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

PJM MRC/MC Preview: Nov. 19,2020

Below is a summary of the issues scheduled to be brought to a vote at the PJM Markets and Reliability and Members committees on Thursday. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider.

RTO Insider will be covering the discussions and votes. See next Tuesday’s newsletter for a full report.

Markets and Reliability Committee

Consent Agenda (9:05-9:10)

B. The MRC will be asked to endorse updates to Manual 3: Transmission Operations incorporating clarifying changes resulting from its periodic review. (See “Manual Endorsements,” PJM Operating Committee Briefs: Nov. 6, 2020.)

C. The committee will be asked to endorse proposed revisions to Manual 3A: Energy Management System Model Updates and Quality Assurance resulting from its periodic review. PJM said the changes include correcting grammatical mistakes and updating references to the behind-the-meter generation rules that took effect in September 2019. (See “Manual First Reads,” PJM OC Briefs: Oct. 8, 2020.)

D. Members will be asked to endorse proposed revisions to Manual 10: Pre-Scheduling Operations to incorporate clarifying changes resulting from its periodic review.

E. The MRC will be asked to endorse proposed revisions to Manual 11: Energy & Ancillary Services Market Operations and Manual 12: Balancing Operations to address changes related to five-minute dispatch and pricing. The revisions are designed to increase transparency and conform to the current PJM process for calculating LMPs. (See “Manual 11 Revisions Endorsed,” PJM MIC Briefs: Nov. 5, 2020.)

F. Members will be asked to endorse proposed revisions to Manual 14D: Generator Operational Requirements to incorporate changes resulting from its periodic review. (See “Manual Changes Endorsed,” PJM OC Briefs: Oct. 8, 2020.)

G. The committee will be asked to endorse a minor correction to Manual 18: PJM Capacity Market regarding an effective date for notifying pseudo-tied resource owners of their assigned locational deliverability area prior to each delivery year. The revision was endorsed as a “quick fix” at last month’s Market Implementation Committee meeting following a discussion in which some members objected to the process and suggested further talks on lingering pseudo-tie issues. (See “Manual 18 Update,” PJM MIC Briefs: Oct. 7, 2020.)

Endorsements/Approvals (9:10-9:20)

1. Day-Ahead Schedule Reserve (DASR) Update (9:10-9:20)

Stakeholders will be asked to endorse the final proposed changes to the 2021 day-ahead scheduling reserve (DASR) requirement. PJM said the final 2021 DASR requirement is 4.74%, slightly lower than the 2020 requirement of 5.07%. (See “Day-ahead Scheduling Reserve Endorsed,” PJM Operating Committee Briefs: Nov. 6, 2020.)

Members Committee

Consent Agenda (10:30-10:35)

B. The MC will be asked to endorse revisions to Manual 15: Cost Development Guidelines resulting from its biennial periodic review process.

B. Stakeholders will be asked to endorse the installed reserve margin (IRM) and forecast pool requirement (FPR) values included in the 2020 Reserve Requirement Study results. PJM is recommending an IRM of 14.4%, down from 14.8% in 2019. The FPR is essentially the same as 2019, at 1.0865 (8.65%) instead of 1.086 from the previous year. The study determines the IRM and FPR for 2021/22 through 2023/24 and establishes the initial values for 2024/25. The results are based on the 2020 capacity model, load model and capacity benefit of ties. (See “IRM Study Results Endorsed,” PJM MRC/MC Briefs: Oct. 29, 2020.)

November 15, 2020

PG&E Working to Improve Safety Blackouts

Pacific Gas and Electric on Thursday acknowledged it needs to get better at notifying local authorities and customers before shutting off power to prevent wildfires, but the utility said it performed far better this fall than it did last year.

In its report to the California Public Utilities Commission on the public safety power shutoffs (PSPS) of Oct. 25-28, the largest this year, PG&E said it had generally met its goals of notifying emergency officials and residents about potential blackouts in the days ahead of an event, but it still sees “opportunities for improvement”

That was unlike the PSPS events last October, when PG&E blacked out more than 2 million residents, many without warning. The utility’s websites crashed under heavy traffic, requiring state agencies to intervene. Its phone lines were also overloaded, and its shutoff maps often were inconsistent or incorrect, then-CEO Bill Johnson said. (See PG&E Restores Power amid Backlash.)

In a meeting Nov. 5, Lee Palmer, director of the CPUC’s Safety and Enforcement Division, said the state’s three big investor-owned utilities, including PG&E, had generally provided PSPS notifications at the “right cadence” in late October, alerting local authorities 48 to 72 hours before an event and telling customers they could lose power 24 to 48 hours beforehand.

In some cases, PG&E failed to notify customers of imminent blackouts because its “process broke down,” Palmer said. Southern California Edison and San Diego Gas & Electric had to make emergency adjustments to their shutoffs because of shifting Santa Ana winds and did not alert some residents before cutting power, he said.

In its report, PG&E said it had made significant strides since last year but acknowledged shortcomings, including that its “delivery of in-event information to [local emergency authorities and customers] needs to improve.”

“Although the situation has improved relative to 2019, there are still some timing inconsistencies between information posted in our online portal, information posted on our customer website and that provided by PG&E liaisons and representatives,” the utility said. “PG&E is working for ways to improve and expedite our information processes and flows to better serve our local partners and first responders.”

PG&E — CPUC President Marybel Batjer | *California State Assembly*

CPUC President Marybel Batjer, a vocal critic of PG&E after the 2019 shutoffs, acknowledged that the IOUs had “greatly improved, particularly the PG&E service area, over last year.” She said, however, that the commission was still waiting to hear from county officials and community representatives about their experiences in the blackouts.

In the late-October PSPS events, PG&E shut down power to 345,000 account customers, or about 1 million residents, across 35 counties. SCE blacked out 19,000 customers, and SDG&E shut off power to about 2,900 customers.

“The scale of these PSPS events makes it clear to all of us that the threat of wildfires and impact of PSPS events are not limited to a specific county or city,” Palmer said. “This is a statewide and regional concern.”

Batteries not Provided

CPUC commissioners focused in their Nov. 5 meeting on another problem: the lack of backup batteries provided by IOUs to at-risk residents.

PG&E had promised to deliver 8,000 backup batteries to customers who rely on medical devices in 2020 but had only provided 2,500 units, Palmer said. The utility has said it will deliver 1,500 more batteries by the end of the year, he said.

Rather than address the shortfall in its report, PG&E said it had worked “to provide a cumulative total of approximately 2,525 portable batteries to qualifying customers who need power during a PSPS event” along with food boxes, hotel stays and wellness checks to seniors and others in need.

SCE told the CPUC it would enroll 2,500 residents in its battery-backup program in 2020 but so far has provided only 200 batteries, Palmer said.

Logistical holdups and manufacturing delays caused by the COVID-19 pandemic are partly to blame, he said.

Batjer said she had repeatedly asked the utilities for updates on battery distributions during briefings this year, but the IOUs had only recently provided numbers. The figures fell short of what the commission had hoped for, commissioners said.

“None of them, frankly, lived up to the pledge they made to us in August and then updated by written memo in September,” Batjer said. “It’s something we must indeed continue to work on, so the medically baseline and critically in-need customers have backup batteries that they need during these unfortunately called PSPS.”

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.

November 15, 2020

RTOs, BPA Fear NAESB Rules Will Cut Tx

Commenters generally back FERC’s proposal to approve new standards for electric transmission but urged the commission to reject two replacement rules that they said could lead to less efficient use of the grid.

In July, FERC issued a Notice of Proposed Rulemaking to approve Version 003.3 of the North American Energy Standards Board’s (NAESB) Standards for Business Practices and Communications Protocols for Public Utilities (RM05-5-29, et al.). (See FERC Backs Latest NAESB Rules.)

Comments filed earlier this month by the Edison Electric Institute, the Bonneville Power Authority, the ISO/RTO Council (IRC) and Open Access Technology International (OATI) all generally supported the standards adopted by NAESB’s Wholesale Electric Quadrant (WEQ). Version 003.3 includes revisions responding to recommendations by Sandia National Laboratories to strengthen cybersecurity protections; change rules on redispatch services and transmission curtailments; and replace 56 requirements in NERC’s Modeling, Data and Analysis (MOD A) reliability standards addressing the calculation of available transfer capability (ATC). NERC asked that the rules be removed from its standards because they deal primarily with commercial terms rather than reliability.

But none of the commenters agreed with FERC’s suggestion that it might revise its own regulations on ATC. And both BPA and the IRC asked the commission to reject standards WEQ-023-1.4 and WEQ-023-1.4.1, which they said would prevent transmission providers from maximizing the utilization of their systems.

Scheduling Limits

Requirement 1.4 would prohibit transmission providers from granting firm transmission service exceeding the sum of facility ratings for an ATC path; 1.4.1 would limit net interchange schedules to this same amount.

The IRC said the requirements could expose transmission providers to compliance risks when there is a sudden, unexpected outage or derate of a transmission facility on an ATC path, “as there may not be sufficient time to adjust posted ATC or modify the current interchange schedule in a manner that would completely avoid a violation of the requirement language.” The requirements would also require transmission providers to disregard “expected usage” and account for full reservation capacity granted when calculating firm transmission service transactions. “Treating every firm transmission service reservation as if it is being used in full, regardless of the transmission customer’s scheduling activity, will undoubtedly result in less efficient use of the transmission system,” the IRC said.

BPA said the proposals “address regional seams issues arising primarily in the Eastern Interconnection and are not requirements migrated from the NERC MOD A reliability standards.” It said the rules would require transmission providers and operators to continually balance schedules so that the schedules never exceed the path ratings.

“These standards appear to be inconsistent with how Bonneville and other providers/operators in the Western Interconnection operate their systems,” BPA continued. “For Bonneville and others, an ATC path is allowed to be overscheduled up to 20 minutes prior to flow, at which point interruptions of non-firm service, curtailments or economic dispatches are then performed to ensure path limits are not exceeded. This practice supports the maximum utilization of the transmission system, a key commission objective with respect to transmission, including the integration of variable resources scheduled within the hour. There are many situations that arise which may allow additional schedules or non-firm reservations to stand prior to flow, such as changes in system conditions or the receipt of counterflow schedules.”

BPA said its concern “is particularly relevant in light of the recent heat wave events of August and September 2020 in California, wherein energy supply and transmission availability were severely constrained, which led to energy emergency alerts and ultimately rolling blackouts. Eliminating the practice of overscheduling until 20 minutes [prior to flow] on transmission facilities such as the California-Oregon Intertie … could exacerbate the problem by artificially restricting energy supply and transmission availability even further.”

The IRC said the requirements were included in WEQ-023 even though they were initially rejected by the NAESB Business Practices Subcommittee and opposed in comments by PJM, MISO, SPP, ERCOT and Ontario’s Independent Electricity System Operator.

ATC

In the NOPR, the commission expressed concern that WEQ-023 may lack the transparency and consistency of MOD A, noting that it does not contain replacements for MOD-001-1a requirements R6 and R7, which direct transmission operators to use assumptions no more limiting than those used in its planning of operations calculations.

The commenters were unconcerned. EEI and OATI said the commission should not attempt to address ATC calculations within its regulations and that any additional changes should be considered in the NAESB standard development process.

“By its directives in Order No. 890 and its provisions in the pro forma Open Access Transmission Tariff (OATT), the commission has ensured that the ATC calculation is consistent and nondiscriminatory,” EEI said.

NAESB provides “an open, transparent and industry-participant-driven process” for considering additional rule changes, said OATI, which offers transmission providers software and processes for automation and decision support.

“This fosters a working environment where both transmission providers and transmission customers can come together to discuss solutions to issues that address the unique needs of both parties. This process is then documented for those not in attendance,” OATI said. “In contrast, unilateral alteration of the pro forma OATT lacks the collection of input from impacted industry participants. Without the input from such parties, the commission could unintentionally and unnecessarily burden industry participants with regulatory changes.”

The IRC said WEQ-023 contains “sufficient detail to protect transmission customers and ensure transparent, consistent and non-discriminatory ATC calculations” and increase transparency by requiring transmission providers to document and post their calculation methodologies.

“The WEQ-023 standards reflect an industry-wide consensus on the treatment ATC and TTC [total transfer capability] from a commercial perspective,” BPA said. “There is no need for the commission add additional requirements.”

BPA also said FERC’s proposed language “includes ambiguous references to technical concepts such as using ‘factors derived from operations and planning data’ in the calculation of ATC and TTC.”

If the commission does order NAESB to pursue additional standards, BPA said, it and industry should “avoid conflating commercial and reliability standards. Any further work done by NAESB should be focused strictly on commercial-related standards, whereas NERC should be focused on reliability matters.”

Sequence

FERC also got pushback on whether it should cancel NAESB Version 3.2 and proceed directly to Version 3.3.

“Implementation of the different versions simultaneously are not necessarily simple upgrades,” EEI said. “Additionally, [Open Access Same-Time Information System] updates, training and testing are required for successful implementation.”

OATI said the implementation periods for 3.2 and 3.3 should be “separate and consecutive … to prevent wasted industry effort and cost” because combining the two would force companies to cancel or heavily revise their implementation plans.

“Keeping the Version 3.2 and Version 3.3 separate also decreases the impact to the industry and therefore reduces risk of implementation failure and errors,” OATI said. “The business practices included in Version 3.2 are significant changes to the currently established business practices. The impacts of pre-emption, right of refusal and consolidation affect many aspects of the transmission service procurement and approval process. The fundamental changes begin with transmission customer actions and extend into areas such as line capacity calculations, settlement calculations and billing notification systems. Combining the implementation of Version 3.2 and 3.3 exponentially increases the number of impacts changing in one period.”

The 18-month implementation period for Version 3.3 should begin after implementation of Version 3.2 ends, OATI added.

BPA said FERC should allow at least a 12-month implementation period for Version 003.3, after the final compliance deadline for 003.2.

Parallel Flow Visualization

The IRC asked FERC for an accelerated implementation of rules that it said will improve congestion management in the Eastern Interconnection by incorporating “parallel flow visualization” (PFV) into the transmission loading relief process.

The IRC said PFV, the result of a 14-year industry effort, “will more accurately account for internal flows [i.e., network native load] by incorporating the use of real-time data into relief obligations calculated by the interchange distribution calculator (IDC). Rather than estimating generator output based on load and whether or not units are on outage, the calculation will utilize real-time output and projected next-hour output to calculate native load and network service. This approach is similar to an approach currently used by PJM, MISO and SPP to calculate market flows that was incorporated into the IDC in 2003.”

It asked that the PFV standards be implemented on an expedited timeline, with compliance filings due nine months after the publication of a final rule in the NAESB proceeding and implementation required three months later.