Page 1016 – RTO Insider

November 16, 2020January 15, 2025

Study Outlines Challenges of Decarbonizing New England

The decarbonization of New England’s electricity system will require deployment of significant quantities of renewables and energy storage complemented by firm capacity from nuclear, gas-fired power plants, carbon-capture facilities, hydrogen generation or other options, according to a new study.

“Net-Zero New England: Ensuring Electric Reliability in a Low-Carbon Future,” co-authored by Energy and Environmental Economics (E3) and Energy Futures Initiative (EFI), studied how the electricity system can meet the challenges of growing demand and reducing economy-wide greenhouse gas emissions to nearly zero by 2050.

All six New England states have adopted economy-wide GHG reduction targets of at least 80% by 2050, with Massachusetts recently adopting a net-zero commitment. Through decarbonization of electricity supply and the electrification of transportation and buildings, the grid will play a critical role in achieving regional and state targets.

Removing all gas generation increases the cost of achieving a zero-emission grid by about $19 billion annually, relative to a zero-emission portfolio with zero-carbon fuels, according to a new report. | E3, EFI

EFI CEO and founder Ernest Moniz, former secretary of energy during the Obama administration, presented the study’s key findings in a keynote address to the New England Energy Summit on Monday.

Net-zero Goals vs. Increased Demand

Profound change is required across all energy sectors to achieve the decarbonization goals in New England, the study stated. Presently, transportation and buildings make up two-thirds of the region’s emissions. The study listed prime strategies for mitigating economy-wide GHGs, including aggressive deployment of energy efficiency, widespread building and transportation electrification, development of low-carbon fuels and deep decarbonization of electricity supply.

Regionally, electricity demand will increase significantly over the next three decades under the study’s net-zero scenarios. In the two bookend scenarios, annual electricity demand grows 60 to 90% — 70 to 110 TWh — from the present. Peak demand is predicted to reach 42 to 51 GW as peaking shifts from summer to winter in the 2030s. The growth is driven by the electrification of transportation and buildings that currently rely on fossil fuels. This demand increase will occur even with significant energy efficiency resources.

Study scenarios selected a diverse mix of 47 to 64 GW of new renewable generation capacity needed by 2050. The study found renewables — which include land-based solar and wind, offshore wind and distributed solar, along with 3.5 GW of new incremental Canadian hydro — will play a significant role in providing zero-carbon energy to the region.

New England’s limited land availability means greenfield development will be required for renewables to reach adequate scale, even if opportunities to develop brownfield sites, rooftops and marginal lands are maximized, the study found. It also found that New England’s geography, the slow pace of electric transmission planning and historical difficulty siting new infrastructure are significant challenges.

A decarbonized grid requires firm generating capacity, and natural gas and nuclear generation are the primary sources of firm capacity in New England. Solar, wind and battery storage technologies will play large roles in the future regional system, but reliance on these resources alone would require substantial quantities of renewable energy and storage and would be too costly.

In practice, as much as 46 GW of firm capacity could be needed in 2050 to ensure resource adequacy. The study included 34 GW of gas generation, 3.5 GW of existing nuclear, 8 GW of imports and 1 GW of biomass and waste.

Significant gas capacity is retained even though the gas plants operate far fewer hours and contribute less energy and emissions to the region. New resources potentially developed and deployed to provide low-carbon firm capacity, such as advanced nuclear, natural gas plants with carbon capture and sequestration, long-duration energy

Ernest Moniz, EFI | © RTO Insider

storage or generation from carbon-neutral fuels such as hydrogen. These resources would require significant investments in supporting infrastructure; for example, natural gas with CCS or hydrogen would require pipelines connecting New England to regions with suitable geology for carbon sequestration or hydrogen storage.

“Fundamentally, one way or another, we are going to need significant firm generation in order to have a reliable and resilient system,” Moniz said. “There are still some uncertainties that need to be addressed in that context, such as the need for long-term storage. There will be substantial infrastructure needs, and that frankly has been a significant challenge in New England. The path forward is not only through technical innovation but also through innovation in the policy and regulatory environment to allow the needed infrastructure to be built in a timely way.”

Technology Choices

The study also concluded that a broad range of technology choices could lower costs and risks. The availability of low-carbon firm generation technologies — such as advanced nuclear or natural gas with CCS — could provide significant savings and reduce the pressure of renewable development on New England’s lands and coastal waters. In addition to reducing costs, a portfolio approach to making low-carbon firm generating resources available mitigates the risks that one or more technologies do not materialize as expected.

Meeting net-zero GHG emissions requires carbon dioxide removal (CDR), though that alone will not be enough to achieve economy-wide decarbonization or meet the region’s policy targets. The lack of suitable geology for carbon sequestration makes direct air capture and bioenergy with CCS an imperfect solution, but a large stock of forests provides an excellent opportunity for in-region CDR.

“We need CDR to get to net-zero, probably beyond the borders of New England,” Moniz said. “We need to use the innovation capacity that this region is blessed with, hand in hand with what I believe will be a major federal push and a bipartisan push for really upping the game on the innovation of these clean energy pathways.” He added that the New England congressional delegation “should get fully behind a thrust to increase the innovation focus in the federal government.”

“By increase, I’m not talking here about 10% increases,” Moniz said. “I mean a doubling or tripling of the federal research and development budgets.”

Commercialization of emerging technologies can be additionally aided by leveraging regional innovation capacity, according to the study. Policymakers can increase the likelihood of commercializing emerging technologies by orienting the homegrown efforts of private, public and academic researchers already developing science and business innovations relevant to decarbonization. Specifically, advanced nuclear, long-duration storage and renewable fuels are innovation areas with tremendous regional potential, the study stated, and could play a role in supporting a low-carbon power sector, especially when localized efforts coordinate with federally funded programs.

November 16, 2020January 28, 2024

NEPOOL Markets Committee Briefs: Nov. 9-10, 2020

The NEPOOL Markets Committee passed a five-time-amended motion to update Forward Capacity Market (FCM) parameters for the 2025/26 capacity commitment period during a marathon two-day meeting.

The motion won with 64% in a sector-weighted vote. Of the five amendments passed, four of them came from the Union of Concerned Scientists on behalf of RENEW Northeast; the other was from Borrego Solar and Enel X.

The committee rejected the initial motion from ISO-NE and Concentric Energy Advisors (CEA) and Mott MacDonald (MM), two consulting firms hired by the RTO to help update the cost of new entry (CONE), net CONE, offer review prices (ORTPs) and performance payment rate values for the FCM. It gained only 16.7% support, with only the Publicly Owned Entity sector voting in favor.

The RTO said the calculations it put forth did not include changes from its Energy Security Improvements (ESI) proposal and assumed the continuation of the Forward Reserve Market. FERC Rejects ESI Proposal from ISO-NE.)

The proposed CONE and net CONE values were based on a new combustion turbine unit in New England, identified as the lowest-cost, economically viable technology likely to be built in the region. ORTPs were proposed for gas turbines, combined cycle, onshore wind, battery, energy efficiency and demand response technologies. The PPR value was based upon the CT technology recommended for the proposed CONE values. The CONE, net CONE and ORTPs were from CEA and MM.

The 1,143-MW pumped-storage hydroelectric Northfield Mountain Project on the Connecticut River in Massachusetts | FirstLight Power Resources

ISO-NE also put forth Tariff revisions to align the calculations for updating the energy and ancillary services revenues input in the years where there is no full recalculation to revise the indices used to update these revenues.

The RTO previously stated that interdependencies among the FCM parameters present unique challenges when calculating the combined effect of more than one amendment on the values. The RTO said it would tabulate and publish the five amendments’ impacts before a vote on Dec. 3 by the Participants Committee.

Monitor and RENEW Duel in Memos

Abigail Krich and Alex Worsley of Boreas Renewables presented RENEW’s four amendments, including capital costs and the investment tax credit for the ORTP calculation for offshore wind.

RENEW used an overnight capital cost of $3,326/kW (2019$) and an 18% tax credit for OSW in Forward Capacity Auction 16 and added that the RTO’s capital cost is 161% of expected prevailing market conditions for 2024/25 projects.

The RTO’s Internal Market Monitor posted a memo critical of RENEW’s calculations and methodology, saying “the use of a top-down method to infer a capital cost from contract rates is not an accurate means of establishing capital cost and the resulting ORTP value as compared to the bottom-up approach taken by the ISO and prescribed by the Tariff.”

According to the Monitor, the approach taken by CEA and MM is a direct estimation of capital cost.

“It uses actual capital cost data; [it] can be scrutinized in its components; and the value does not vary with assumed model parameters,” the Monitor wrote. “While the details were not made available to NEPOOL for confidential/commercial sensitivity reasons, they were scrutinized by MM, CEA and the ISO — none of which has a financial or other interest in having a higher or lower capital cost value other than one that accurately represents the capital cost of a new OSW project in New England.”

In reply to the Monitor, RENEW said ORTPs in FCA 16 would affect capacity commitment periods between 2025 and 2028, when many OSW projects will come online.

“Offshore wind plays a significant role in states’ plans to reach their renewable energy and decarbonization objectives,” the memo said. “Without an appropriate ORTP, these projects will be prevented from clearing in the market due to unreasonable mitigation, which will deprive them of revenue critical to their implementation and consequently increase costs to consumers.”

The Monitor also noted that setting the ORTP “too low … carries with it the potential for significant market harm.”

RENEW countered that setting the ORTP at the low end is “exactly what we should be doing according to the Tariff and FERC directives.” It added that the RTO itself in its December 2013 filing updating ORTPs for FCA 9 described the intent of the calculation is to set ORTPs “at the low end of the competitive range of expected offers so as to strike a reasonable balance by only subjecting resources to IMM review which plainly appear commercially implausible absent out-of-market revenues.”

“If it is the position of the ISO and IMM to subject offshore wind resources to a higher bar than that specified in the Tariff or FERC directives, that could explain why the ISO’s proposed ORTP values are head-and-shoulders higher than all public estimates,” RENEW said.

Order 841 Compliance Filing Nets Support

The committee unanimously supported ISO-NE’s plan for its third Order 841 compliance filing.

The RTO proposed Tariff changes to comply with three FERC directives. The first change was removing Tariff language that could have created a barrier to the participation of a storage resource in its markets, effective in the first quarter of 2021. The second is the inclusion of four bidding parameters and a newly defined term into the Tariff that the RTO will use to account for the state of charge and duration characteristics in the day-ahead energy market. It would be effective Jan. 1, 2026.

Separately at the NEPOOL Transmission Committee, the RTO and Participating Transmission Owners Administrative Committee have proposed Tariff changes to clarify the application of transmission-charge exemptions associated with storage. In addition to the compliance revisions, ISO-NE also proposed several clean-up revisions to Appendix C of the Tariff to correct outdated terminology.

The RTO will next seek support from the Participants Committee, which will vote on the plan at its Dec. 3 meeting, and has asked FERC to allow a Dec. 7 filing date.

Modifications for EERs, RAs Approved

The committee also voted to support the RTO’s modifications to the qualification process for energy efficiency resources (EERs) to better account for expiring measures. ISO-NE’s Ryan McCarthy wrote in a pre-vote memo to the committee that the modifications “will more appropriately balance the performance and expiration of energy efficiency measures and will produce qualification results that are more reflective” of EER capabilities.

There will also be changes to the monthly reconfiguration auction (RA) and bilateral qualification rules to better account for new financial assurance and performance accounting rules. Additionally, the RTO will assign monthly qualification to resources that become commercial during the capacity commitment period. The monthly qualification will track delayed commercial resources and allow noncommercial capacity to participate in monthly RAs and bilateral qualifications.

The EER qualification changes would become effective in February 2021 for FCA 16. The monthly qualification changes would become effective in January 2022 and implemented for the March 2022 RA and bilateral qualification period.

The Participants Committee will vote on the modifications at its Dec. 3 meeting.

November 16, 2020January 15, 2025

Do Natural Gas Bans Make Cents?

San Francisco and Ojai, Calif., last week banned natural gas in new buildings, bringing the number of cities in the state that have adopted building codes to reduce their reliance on gas to 39, according to the Sierra Club.

Ken Costello | NARUC

While such bans have become increasingly popular in the push for electrification, they are an “exceptionally bad” way to attack climate change, regulatory economist Ken Costello told the National Association of Regulatory Utility Commissioners’ Annual Meeting and Education Conference during a panel discussion Nov. 10.

“Less than 9% of carbon emissions in the U.S. are from direct use of natural gas in homes and buildings. The U.S. emits about 15% of world carbon emissions. Thus, under the condition where all buildings are converted to be electric and we have electricity produced only from clean sources, the reduction in worldwide carbon would be less than 1.5%, which would have no impact at all … on global climate,” said Costello, an independent consultant who formerly worked for NARUC’s National Regulatory Research Institute. “We know there’s more efficient ways to deal with climate change.”

‘Incongruent’

Richard Meyer, managing director of energy analysis for the American Gas Association, was also critical, saying natural gas is desired by consumers and that its infrastructure will be essential for decarbonizing. Bans represent “an all-or-nothing approach that seems incongruent with the size and the scale of the challenge” of climate change, he said.

Richard Meyer, American Gas Association | NARUC

Residential natural gas represents 4% of U.S. GHG emissions, with the commercial sector adding another 3%. “Residential natural gas emissions on average are about 250 million metric tons per year of CO2. That’s equivalent to two weeks of Chinese coal emissions,” Meyer said.

The third member of the panel, Amber Mahone, a partner in San Francisco-based consulting firm Energy and Environmental Economics (E3), acknowledged that U.S. natural gas use is a small contributor to worldwide GHG emissions.

“I would say there’s two reasons for action despite that fact,” she said. “One is the incredible power of the U.S. market to drive innovation. We’ve seen that with investments in solar and wind, bringing down the capital cost of that equipment dramatically and leading to widespread economic adoption of renewables. I think we could see similar innovation occurring in decarbonizing buildings, both with innovations in heat pumps as well as innovations with renewable natural gas. Bringing down the cost of biomethane and hydrogen would certainly be beneficial globally for reducing emissions.

“The other [reason] I would say is that deciding not to take action is a bit of a cop-out for one of the most advanced industrialized economies that historically has contributed to the predicament that we find ourselves in today.”

A Trend?

Although more than three dozen California cities have adopted gas bans, the idea has not taken root elsewhere.

Brookline, Mass., banned natural gas hookups in new buildings last year, but the state’s attorney general struck it down because state law pre-empted the city’s ordinance.

Meanwhile, Arizona, Tennessee, Oklahoma and Louisiana passed laws this year barring local governments from adopting electrification measures or natural gas bans similar to those in California, according to InsideClimate News. At least four other states introduced similar measures, it reported.

Percent of Californians living in jurisdictions with clean energy building codes | Sierra Club

Meyer said bans have been enacted without sufficient analysis on costs and benefits, including the strain on electric infrastructure and the impact on jobs, taxes, wages and low-income residents. “I’m not saying [carbon emissions from natural gas] can’t and shouldn’t be reduced,” he said. “I’m not saying they’re unimportant. Quite the opposite: AGA is committed to reducing GHG emissions through smart innovation, new modernized infrastructure and advanced gas technologies.”

But he said gas is the most affordable way to heat homes, with electric heat costing about 3.7 times as much. “The natural gas system today delivers a tremendous scale of energy to homes and businesses when they need it most. The gas system delivers about three times more energy on the coldest day of the year than the electric system does on the hottest.”

As evidence of consumer demand for gas, Meyer noted that although California has led the way on gas bans, it has also added almost 600,000 residential gas customers since 2010, more than any other state. He said natural gas and its infrastructure will be crucial to meeting climate goals, which some say will require a future “hydrogen economy.”

“One of the key ways to make hydrogen is via natural gas. And you can use carbon capture with a steam reformation process and have low-carbon sources of hydrogen,” he said. “Europe has … come to a recognition that you really do need to leverage the gas system to achieve your goals quickly, effectively and cost-efficiently. I think the U.S. will come to the same realization.”

No Easy Solutions

Mahone acknowledged that decarbonizing existing buildings is difficult and expensive, but she said their contribution to climate change is too important to ignore.

“All of the options on the table have challenges and costs if you look at the economics today. But we also know that reducing greenhouse gases is difficult in many sectors of the economy, including in the industrial sector and aviation and heavy-duty trucking,” she said. “So, if we shied away from one area where it looks hard, we might find ourselves not taking action anywhere. So, I do think it’s important to tackle greenhouse gases for buildings.”

Costs Vary by Region

Mahone also said the economics of replacing gas heating with electricity varies by region. In the Bay Area, she said, there has been a trend toward all-electric new construction, particularly in multifamily buildings, because of the cost savings and reduced permitting time from avoiding natural gas hookups.

Berkeley, one of the first cities to adopt a gas ban, has “a relatively mild climate. … We get an occasional winter frost and that’s about it,” she said. “We do see that electrification can reduce energy bills in some cases.”

Some colder regions are opting for dual-fuel heating systems, “where you can gain the benefit of high-efficiency heat pumps during most hours of the year and still have access to backup thermal heat in colder times,” she said.

She noted that Pacific Gas and Electric supported the Berkeley gas ban to avoid investments in new gas assets that may later prove to be underutilized. “That’s a pretty remarkable statement, I think, coming from a gas utility.”

Mahone noted that gas pipelines and distribution systems are typically financed and amortized over 30 to 50 years, meaning a gas line installed today would not be paid off until as late as 2070. “So, I don’t think that it’s exactly right to look at the economics of a gas ban just purely from the [position] of an individual customer, because the gas infrastructure that our regulatory environment supports is actually … socialized over many customers.

“The alternatives to electrification are quite expensive as well,” she added. “Renewable natural gas has supply limitations. We see it costing about $10/MMBtu today — three to five times the cost of fossil natural gas.”

She noted that while some research suggests the cost of green hydrogen — which uses renewable energy to produce hydrogen from water — may be reduced to between $11 and $20/MMBtu, it would still be well above the cost of fossil natural gas.

Geoengineering?

Costello said policymakers also could consider options for adapting to climate change rather than attempting to eliminate GHG emissions, such as geoengineering, which includes CO2 removal and solar radiation management, or sunlight reflection.

“If you look at the history of mankind, humans have adapted to very drastic conditions of climate and other things over time, and that’s sort of one way to deal with this. But I think the savior of all this is technology, innovation,” Costello said.

“Geoengineering … is somewhat controversial, but still, it’s an option that’s on the table. In fact, some of the best minds now are saying that we have to have a portfolio of different actions to deal with climate change. So far, we have disproportionately focused in on emission reductions.”

November 16, 2020May 6, 2025

NARUC Panel Debates Clean Energy and Markets

Four present and former regulators told the National Association of Regulatory Utility Commissioners last week they are skeptical that carbon pricing and mandatory capacity markets would achieve decarbonization goals.

Instead, consultant Rob Gramlich, who served as an aide to former FERC Chair Pat Wood III, touted the energy-only market his former boss helped design in ERCOT. Former Montana regulator Travis Kavulla cited the simplicity of a clean energy credit market, saying it could save PJM billions annually. Rhode Island regulator Abigail Anthony warned against mixing clean energy goals with economic development, while Kentucky regulator Talina Mathews predicted the role of PJM’s capacity market would diminish.

Speaking at the NARUC conference on clean energy and markets were (clockwise from top left) moderator Judith Jagdmann, Virginia State Corporation Commission; Abigail Anthony, Rhode Island Public Utilities Commission; Talina Mathews, Kentucky Public Service Commission; Rob Gramlich, Grid Strategies; and Travis Kavulla, NRG Energy. | NARUC

Judith Jagdmann, a three-term member of the Virginia State Corporation Commission, moderated the general session discussion on clean energy and the markets at NARUC’s Annual Meeting and Education Conference. The session Nov. 10 came less than a week before Monday’s deadline for comments on FERC’s proposed policy statement inviting states to introduce carbon pricing in wholesale electricity markets (AD20-14). (See FERC: Send Us Your Carbon Pricing Plans.)

Don’t Mix Economic Development with Energy Goals

Anthony, who was appointed to the Rhode Island Public Utilities Commission in 2017, opened the session by listing the criteria she said were needed for a wholesale market design to meet state clean energy objectives: It should deliver incremental carbon reductions; allow clean energy projects to secure financing; include penalties for facilities that fail to deliver; and internalize externalities that are associated with the markets.

Abigail Anthony, Rhode Island PUC | NARUC

What the market should not attempt to do, she said, is “deliver on policies that are not direct externalities of power generation,” including economic development.

“It’s going to take many billions of dollars in investments to mitigate climate change and achieve our states’ greenhouse gas reduction targets, and we risk not having the means to meet those greenhouse gas-reduction goals when we make economic development and local jobs the primary purpose of clean energy,” she said. “So, I think that for our own good — kind of to save us from ourselves — we need markets that are designed to deliver maximum carbon reductions at the least cost.

“I think that [ISO-NE] can certainly design a market that internalizes carbon externalities. The F orward Clean Energy Market seems to be a good example of a market structure that internalized the carbon value of clean energy and provides the stable medium- or long-term revenue stream that allows projects to be financed,” Anthony said. “But to realize cost savings over current practice, states would have to cede control and allow the market to deliver the most efficient projects.”

Carveouts for in-state resources would make the market less efficient, she said. “States have a lot of policies, and very few of them should be reflected in wholesale markets.”

Similarly, the market should not attempt to internalize externalities such as concerns about the land-use impact of solar generation, Anthony said. “The loss of farmland, or pollinator habitat — those are externalities of land development, and the externality needs to be internalized via the price of developing land so that those additional costs flow to whatever development goes on that land, whether it’s solar or condominiums.”

Asking Markets to do More than they Can

Mathews, who joined the Kentucky Public Service Commission in 2017, said markets are best at security-constrained economic dispatch: “The megawatts get to the customers at the least cost available.”

But she said their success depends on a large footprint and a uniform commodity. “I think when you start to carve out the footprint and then you start to change [to] green megawatts, blue megawatts, red megawatts, black megawatts, then you’ve suddenly started segmenting that market and it becomes less efficient.”

Talina Mathews, Kentucky PSC | NARUC

That, she said, is PJM’s problem: dealing with a patchwork of state laws and executive actions, including goals for renewable energy, clean energy, carbon and energy efficiency.

“You’re kind of asking the market to do more than it was designed to do or that it can do efficiently,” she said. “I think fundamentally you will get to a point in an RTO like PJM where there will be state policies that get promoted at the expense of other state policies, and I think you’ll see then either [state] commissions making the decision to pull their utilities out [of the RTO], or maybe in other states, they’ll tell their utilities they have to [use] fixed resource requirements … to acquire their own resources to meet their load, and the capacity market will just be residuals.”

Clean Energy Credit Market, not Carbon Pricing

Kavulla, vice president of regulatory affairs for NRG Energy, noted that 30 jurisdictions have adopted clean energy standards (CES) or renewable portfolio standards and a quarter of the U.S. population is in areas that have declared 100% clean energy goals. But only a handful of them, such as members of the Regional Greenhouse Gas Initiative (RGGI), price carbon.

Travis Kavulla, NRG | NARUC

“For PJM, which has both CESes, RPSes and carbon pricing, the market for [renewable energy credits] is about four times as large as the market for emission allowances within RGGI. … So, if FERC and states are really going to be speaking the same policy language here, it really needs to center around that trade in credits — renewable energy credits or something hopefully more technology-neutral so you can fulfill Commissioner Anthony’s mandate for the same value for the same increment of carbon reduction.

“I think states and FERC alike would be well advised to consider setting up state-led, RTO-facilitated markets for these clean energy credits,” continued Kavulla, who served as NARUC president during his term on the Montana Public Service Commission. “The Forward Clean Energy Market is one type of market design that could facilitate that; there are real efficiencies to be wrung out of the system now.”

RPS and CES programs are often targeted toward particular technologies or include locational requirements, he said. And they are usually secured through long-term contracts that undermine RTO markets’ shift of risk to generation owners like NRG, he said. “So, that same basic model that’s worked fairly well for restructured jurisdictions is something that I think can apply to a trade in clean energy credits to get it to look a little bit more like a competitive market where investors have to take risk.”

Kavulla cited a study published last month by Energy and Environmental Economics that found an efficient regional CES could save $2.5 billion annually in PJM. The study also said that existing state carbon policies and subsidies will increase electricity costs by more than $3 billion in 2030 and achieve less than half of emissions reductions that could be achieved through a competitive, market-based approach. (See Study Recommends Carbon Price for PJM.)

“That study shows that a regional, efficient CES can also rival the efficiency of a regional carbon price” without concern over the kind of carbon leakage seen in RGGI, Kavulla said. “In a regional carbon price configuration, in order for it to really work, you need price uniformity across an entire region. And it’s going to be hard to achieve that in a mix of states as diverse as West Virginia and Maryland, to use two neighbors.”

In contrast, a CES market would provide “a lot more flexibility for the states, as well as more of a seat at the table in terms of governance and market design oversight, simply because they ultimately control the spigot of demand.

“I think a more voluntary market like a regional clean energy standard or a clean energy market is probably a more politically appealing way to go, simply because a lot of states have voluntarily expressed the quantity they want as well as the reserve price — the price ceiling. And you don’t have to worry about FERC playing carbon referee on leakage,” Kavulla continued. “I think it’s worth FERC considering carbon pricing … but they really need to be considering alongside that a policy for a regional clean energy standard. Because without it, I fear, states and FERC are still going to end up two ships passing in the night.”

ERCOT Model

Gramlich, president of Grid Strategies and executive director of Americans for a Clean Energy Grid and the WATT Coalition, said he was confident the U.S. can achieve more than 80% renewable penetration and up to 95% carbon-free generation with existing technologies.

Rob Gramlich, Grid Strategies | NARUC

“But you operate that system differently, and so, we’re going to have to think about how do we not only get the long-term procurement for the carbon-free, clean renewable resources … but also the flexible and firm resources, because we need to acknowledge there will be three-day periods where there isn’t a lot of wind or sun.”

Gramlich said he supports ERCOT’s energy-only model, which makes competitive retailers responsible for resource adequacy. “Of course, if a state has more ambitious clean energy objectives, they can pass a CES or carbon price and do that if they wish. If a state is not interested in that much retail competition … they can do a New Jersey-style [basic generation service auction] under that same market structure, where … you still get the benefit of competitive generation.

“Right now, it’s really unclear between a lot of different entities who has the responsibility” for resource adequacy, he said.

Commissioner Jagdmann noted that Texas has shown reserve margins as low as 3%. “Are you comfortable with that?” she asked Gramlich.

“Every year is another test of the ERCOT model, and every year it works,” Gramlich replied. “And then every skeptic or every fan of central capacity markets says, ‘Oh well, there was something unique about last year. We’ll see how it goes next year.’ You know, we’re in Year 20. … It’s been working great every year. I don’t think reserve margin is necessarily the right metric of reliability; it will be different in the future if you get that active demand-side” response.

“Texas isn’t perfect,” Gramlich continued. “They need more dynamic retail rates, like most states do — some type of real-time, time-of-use [pricing] or some other type of pricing on the retail end.

“We all need to get used to scarcity pricing in any RTO. I think all of them should have prices that go … well into the four digits, because there are times when the accurate wholesale price in terms of the value of energy is up there. Now the key from a consumer protection standpoint … is you want to make sure nobody actually has to pay that. And you do that by making sure there is forward contracting or hedging. And that basically is what happens in Texas. You get to $9,000[/MWh] prices, but you look around and pretty much everybody is hedged. So, it’s sort of like: You don’t want to get the speeding ticket, but you didn’t have to speed.”

Pricing Carbon in Electricity but not Heating, Vehicle Fuel

Anthony said the focus on carbon pricing in wholesale power markets alone is myopic.

“What we’re really, really going to need if we’re going to achieve our goals is an economy or energy sector retail carbon price, which theoretically would be a much more efficient tool to achieve the New England states’ goals around transportation and heating electrification.

“If we continue to price carbon in electricity like we do through RGGI and all of our other clean energy goals and continue to ignore it in the price of natural gas and heating oil and transportation fuels, we’re going to fail at our electrification efforts because we’re just going to keep driving up the price of electricity even more relative to its substitute fuels.”

November 16, 2020

ISO-NE to FERC on Fuel Security: What Now?

ISO-NE asked FERC on Friday whether it was free to seek its directions on how to improve its fuel security following the commission’s ruling last month rejecting the RTO’s proposed Energy Security Improvements (ESI) market design (ER18-1509, EL18-182, ER20-1567).

“The region is at a crossroads with respect to energy security and its reserve markets,” ISO-NE said. “The ISO does not believe that it is prudent to move forward without the opportunity to speak freely with the commission and its staff. Accordingly, we are stalled.”

In July 2018, FERC found that ISO-NE’s Tariff is not just and reasonable because the RTO lacks a way to address fuel security concerns, prompting a nearly two-year-long effort that resulted in the ESI proposal. (See FERC Rejects ESI Proposal from ISO-NE.)

ISO-NE told FERC that it, along with New England states and other stakeholders, “expended considerable resources and time evaluating the region’s fuel and energy security and possible market design enhancements.” Still, its efforts, which included more than a year of stakeholder meetings, “did not benefit from a consultation” with the commission because of ex parte communication rules following the 2018 order.

ISO-NE fuel security — FERC headquarters | © *RTO Insider*

The RTO requested confirmation of its understanding that the commission’s rejection of ESI left it up to ISO-NE “to determine whether to pursue market solutions to the region’s needs” and that it does not have a pending obligation from the 2018 order to file another proposal.

ISO-NE spokesperson Matt Kakley said that the filing explicitly seeks clarity on whether “ex parte communication rules that are part of a [Federal Power Act Section] 206 proceeding still apply” following the commission’s decision. Kakley noted that the RTO did not request a rehearing of the decision.

The RTO asked that FERC act on its request by Dec. 1, contingent on no other party filing a rehearing request.

ESI would have allowed the RTO to procure energy call options for three new day-ahead ancillary service products to improve the region’s energy security, particularly in winter, when natural gas shortages can leave generators without fuel. Option awards would have been co-optimized with all energy supply offers and demand bids in the day-ahead market.

FERC ruled that the products “do not provide enough time for resources to take the steps necessary to perform during stressed conditions if they have not already taken them” as arranged fuel, for example. The proposal would have allowed resources that have not made advance arrangements to not participate because of its voluntary nature, undermining its ability to address fuel security, the commission said.

The commission also rejected an alternative proposed by NEPOOL, which would have had lower costs to ratepayers than the RTO’s proposal but contained the same deficiencies.

November 16, 2020

WECC Findings Show Complexity of Heat Wave Event

WECC does not want its analysis of the August heat wave that caused rolling blackouts in California and high-level grid emergencies in other Western states to be a “one-and-done” affair.

“Given the nature and complexity of the heat wave event, we didn’t think it appropriate to create just one report,” Vic Howell, WECC director of reliability risk management, said during a stakeholder call Wednesday.

Instead, the regional entity for the Western Interconnection is developing an information website that it can update as it uncovers more findings about the Aug. 14-18 weather event that prompted CAISO to shut off power to about 2.4 million California residents and provoked 30 energy emergency alerts (EEAs) across 10 balancing authority areas, including nine that escalated to EEA 3 — the highest level — according to RC West. (See Western BAs Lauded for Coordination During Western Heat Wave.)

Howell said WECC staff are still determining how to break down the website’s design into “buckets of topics.” He noted that the RE could not cover every issue related to the heat wave because of the complexity of the event.

WECC’s work is meant to supplement the analysis that CAISO, the California Public Utilities Commission and the state’s Energy Commission are performing to identify the root causes for the blackouts, Howell said. Those agencies jointly issued their preliminary report last month. (See CAISO Says Constrained Tx Contributed to Blackouts.)

Howell re-emphasized that WECC is broadening the scope of its analysis to include examination of developments across the entire interconnection. (See WECC Examining August Heat Wave with West-wide Lens.)

The objective is to identify the underlying issues behind the EEAs and provide corrective recommendations, according to Tim Reynolds, senior engineer at WECC.

“This isn’t a one-and-done. … We want to continue to go through this … and have that learning mentality so we can grow as an interconnection,” Reynolds said.

WECC’s analysis has produced four preliminary findings — “still subject to change,” Reynolds said — related to the cause of the emergencies, including: high demand for generation, transmission congestion, inaccurate forecasts and resource adequacy issues. The findings align with the California joint agency root-cause report.

During the heat wave, the Western Interconnection hit an all-time demand peak of 162,017 MW on Aug. 18, coming in well under the forecast peak of just under 167,000 MW because of conservation measures, Reynolds said. The system peak occurred about two weeks later than WECC had forecast and resulted in high levels of north-to-south energy transfers. At the same time, planned outages on north-to-south transmission lines created limitations that caused congestion on those paths.

“On normal days these outages may not have caused any issues, but as we just hit a peak load from the interconnection during this heat wave, there was some congestion that was happening,” Reynolds said.

He pointed out that a number of balancing authorities reported to WECC that inaccurate variable generation forecasts had forced them into EEAs. Some BAs also fell short in their demand forecasts.

Coping with Variability

Matt Elkins, WECC manager of performance analysis and resource adequacy, used the RE’s Maverik tool to walk stakeholders through the RE’s approach to examining resource adequacy shortfalls during the heat wave. “Are we forecasting the variability of the system accurately, so that we can really get ahead of these events and not be surprised by them?” he said.

To assess the accuracy of WECC’s summer peak forecast, Elkins’ group used geospatial maps to compare regional hourly demand data from the week of the heat wave against figures for the same week a year earlier.

Elkins noted that CAISO found the August heat wave especially challenging because nighttime temperatures “didn’t get low enough” to temper demand. For example, WECC’s “same week” comparison showed that during the 12 a.m. PT interval Aug. 16, demand in WECC’s CAMX (California and Baja California Norte, Mexico) region was 41% above the 2019 figure, with the Northwest Power Pool (NWPP) Central and Southwest Reserve Sharing Group (SRSG) Desert Southwest regions at 44% and 29%, respectively, above the previous year. At the same time, demand in NWPP’s Northwest region was just 4% above that of the same week in 2019, while NWPP Canada (British Columbia) exceeded the previous year’s figure by a surprising 35%.

WECC also performed an analysis comparing heat wave load figures for its originally forecasted “peak week” — predicted to occur in late July — with those from its year-ahead 50/50 forecast. That exercise showed similar deviations between expectations and actuals.

Because the heat wave persisted for multiple days and was spread across such a wide region, WECC additionally compared demand from each of the Aug. 17-19 weekdays with its peak day forecast. This “repeated highest peak weekday” exercise showed lower, but still significant, variability between actuals and the peak forecast, with CAMX 21% higher during the 2 a.m. PT interval, the Northwest U.S. about 1% lower and the Desert Southwest in line with predictions. British Columbia came in about 40% above the forecast.

WECC Heat Wave — WECC used its Maverik tool to illustrate the hour-by-hour deviations from regional 50/50 load forecasts that occurred during the West’s August heat wave. | *WECC*

“I think one of the things we want to look at to really be sure our forecasts our correct is that we’re picking up Canada’s shape correctly. I don’t know if they’ve had a lot of air conditioning growth, so we definitely want to check that out,” Elkins said.

Elkins’ presentation showed that each exercise revealed that deviations from expectations persisted throughout the day over the heat wave. He speculated that the COVID-19 pandemic might have contributed to unexpectedly high load during the daytime, with residential demand boosted by people working at home, but he acknowledged WECC is still trying to gain insight into what drove the variability from forecasts.

WECC also examined how renewable performance during the heat wave stacked up against its 50/50 generation forecasts. “In this one … the numbers are going to be negative. That means it’s less than we expected, which is not a good thing,” Elkins said.

The analysis picked up significant underperformance of renewable resources. For example, renewable output in the CAMX area was 24% below forecast at 1 p.m. PT on Aug. 14. The following day saw intervals when Desert Southwest renewables underperformed forecasts by 20%.

Elkins said that while he “feels good” that WECC’s forecasts are reflecting the general variability in renewable generation, the next step is to “take a look and say what is the [forecasting] model telling us our reserve margins should’ve been to cover that amount of variability and then start looking at how much reserves were there in the system” during the heat wave.

The findings will be the subject of the technical session at WECC’s next quarterly Board of Directors meeting Dec. 8.

November 15, 2020

SPP Seams Steering Committee Briefs: Nov. 12, 2020

SPP’s seven different transmission planning processes “makes for an interesting mix of different ways to solve difficult transmission challenges,” staff said of the stakeholder team re-engineering the processes during last week’s Seams Steering Committee.

“None [of the seven] are perfect, and [they] will benefit from continual improvement,” communications strategist Russell Carey said.

Enter then, the Strategic and Creative Re-engineering of Integrated Planning Team (SCRIPT), which will analyze the interconnected processes and applicable cost-allocation methods. The team will also consider and evaluate options to strategically re-engineer those processes, delivering a final report with high-level recommendations to the Board of Directors and Members Committee next October. (See “SPC Takes Look at Tx Planning,” SPP Briefs: Week of Aug. 31, 2020.)

The recommendations are expected to consolidate the processes, improve responsiveness and certainty, reduce dependence on interconnection queue-driven analyses, improve decision quality, facilitate beneficial exports and improve cost-sharing.

SPP’s planning processes are either stakeholder-driven and member-funded (Integrated Transmission Planning, high priority, balanced portfolio and interregional projects) or customer-initiated and funded (transmission services, generation interconnection service and sponsored upgrades). Costs can be allocated through the RTO’s highway/byway methodology, sometimes subject to a safe-harbor limit, or directly assigned.

“A lot has changed since those processes were implemented,” Carey said, noting wind energy’s growth and the need to export its excess as one example. “We might need to see some efficient structures developed for exports.

“We have all these studies running in parallel. Sometimes, they’re looking at similar solutions to accomplish different goals. That has created uncertainty around the long-term viability of some of those projects,” he said.”

As if to add emphasis to Carey’s comments, SPP upped its record for wind energy with a new peak of 18,442 MW Nov. 14 at 6:20 p.m. The previous mark of 18,343 MW was set in July.

The SCRIPT will add sub-teams in early 2021 to begin digging into the different proposals.

One of stakeholders’ chief concerns is the backlog of interconnection requests. Staff said the queue might not be cleared of old requests until 2023 or 2024.

“More needs to be done to address our current backlog,” Carey said.

David Kelley, SPP’s director of seams and Tariff services, said staff are working on a separate strategy to reduce and “eventually eliminate” the queue’s backlog.

“We’re doing that in parallel with what the SCRIPT is already working on,” he said. “We’re hoping to bring something to the January round of meetings.”

Tx Study Briefing for SPP, MISO Stakeholders

SPP staff said they have been meeting with MISO, SPP to Conduct Targeted Transmission Study.)

The effort, which has been described as a “vehicle” offering a different approach than previous joint transmission studies, will begin in earnest with a joint stakeholder briefing on Dec. 11. The RTOs have conducted four joint studies in six years but have yet to agree on a single interregional project.

“It’s fully intended to be a project that results in meaningful [transmission] projects,” Kelley said.

The RTOs’ state regulators are also working on seams issues, but they’re “kind of in a waiting pattern right now,” said Adam McKinnie, an economist with the Missouri Public Service Commission.

The Seams Liaison Committee — comprising regulators from SPP’s Regional State Committee and the Organization of MISO States — met Nov. 9. OMS members came with a prioritized list of recommendations, but the RSC was “not quite there with their list,” McKinnie said.

The committee canceled a scheduled December meeting and will get together again in January.

M2M Settlements Crack $100M Barrier

A monthly record of $7.19 million in market-to-market (M2M) settlements with MISO in September pushed the accrued amount due to SPP to $102.57 million.

More than three dozen temporary flowgates were binding for 951 hours during the month, accounting for $6.16 million of the settlements. Permanent flowgates bound for 216 hours.

SPP Seam — SPP’s accrued market-to-market settlements passed the $100 million barrier in September. | *SPP*

Staff attributed the record settlements to increased loading caused by outages, high winds and a lack of cheap fast-ramping generation, resulting in high shadow prices.

It was the 11th month in the last 12 and the 50th overall in 67 months since the RTOs began the M2M process in March 2015.

November 15, 2020

Early-evening Solar Trough has ERCOT’s Attention

ERCOT has learned to live with a wind trough during the early afternoon hours, when coastal breezes drop and West Texas turbines aren’t spinning.

The same phenomenon is taking place with solar energy as it becomes a more reliable resource for the grid.

Dan Woodfin, ERCOT’s senior director of system operations, said last week that the summer sun sets about 7:30 or 8 p.m. in the west, where most of Texas’ wind farms are. The loss of solar production took place shortly after thermal generation shut down after helping meet peak demand, resulting in tighter operating conditions and lower operating reserves.

“There’s kind of an interaction there that hasn’t typically been there,” Woodfin said during a Gulf Coast Power Association webinar Wednesday. “It didn’t cause us a problem, but it did cause us to be a little tighter on some of those days during the early afternoon. As solar continues to grow on the system, it’s something we’re going to have to watch over.”

ERCOT had about 2.1 GW of additional installed solar capacity at the start of last summer than it did in 2019. Solar farms generally provided between 2.2 and 3.7 GW of energy from 2 to 3 p.m. this summer after producing a fairly steady 1.5 GW during the same period last summer.

“There was a little more variability around the solar output this year,” Woodfin said. “That’s just a matter of having more installed capacity.”

To address the solar trough, staff proposed a system change request (SCR811) that the Board of Directors approved in October. The SCR adds the short-term solar forecast to the resource-limit calculator’s formula for calculating the generation-to-be-dispatched value.

“Every five minutes it will start to look at the drop-off in solar and dispatch the rest of the generation,” Woodfin said.

He said the change is designed to avoid adding more system requirements to cover the balancing during each five-minute interval as solar production drops off.

“It will also provide an incentive for [thermal] generation to incrementally stay online as solar drops off by having the prices reflect that,” Woodfin said.

ERCOT began the year with about 2.3 GW of installed solar capacity but expects to end the year with about 5.2 GW. The grid operator expects to install as much as 10 GW of solar capacity by the end of 2022, with more planned for the future. The interconnection queue contains a staggering 81.3 GW of solar projects under some form of study.

November 15, 2020

Overheard at the 28th NECBC Annual Conference

The rush to transition to clean energy resources, ambitious offshore wind targets and increasing goals for net-zero emissions are combining to spur cooperation among the New England states, officials said last week during the New England-Canada Business Council’s 28th Annual Executive Energy Conference.

NECBC Conference — Connecticut DEEP Commissioner Katie Dykes | *NECBC*

“Our six different states, with all their diversity, are coming together and speaking with a common voice,” Connecticut Department of Energy and Environmental Protection Commissioner Katie Dykes said Thursday.

When the governors of Connecticut, Maine, Massachusetts, Rhode Island and Vermont released a joint statement in October calling for reforms to States Demand ‘Central Role’ in ISO-NE Market Design.)

“We desperately need to pursue a more unified market design to ensure that the renewables we’re contracting for are counted and credited appropriately in the capacity market, and that we also can align future procurements with transmission planning,” Dykes said. “We’re at a really positive moment here with our six states and in partnership with the ISO.”

ISO-NE CEO Gordon van Welie, who appeared on the preceding panel, said the RTO has long had the same concerns as the states and that its strategic plan “aligns quite well with the recent statements from the governors of New England.” (See “ISO-NE Shares ‘Vision for the Future,’” NEPOOL Participants Committee Briefs: Nov. 5, 2020.)

Offshore Transmission

Foley Hoag partner Kevin Conroy asked whether transmission to support offshore wind generation is a regional asset or one that belongs to the generator.

“At the scale that we see offshore wind developing, a generator lead line that is developed as part of one individual project will have some limitations in creating a real optimized transmission system,” Massachusetts Department of Energy Resources (DOER) Commissioner Patrick Woodcock said. “I don’t think we have arrived at the point where the limitations on the transmission system are going to impede [OSW] development, but we will arrive at that point very quickly.” It is important to make sure that the new industry “does not hit a wall, and I am concerned that transmission could bring paralysis to offshore wind development.”

The idea of a planned and shared OSW grid is earning support both locally and nationally. At a conference in September, New Jersey Board of Public Utilities President Joseph Fiordaliso said the board was committing to a shared network approach after procuring 3,500 MW of offshore wind, lower than half the state’s goal of 7,500 MW by 2035.

More recently, the National Association of Regulatory Utility Commissioners at its annual meeting Wednesday adopted a resolution urging FERC to consider “that a well planned OSW grid may result in enhanced transmission efficiency and reliability … [and] may reduce the impacts of OSW development on the marine environment and fishery.”

Dykes agreed with Woodcock and said that the commitment to decarbonization by most New England governors provides a strong foundation for discussions on regional cost allocations for a shared OSW transmission system.

“The states need to be in the lead and in control of those cost allocation discussions,” Dykes said. “I think that’s one of the big tragedies of [FERC] Order 1000 is that it took away some of the state control.”

“We’re very excited about offshore wind,” said Dan Burgess, director of the Maine Governor’s Energy Office. “We’re slated to have the first floating offshore wind project in the country with our University of Maine-developed Aqua Ventus floating technology, with one turbine in the Gulf of Maine.”

Simon d’Entremont, Nova Scotia’s deputy minister of energy and mines, touted the province’s work on tidal energy in the Bay of Fundy. In a rare Canadian reference to hockey, he said, “We’re not looking to go where the puck is; we’re going where the puck is headed.” He welcomed the new U.S. administration as “an opportunity for us to partner on initiatives where we have common supply chains and technologies we want to invest in. … If you are advancing a green economy, we’re doing likewise.”

‘Weird’ Gas Situation

Because the role of natural gas in power production will decline as more renewables come online, some believe that it is irresponsible to think about continuing to use the fuel or invest in anything to do with it.

NERC CEO Jim Robb is not one of those people.

“As we see declining volumes, particularly on the gas system related to power generation because it’s being displaced by other fuels, we create this very weird and challenging situation where there probably, almost certainly, needs to be more investment in gas infrastructure,” Robb said.

The pipelines and compressor stations may not be needed for the full 50 or 100 years over which such assets might normally be depreciated, he said.

“However, it may be really important over the next 15 or 20 years, so there is a real pricing issue around how to recover the cost of those assets,” Robb said. “The New England electrical system is especially vulnerable during the clean energy transition because of not having invested enough in natural gas infrastructure.”

Former FERC Chair Cheryl LaFleur, now serving on ISO-NE’s Board of Directors, said the region will transition to clean energy by “concentrating on the facts” and relying on solid analysis of greenhouse gas emissions outcomes under various scenarios.

“In New England, we’re used to seeing natural gas as baseload, because it displaced a lot of the coal and oil baseload, and it did so very well,” LaFleur said. “But in the future … given the decarbonization goals, I don’t see fossil fuels as a baseload; I see them as a balancing fuel in conjunction with a very heavy portfolio of variable, renewable generation.”

ENMAX CEO Wayne O’Connor said the clean energy transition needs “massive” amounts of capital.

“If modernizing time-of-use is our approach, we’re in big, big trouble,” O’Connor said. He said he disagreed with a New York Times op-ed on the future of natural gas that decried a “poverty of imagination” in the energy industry. “I think quite the opposite: that our industry has a great deal of imagination; that we’re looking for solutions for a better future.”

Dan Dolan, president of the New England Power Generators Association, said he thought of natural gas’s role “less about a fuel or a specific technology, and more about what are the types of services and attributes we need. The reason that we’re focusing on natural gas is that today it provides that dispatchable energy more cost-effectively than a lot of the alternatives, and as long as it continues to serve that role, while hopefully having the constraint within from an emissions standpoint, then we will continue to rely on it.”

Energy Security

Asked about his main takeaway from the California power troubles this past summer, van Welie said it was an energy-security problem. There was enough nameplate capacity around the system, but there were unusual demand patterns and insufficient supply, he said.

Clockwise from top left: Nova Scotia Deputy Energy and Mines Minister Simon d’Entremont; Kevin Conroy, Foley Hoag; Dan Burgess, Maine; Massachusetts DOER Commissioner Patrick Woodcock; NECBC President Jon Sorenson; and Connecticut DEEP Commissioner Katie Dykes. | *NECBC*

“It’s all around the assumptions one is making about what resources are going to show up and when, and I think it’s indicative of the kind of volatility we should expect on a system that’s going to be dominated by renewable resources,” van Welie said. “The real question is how much insurance do you want to pay for in the region to cover those types of situations.”

On FERC’s rejection of the RTO’s Energy Security Improvements (ESI) proposal, van Welie said, “We hit ‘pause’ until we can consult with the new commissioners and staff. … Our basic thought is that the concepts behind ESI are still fundamentally sound.” (See FERC Rejects ESI Proposal from ISO-NE.)

November 15, 2020

PJM IMM Warns Against Another Capacity Market Overhaul

PJM’s Independent Market Monitor urged the RTO not to rush into making changes to its capacity market before the recently approved design is given a chance to succeed.

The IMM made the plea in its latest quarterly report, issued Thursday, which noted that PJM energy prices were the lowest in the first nine months of this year compared to any year since the creation of the RTO’s markets in 1999.

According to Monitoring Analytics’ third-quarter State of the Market Report for PJM, the load-weighted average real-time LMP was 23.1% lower in the first nine months of 2020 than the same period last year, coming in at $21.22/MWh versus $27.60/MWh. Of the $6.38/MWh decrease, 57.7% was a result of lower fuel costs, while mild winter weather and the COVID-19 pandemic caused a significant drop in demand.

PJM IMM — Components of the PJM day-ahead, annual, load-weighted, average LMP. In the first nine months of 2020, 25.3% of LMP resulted from coal costs, while 17.9% were from gas costs. | *Monitoring Analytics*

The Monitor used these data to extol competitive electricity markets, noting that “changes in input prices and changes in the balance of supply and demand are reflected immediately in energy prices.”

“The value of markets is under attack, from those who assert that energy prices are too low and from those who assert that markets are incompatible with decarbonization of the power sector,” the Monitor said. “Organized, competitive wholesale power markets are the best way to facilitate the least-cost path to decarbonization. Markets provide incentives for innovation and efficiency. Renewables can compete. Innovation will occur in renewable technologies in unpredictable and beneficial ways.”

The Monitor said fears by over the impacts of the expanded minimum offer price rule (MOPR) have led stakeholders to discuss overhauling the PJM capacity market and states to consider opting out of the market using a fixed resource requirement. It acknowledged there are “clear issues” with the market’s design, including an overstated offer cap, the shape of the demand curve and the application of penalties for nonperformance.

But the Monitor also said there is no evidence that the new MOPR will make the market less competitive or that nuclear and renewable resources won’t clear it. The IMM noted that PJM has not run its annual Base Residual Auction since 2018 and that capacity prices have not been set for beyond June 1, 2021. “PJM should not rush to overhaul its capacity market again.”

New Recommendations

The Monitor included 10 new recommendations for changes and enhancements to existing market rules and implementation of new rules.

It made seven new recommendations in the Energy Market section of the report, including that:

the temporary cost method and penalty exemption provision be removed;
all units that submit non-zero cost-based offers be required to have an approved fuel-cost policy;
market participants be required to document the amount and cost of consumables used when operating to verify that the total operating cost is consistent with the total quantity used and the unit characteristics;
market participants be permitted to include only variable maintenance costs, linked to verifiable operational events and that can be supported by clear and unambiguous documentation of the operational data, including run hours and megawatt-hours, that support the maintenance cycle of the equipment being serviced or replaced;
offer capping be applied to units that fail the three-pivotal-supplier (TPS) test in the real-time market that were not offer capped at the time of commitment in the day-ahead market or at a prior time in the real-time market to ensure effective market power mitigation when the TPS test is failed;
eliminating up-to-congestion (UTC) bidding at pricing nodes that aggregate only small sections of transmission zones with few physical assets; and
eliminating increment offers, decrement bids and UTC bidding at pricing nodes that allow market participants to profit from modeling issues.

In the Energy Uplift section of the report, the Monitor recommended that PJM designate units whose offers are flagged for fixed generation in Markets Gateway as not eligible for uplift. It said units that are flagged for fixed generation are not dispatchable, and following dispatch is an eligibility requirement for uplift compensation.

The Generation and Transmission Planning section of the report included a recommendation that storage resources not be included as transmission assets for any reason. Monitor Joe Bowring brought the issue up in the Planning Committee on Nov. 4. (See PJM Moves Closer to Endorsing SATA.)

Finally, in the Financial Transmission Rights and Auction Revenue Rights section, the Monitor recommended that PJM enforce the FTR auction bid limits at the parent company level beginning immediately.