, according to the U.S. Offshore Wind Power Economic Impact Assessment.
OSW project development, construction and operations could bring a projected 83,000 jobs in that time and deliver $12.5 billion to $25.4 billion per year in economic output. During a panel at the American Wind Energy Association’s Offshore Windpower Virtual Summit on Wednesday, state officials from Massachusetts, New Jersey, New York and Rhode Island discussed their role in training tens of thousands of people for those jobs as part of that hoped for economic boon.
Kirsten Holland | Massachusetts Clean Energy Center
Kirsten Holland, program manager for offshore wind for the Massachusetts Clean Energy Center (CEC), said a “well trained and highly skilled workforce” is needed for OSW jobs where educational requirements range from apprenticeships to advanced degrees. Holland’s agency released an assessment in 2018 examining the workforce needs and economic impact associated with 1,600 MW of OSW development.
“It really laid the groundwork for our workforce development initiatives by demonstrating that there are thousands of jobs and hundreds of millions to billions of dollars in economic impact associated with just 1,600 MW of offshore wind built out,” Holland said.
Building on that initial assessment, Holland said the CEC maintains a website dedicated to training and educational programs for clean energy jobs, including OSW, which lays out career pathways, educational offerings and training programs. Additionally, Holland said there is an active process to identify unemployed or underemployed people to set up those “who need the jobs most” with education and technical training programs.
According to Holland, another priority area was increasing access to OSW jobs, specifically those in the commercial fishing industry. She said $2 million in grant funding to 15 institutions, including a public university, community colleges and other organizations, have helped build a bridge to new employment opportunities and training over the last two years.
Laura Hastings, deputy director of the Rhode Island Department of Labor and Training’s Real Jobs program, said her state offers the Wind Win RI certification program for high school students looking to work in the OSW industry. The state also offers two free years of tuition at a community college for a renewable energy program, and there is a partnership with the Business Network for Offshore Wind to train companies that want to work in the industry. (See Tiny RI Seeks its Share of Offshore Wind Jobs.)
Earn and Learn
Matthew Vestal, senior adviser for large-scale renewables at the New York State Energy Research and Development Authority, noted his state’s legislative mandate to install 9 GW of offshore wind by 2035. By his “fairly conservative estimate,” that could mean 10,000 jobs and the capacity to provide enough renewable energy to power 6 million homes and produce 30% of the state’s electricity load.
Matthew Vestal | NYSERDA
“We recognize that offshore wind is a very unique economic opportunity,” Vestal said.
Vestal said New York is spending $20 million to create the Offshore Wind Training Institute at the Farmingdale State College and Stony Brook University campuses and additionally providing grant funds for the Center of Excellence for Offshore Energy at SUNY Maritime College. The developers of the Sunrise Wind project will spend $10 million on the Offshore Wind Training Center at Suffolk County Community College. (See related story, Preparing the Wind Energy Workforce.)
Brian Sabina | NJEDA
Brian Sabina, senior vice president of economic transformation at the New Jersey Economic Development Authority, said Gov. Phil Murphy wants to expand opportunities for good-paying OSW jobs through “on-ramps and off-ramps” so that people can “earn and learn at the same time,” especially people of color and women.
“We’ve more than doubled participation in apprenticeship programs by Black, Latinx and female apprentices,” Sabina said.
One area where apprenticeships are needed is welding, a skilled trade that Sabina said has leveled off in New Jersey. That is where increased regional cooperation comes into play, according to Hastings.
Laura Hastings | RI Department of Labor & Training
“Welding is robust in Rhode Island and Connecticut, as we can build nuclear submarines, largely with welders, so that’s one way we can use regionalization to play on each other’s strengths versus what we don’t have,” Hastings said.
“There’s definitely the opportunity for direct or indirect collaboration on workforce training,” Vestal added. “I think there’s the ability to send workers to different states to make this a regional workforce rather than a state-by-state workforce.”
For students in either high school or college considering the OSW industry, Hastings said that critical-thinking and problem-solving skills are in-demand attributes, aside from education and training initiatives.
“Being able to look at something critically and come up with a new solution that doesn’t exist yet, this industry is ripe for that, and if that’s the kind of person and kind of thought process that you go through, that would only help you,” Hastings said.
