Page 1233 – RTO Insider

June 17, 2019

Overheard at EEI 2019

PHILADELPHIA — In the last two years, oil giant Royal Dutch Shell has purchased a U.K. electric utility and two electric vehicle charging companies. Shell CEO Ben van Beurden and his wife both drive EVs themselves.

“On the other hand, in this country, we have 43,000 zip codes,” oil expert Daniel Yergin said. “One hundred eighty-nine of them — which represent two-tenths of 1% — reflect 25% of all EV sales in the country.”

Yergin, founder of IHS Cambridge Energy Research Associates, offered that statistic to set the stage for a discussion on electrification and decarbonization at the Edison Electric Institute’s annual conference last week. The three U.S. electric utility CEOs who joined him agreed: While the industry has come a long way in reducing its carbon emissions, the road to carbon-free power won’t be a freeway.

Exelon CEO Chris Crane said there are regions, such as Commonwealth Edison’s territory in Northern Illinois, that are 100% carbon free now.

“For Illinois to declare they want to be carbon free by 2030 to 2032, that’s not a stretch. … And it’s because of existing nuclear and the renewables that have been installed without the storage, without the advanced technology. But in other jurisdictions that would be much more difficult.”

Crane said storage technology needs to advance beyond lithium-ion batteries before utilities can take full advantage of intermittent resources. “It’s a ways away from [the] central station being [in] full demise,” he said.

Duke Energy CEO Lynn Good said utilities must remain “the voice of reliability and affordability.”

“We need to recognize that we don’t have all the tools today to operate at scale to achieve a 100% renewable solution in four-season climates and heavy urban areas and areas that don’t have a mix of renewable resources that certain geographies have,” she said.

Xcel Energy CEO Ben Fowke said his company can help customers and communities reach 100% renewables with customized programs but that it will need more advances to reach Xcel’s company-wide target of 100% carbon-free by 2050 and 80% by 2030.

Eventually, the grid will be saturated with renewables and short-duration batteries, he said.

“And at that point, we’re going to [need] those carbon-free dispatchable resources. … Nuclear is one today. So, we’re all about preserving our nuclear fleet. And I think the technologies that will get us that last 20% on our goal … might come from hydrogen. It might come from the next generation of nuclear. It might come from carbon capture. It might come from something we don’t even know — long-term storage for example.”

EEI — From left: moderator Daniel Yergin; Ben Fowke, Xcel Energy; Lynn Good, Duke Energy; and Chris Crane, Exelon | © *RTO Insider*

Chef Says Adaptation is Recipe for Success

Chef José Andrés, the keynote speaker for the June 10 session, talked about how he and others provided more than 3.5 million meals in Puerto Rico following Hurricane Maria in 2017.

Andrés recalled how the effort grew “from one kitchen to 26 kitchens; from 20 friends [the] first day to 25,000 volunteers. We went from 1,000 meals a day the first day to more than 150,000 meals a day every day. We were delivering food in 935 places each day. … At the end, what seemed impossible became possible. What we did was adapt to every circumstance.”

Andrés said his group was initially rebuffed when it asked the Army to deploy its helicopters to deliver the meals to remote locations. “The bosses here would not make it happen, but when I met with the guy who was running the helicopter he said, ‘We’ll find a way to deliver that food.’ We needed to cross rivers without bridges. If I ask here, I never get it. If I ask the officer in charge of a unit of Humvees, boom! Those men and women would be there helping us cross the rivers. [When] we needed a boat to get to Vieques, if I ask over here, it would never happen. In the moment I met the Navy captain, all of the sudden, I had the boat to go every day to Vieques,” Andrés said.

“You see the men and women are extraordinary people, the military and [the Federal Emergency Management Agency]. But we need to liberate them from rules and regulations that don’t allow them to be successful. Because we are outside the system, we don’t follow rules. We don’t follow the plan. We continuously adapt.”

Andrés also recalled for the EEI crowd his first visit to New York City, when he was a member of the Spanish Navy and his ship docked at 30th Street on the Hudson River. “Last month, I opened a big restaurant … 100 meters away from the dock I arrived on at 30th Street. Do I believe in the American dream? Yes, I do believe in the American dream.”

Natural Gas: Bridge or Destination?

It wouldn’t be an energy conference without a debate about natural gas’s future. EEI’s panel (“Natural Gas: A Bridge or a Destination?”) featured an environmentalist, a representative of gas turbine manufacturer GE Power and two utility representatives.

Mark Brownstein, the Environmental Defense Fund’s senior vice president for energy, said gas’s future in a zero-carbon electric future will depend on the competitiveness of storage in supplementing intermittent sources and the gas industry’s ability to eliminate CO₂ and methane emissions.

If the goal is to be net carbon zero by 2050, gas’s future “has a lot to do with the level of investment in carbon capture and storage, either at the power plant or it may be in the context of producing hydrogen that is then run through combustion turbines,” Brownstein said. “But either way, you have to have some way of capturing that CO₂. The future is really up to you guys.”

DTE Energy CEO Jerry Norcia said his company is doing its part to prevent methane emissions by replacing leaky cast iron pipe with plastic.

Diane Leopold, CEO of Dominion Energy’s Gas Infrastructure Group, said the gas industry also needs to improve its physical and cybersecurity to match mandatory reliability standards for the electric industry. “So, we’ve been investing heavily, thinking of ourselves as the critical infrastructure to be able to be that backup … to achieve these goals of higher electrification and increased penetration of renewables.”

Brian Gutknecht, chief marketing officer for GE Power, said gas will continue to prosper as the cheapest dispatchable thermal energy technology, noting its energy density allows it to produce energy on 50 to 100 times less real estate than renewables.

Carbon capture “for us is the next tier,” he said, adding that GE’s gas turbines can burn 100% hydrogen. “Our customers are buying an asset that early on can accelerate decarbonization [by] burning natural gas, and over time, as the technologies advance, the role of gas is going to change, and our technology is able to change with it.”

Brownstein said the 2015 leak at the Aliso Canyon storage facility, which took four months to plug, is an “object lesson.”

“The methane emissions that came out of that facility … basically [wiped] out all of California’s climate progress for the course of that year, from all measures,” he said. “California learned from that experience … that battery technology was ready, willing and able to deploy to support the electric grid. So, the role that gas was playing in providing peak support in the summertime was taken up by batteries.

“The lesson is when the industry fails to take care of their equipment and emissions result, there are other competitors in the marketplace now … able to take up that slack — so much so that California is really playing with the idea of closing that facility and other facilities like it entirely. The options that we have to deliver reliability and resilience … are growing. It’s not the case that natural gas has a corner on that market.”

Gutknecht acknowledged that gas’s role will change. “It will be doing more firming when renewables aren’t available,” he said. “Batteries are going to play a very important role for shorter duration … storage. So, gas is left to play the longer duration role that may be required at times.”

Addressing Climate Change: A View from the States

At a session on the states’ view of climate change, former Ohio regulator Asim Haque, reflected on how his perspective has changed since joining PJM 12 weeks ago as executive director of strategic policy and external affairs.

Haque said the RTO has gotten whipsawed by stakeholders’ decision in April to explore how to accommodate carbon pricing in its markets. (See “Carbon Pricing Talks Move Forward,” PJM MRC/MC Briefs: April 25, 2019.)

“On the one hand, you’ll get folks within the environmental community who will say, ‘It’s about time.’ On the other hand, you’ll get perspectives — which I’ve already gotten — from states who will say, ‘How dare you engage in policymaking?’ This is the Catch-22 that the organization finds itself in.”

Haque knew what he was getting himself into when he took the job, however.

“From an outsider’s perspective, PJM is a very convenient punching bag,” he said. “Politically it’s so intelligent to utilize PJM in that fashion.”

The 13 states and D.C. in PJM’s territory have disparate views on climate policy, making it difficult to achieve any kind of consensus, Haque said.

The D.C. Public Service Commission is on one end of the spectrum, required to consider climate change in all decisions. “While states can move the ball … it’s a no brainer that federal action is necessary,” D.C. PSC Chair Willie Phillips said.

EEI — From left: PSEG CEO Ralph Izzo; D.C. PSC Chair Willie Phillips; Asim Haque, PJM; and Sam Robinson, deputy chief of staff to Pennsylvania Gov. Tom Wolf | © *RTO Insider*

With New Jersey planning to rejoin the Regional Greenhouse Gas Initiative and Virginia’s governor considering it, Pennsylvania is at risk of becoming the “donut hole” in RGGI, acknowledged Sam Robinson, deputy chief of staff for Gov. Tom Wolf (D). Republicans, who control Pennsylvania’s House and Senate, contend such a move would require legislative approval.

Although the state hasn’t taken steps to join RGGI, it “is the type of program we would consider,” Robinson said. “It’s something we’re looking at.”

Panel moderator Ralph Izzo, CEO of Public Service Enterprise Group, said the need for grid resilience will only increase in a world of electrification of transportation.

“If you think people are grumpy today when they can’t charge their cell phone after a two-day outage, think of what the future will be like if they cannot drive their car after a two-day outage.”

— Rich Heidorn Jr.

June 17, 2019

NYPSC Dings Utilities for 2018 Reliability, Safety

By Michael Kuser

Four of New York’s major utilities will collectively see their revenues reduced by more than $7 million for failing to meet certain reliability and customer service requirements last year, state regulators revealed last week.

The New York Public Service Commission on Thursday reviewed reports on utility performance in electric reliability, gas and electric safety and customer service in 2018 (Cases 19-E-0169, 19-E-0246 and 19-M-0307). “While most utilities are doing a good job providing safe and reliable service, four utilities have fallen short of our expectations in certain areas, and we will continue to act aggressively to ensure utilities improve performance,” PSC Chair John B. Rhodes said. “Additionally, as a result of this analysis, it is clear that utilities must be ready to address more frequent and powerful storms.”

NYPSC reviewing the reliability and safety of NY's utilities — The PSC held its regular monthly session in New York City on June 13.

The utilities being dinged for their performance include New York State Electric & Gas, Central Hudson Gas & Electric, Orange and Rockland Utilities, and National Grid’s Long Island gas operation.

Major storms last year accounted for more than 80% of the total customer-hours of electric service interruptions and 36% of the overall number of customers affected. New York experienced 36 separate major storm events in 2018, with the five largest occurring between March 2 and May 20, said Mary Ferrer, of the Department of Public Service’s Office of Electric, Gas and Water.

Last year ranks third in customer-hours of interruption in the last 20 years, behind Hurricane Irene and Tropical Storm Lee in 2011 and Hurricane Sandy in 2012.

Last year saw more customer-hours of interruption when including major storms than calendar year 2017; however, excluding major storms, the statewide interruption frequency and duration performance for 2018 declined compared to the previous year and the statewide five-year average, primarily because of fewer outages from equipment failures and tree contacts, Ferrer said.

‘Right Kind of Oversight’

The commission relies on two primary metrics to measure electric performance: the System Average Interruption Frequency Index (SAIFI), and the Customer Average Interruption Duration Index (CAIDI). By compiling the interruption data provided by the individual utilities, the average frequency and duration of interruptions can be reviewed to assess the overall reliability of electric service statewide.

reviewing the reliability and safety of NY's utilities — Benjamin Dunton

NYSEG had its worst performance last year since 2007 with an average duration of 2.17 hours, above the target of 2.08 hours. Central Hudson’s frequency performance of 1.50 did not meet the target of 1.38.

The duration and frequency target failures mean NYSEG shareholders will see a negative revenue adjustment of $3.5 million and Central Hudson shareholders will see a negative revenue adjustment of $2 million, the commission said.

All the utilities complied with safety standards in 2018. Manual stray voltage testing performed on approximately 1 million utility facilities statewide identified 396 stray voltage situations, more than in 2017, though incidences of the more severe category over 4.5 V declined. Most such incidents on utility-owned facilities stem from street lighting, DPS staff member Benjamin Dunton said.

In response to a question by Commissioner Diane Burman about why the more serious stray voltage readings were down from the previous year, Dunton said, “More awareness on the part of people doing construction work and digging.”

DPS staff member Sonny Moze delivered the report on customer service quality, which found that most utilities met or exceeded the standards for customer service for 2018, with the exception of O&R, which failed to meet its target for calls answered by a representative within 30 seconds.

“This is the right kind of oversight,” Rhodes said of the customer service report. “I appreciate that O&R is responding to the evidence and will appreciate it even more when their performance improves to the standard that we expect.”

O&R’s shareholders will be required to pay $450,000 for the performance shortcoming.

“I do think it’s important that we have more meat on the bone when it comes to the 30 seconds for calls answered,” Burman said. “The utilities point out why it’s taking longer to answer the call, so we might need to work on that.” O&R, for example, cited higher-than-normal call volumes.

Barring ESCOs?

The PSC also announced steps that could prohibit five energy service companies (ESCOs) from further marketing and enrolling new customers in New York. Only one of the five companies, Atlantic Power & Gas, currently has any customers.

“I think it’s important to identify that we are looking at potential violations of the Uniform Business Practices [adopted for ESCOs], and really relating to filings that haven’t come, and there are no customers there,” Burman said. “Two of them have voluntarily discontinued practicing in the state because they failed to report to us. The other two are orders to show cause, but again there are no customers involved.”

The commission has the authority to regulate ESCOs’ access to utility distribution systems, including the power to require them to meet price caps set at utility prices.

The PSC directed that Atlantic explain why the commission should not ban it from operating in New York or take other remedial action (Case 16-M-0618).

In March 2017, the commission ordered Atlantic to cease marketing to and enrolling customers. On March 4, DPS staff identified apparent violations of the order.

Atlantic does business in the service territories of Central Hudson, Consolidated Edison, and National Grid’s KeySpan Gas East and Brooklyn Union Gas. It has 30 days to counter the DPS findings.

Further, the commission also directed that Clear Choice Energy, Amerigreen Energy, Bluesource Energy and Got Gas? — none of which has customers — explain why they should not be barred from operating in New York for failing to file their annual compliance filings.

Sayre Farewell

Rhodes read a resolution of appreciation for Commissioner Gregg C. Sayre, likely attending his last session as commissioner, as the New York State Senate is soon to vote on Gov. Andrew M. Cuomo’s nomination of Tracey Edwards, a Long Island Democrat, to a seat on the PSC. State law sets a maximum of five members of the commission, of which only three can be members of the same political party.

The PSC currently has four members: three Democrats and one Republican.

June 17, 2019February 12, 2025

NEPOOL MC Debates Energy Security Models

By Michael Kuser and Robert Mullin

ISO-NE floated a portion of its long-term market proposal to address fuel supply constraints, and five stakeholders presented their own concepts at the June 10-12 meeting of New England Power Pool’s Markets Committee.

The RTO faces an October deadline to file a market design with FERC that permanently addresses the regional fuel supply issue — specifically winter scenarios when natural gas supplies are limited.

In March, the RTO filed an interim proposal with the commission to address winter energy security for the commitment periods covered by Forward Capacity Auctions 14 (2023/24) and 15 (2024/25). That plan would “provide incremental compensation to resources that maintain inventoried energy during cold periods when winter energy security is most stressed” (ER1 9-1428). (See ISO-NE Filing, Whitepaper Address Energy Security.)

The interim proposal consists of five core components, including a two-settlement structure, a forward rate, a spot rate, trigger conditions (such as extended cold snaps) and a maximum duration for compensation. But some stakeholders have found the plan to be unduly complex, with the Massachusetts attorney general contending it represents the most dramatic change to the energy and ancillary services markets since their inception.

Keeping it ‘In Market’

ISO-NE’s proposed long-term solution looks to be no less complex — and transformative — than its short-term one. Senior Market Designer Andrew Gillespie’s presentation last week focused on just a portion of the plan — a proposal to create day-ahead ancillary services products intended to ensure that in-market processes begin to cover more of the RTO’s next-day operating requirements.

“Meeting these requirements via ‘in-market’ awards improves resources’ incentives to arrange energy supplies facing uncertainty,” the presentation said.

ISO-NE’s proposal calls for the creation of an hourly energy call option: option sellers would offer resources in hope of clearing in the day-ahead option market. As the buyer of the option, the RTO would specify an option price for each hourly interval before submission of option offers, which would occur in concert with submission of hourly energy offers. A resource could submit offers for both options and energy for the same hours, subject to limitations based on its physical parameters.

A resource with a cleared day-ahead option would then have an option position open for a given interval, which would be “closed out” at the real-time LMP for that interval.

“If the real-time LMP is greater than the strike price, the unit will be debited an amount equal to the product of the option quantity and the difference between the real-time LMP and the strike price,” the presentation explained.

The resource would also be credited for real-time energy and reserves supplied at applicable real-time prices.

Day-ahead headroom is the difference between the sum of day-ahead schedule amounts and the sum of real-time economic maximum values for the winter on-peak hours. | ISO-NE

ISO-NE expects that the total volume of call options it procures will meet day-ahead ancillary services requirements.

“These amounts would be based, at a minimum, on the procedures currently applied by the ISO in developing a reliable next-day operating plan,” ISO-NE said.

From a supplier’s perspective, Gillespie’s presentation points out, the option is on real-time energy — not a specific real-time ancillary service; regardless of why the option was awarded, it will still be settled against the real-time LMP.

The RTO commissioned Analysis Group to provide some context on how the proposed changes might affect energy market outcomes. Company principal Todd Schatzki on Wednesday said its study concluded that the proposed improvements could change the way market participants make resource decisions and change economic offers in ways that improve energy security.

Gillespie also noted that the RTO is reviewing a stakeholder suggestion to develop its proposed Multi-Day Ahead Market (M-DAM) separately, after the rest of the energy security improvements are filed with FERC in October.

Massachusetts AG: Simpler, More Physical

In a proposal prepared by London Economics, the Massachusetts attorney general’s office recommended a simple auction format of sealed bids with a uniform clearing price.

Marie Fagan of London Economics described the Forward Stored Energy Reserve (FSER) proposal as a limited amount of insurance for a limited challenge; she said details on the timing of the auction and other matters would be discussed at the July 8-10 MC meeting.

The pros of a uniform clearing price? Each bidder that clears the auction is paid the same price as the highest-cost clearing bid. Bidders can also submit low bids at short-run marginal cost (SRMC) for low-cost (infra-marginal) plants, ensuring they will be chosen.

The Massachusetts attorney general’s office prefers a simple auction wherein bids vary depending on bidders’ independent evaluations of costs and other factors, as well as the strike price the bidder wants to offer. | London Economics

But the proposal acknowledged one potential negative outcome of a uniform clearing price — that a bidder could engage in portfolio bidding, raising the bid price over SRMC for plants it expects to be marginal.

London questioned whether ISO-NE’s proposal will be effective from a reliability or cost perspective. It said the FSER is a simple and smaller-scale alternative to the RTO’s complex scheme, helping preserve the market signal when supplies are tight.

NextEra: Reserve Products

NextEra Energy Resources propose d the creation of replacement energy reserve (RER) and generation contingency reserve (GCR) products to be purchased by ISO-NE in the day-ahead market.

NextEra’s Michelle Gardner emphasized that both RER and GCR would be physical products, not financial call options, and as such could increase real-time energy prices when fuel reserves are low.

“Resources that sell the call options would have incentives for next-day fuel arrangements,” NextEra said of ISO-NE’s proposal. “However, the extra incentives are weak at best. They depend on assumptions about lumpy offers and risk aversion. One simply cannot expect a strong response absent a fundamental change to real-time demand.”

If done incorrectly, a seasonal forward market is likely to depress energy market prices and provide the wrong incentives, NextEra said. A physical RER, coupled with the right forward incentives, is key, it said.

Calpine: More Precise; More Cautious

Calpine — which has long suggested that the RTO acted in haste in not allowing the market time to work through its energy security issues — presented an energy security concept dubbed Forward Enhanced Reserves Market, which would procure fuel-secure capacity for the winter months three years prior to the obligation year.

By qualifying resources based on their ability to contract for stored fuel or readily-used stored energy, Calpine proposes that suppliers bid at auction for a total minimum or maximum amount of megawatt-hours they will commit to offer off of stored fuel during an Operating Procedure 21, which is activated when the RTO declares an energy emergency event.

Rebecca Hunter, Calpine senior analyst for government and regulatory affairs, said the benefits of its market design include: fuel security through a diverse pool of resources; timely transition of the evolving resource mix; investment in the existing fuel infrastructure; and market design changes in critical winter months only.

Energy Market Advisors: Use Today or Save for Later?

Brian Forshaw presented a concept by Energy Market Advisors, which has concluded that ISO-NE’s market suffers from:

Misaligned incentives: Resources lack incentive to procure and maintain energy supplies that may be needed in the future.
Operational uncertainty: The system may not have sufficient energy available to withstand extended supply losses during winter.
Inefficient schedules: Energy supplies can be depleted prematurely even when stored energy may be more valuable in the future.

Forshaw’s presentation posed the hypothetical question of whether the RTO should “use stored energy today or save it for later when it may be more valuable?”

“How we answer this question has significant (and differing) impacts for resource owners, system operators and electric consumers,” the company said, concluding ISO-NE should primarily focus on addressing those problems as quickly and efficiently as possible. Forshaw cautioned the RTO against implementing M-DAM and seasonal forward procurement at the same time as day-ahead enhancements, contending that would significantly complicate stakeholders’ development, and FERC’s evaluation of such significant changes.

FirstLight: Filling Buckets

Tom Kaslow of FirstLight, owner of the largest pumped hydro facility in the region, presented his firm’s concept for defining energy security, which asks the RTO to “connect the dots” between fuel security and resource adequacy by ensuring that the latter is backed by sufficient fuel storage. Kaslow’s presentation posed the question in terms of generator fuel tanks, which he termed “buckets”: How many buckets need to be filled, he asked, against how many can be filled?

“If the aggregate gas-only generator winter capability exceeds the region’s capability to access gas to support simultaneous generation at such resources, their actual reliability support to meet winter peak load is less than their aggregate megawatts of capability,” the presentation said.

Based on FCA 13-related values, being resource adequate at the summer peak may not assure enough gas storage to be resource adequate at the winter peak. | FirstLight

FirstLight recommends ISO-NE “establish the highest level of aggregate winter gas-only capability that can be simultaneously fueled at winter peak demand” and give capacity credit to gas-only resources that have firm transportation rights or contracted priority to take LNG during winter.

“Limit qualified gas-only winter capacity on the rest of the gas-only fleet to the level of such generation that can simultaneously operate,” FirstLight urges.

By assuring that each procured megawatt can be fueled, FirstLight says, ISO-NE can avoid sending inaccurate market signals at times when winter capacity is actually not in surplus. At the same time, it will provide efficient longer-term signals for resources to install dual-fuel capability, contract for pipeline transportation or obtain priority access to LNG, it said.

June 17, 2019

Fire Season Starts in Calif. with Power Shutoffs

By Hudson Sangree

California’s annual wildfire season kicked off last week with high winds, a heat wave and precautionary power shutoffs by Pacific Gas and Electric to thousands of customers.

A wind-driven blaze called the Sand Fire burned 2,500 acres of hilly terrain 60 miles west of Sacramento, and another fire scorched 1,800 acres of dry grasslands in rural Central California. Neither fire caused serious injuries or property damage, but they underscored the threat of wildfires as vegetation begins to dry out after an especially wet winter.

In response to the hot, windy conditions, PG&E turned off power for a day or two for about 1,700 customers in Napa, Solano and Yolo counties near the Sand Fire and for nearly 21,000 in the Sierra Nevada foothills of Yuba and Butte counties. Last year’s Camp Fire, the deadliest and most destructive in state history, ravaged a large part of Butte and leveled the town of Paradise.

Southern California Edison and San Diego Gas & Electric have shut down power before when Santa Ana winds blew. (See Fire Season Becomes Blackout Time in California.)

PG&E first deployed its controversial Public Safety Power Shutoff program last October, nearly a month before the Camp Fire started Nov. 8 — though it did not use the measure in Butte just before that fire ignited.

Power shutoffs are now part of the utilities’ annual wildfire mitigation plans approved by the California Public Utilities Commission. (See California Regulators OK Utility Wildfire Plans.)

A Portland, Ore.-based utility announced Thursday it was adopting a similar measure, suggesting that intentional shutoffs may spread beyond California. The Pacific Northwest has seen its share of devastating wildfires in recent years.

“This measure would only be taken as a last resort to help ensure customer and community safety,” Pacific Power said in a statement. The utility, a subsidiary of PacifiCorp, serves about 764,000 customers in Oregon, Washington and an area of Northern California near the Oregon border.

The National Interagency Fire Center (NIFC) in Boise, Idaho, predicts an active wildfire season in California, the Great Basin and the Pacific Northwest this year because of a “robust grass crop” from winter rains.

“As we go forward into June, those grasses that we see across the landscape are going to dry and cure out … and we’ll see an increase in fire activity especially across California,” said Bryan Henry, assistant program manager of predictive services at the NIFC.

Temperatures soared above 100 degrees Fahrenheit in inland areas during last week’s heat wave. CAISO issued its first “flex alert” of 2019 by calling for residents to voluntarily conserve electricity during peak demand in the late afternoon and evening, when air conditioning use spikes and solar arrays power down.

“Because of widespread heat, the ISO anticipates energy demand reaching a peak of 42,800 MW this evening,” CAISO said in a June 11 news release. “Also, two units with a total generation of 1,260 MW are offline due to mechanical failures. The Flex Alert is being called in response to the high electricity demand and the reduced generation.”

California, which last year mandated greater dependence on renewable energy sources going forward, offset the spike in demand largely with natural gas peaker plants, according to CAISO.

June 17, 2019

PJM PC/TEAC Briefs: June 13, 2019

VALLEY FORGE, Pa. — PJM Planning Committee Chairman Ken Seiler said the new executive director of systems operations, Dave Souder, will replace him as committee chair in July.

Souder currently heads the Operating Committee. Seiler is becoming PJM’s vice president of planning. (See related story, “New Chair Come July,” PJM Operating Committee Briefs: June 11, 2019.)

Seiler’s promotion came during a leadership shake-up with the announcement of CEO Andy Ott’s retirement, effective June 30. (See PJM CEO Andy Ott to Retire.)

PJM’s Planning Committee and Transmission Expansion Advisory Committee met June 13. | © *RTO Insider*

RTEP Poll

Aaron Berner, manager of transmission planning, said after more than six meetings with stakeholders, staff believe they are “close” on tweaks to Manual 14B that address how and when supplemental projects are removed from the Regional Transmission Expansion Plan.

Staff will email two questions to PC members regarding whether they believe the posted manual changes “are on the right track” and what further revisions still need to be made. Results will be presented at the Markets and Reliability Committee meeting June 27. (See “RTEP Removal Language on Track for June MRC Vote,” PJM PC/TEAC Briefs: May 16, 2019.)

The decision was made after stakeholders expressed confusion over how the results of the nonbinding poll would be interpreted. Some felt uncomfortable signaling approval without complete consensus on the language. A few transmission owners remain diametrically opposed to the entire effort and consider existing manual language sufficient as is, possibly skewing PJM’s perception of how willing stakeholders are to adopt changes. (See PJM Rebuffs Stakeholders on Supplemental Projects.)

PJM Developing Hybrid Fee Structure

Stakeholders will soon see PJM’s proposal for a hybrid-fee structure for transmission project cost –containment analyses, Manager of Infrastructure Coordination Mark Sims said.

Currently, the RTO charges nothing for cost-containment reviews of projects $20 million or less. Projects up to $100 million cost $5,000 to review, and larger projects incur a $30,000 fee. Sims said the new formula may include a flat fee, plus itemized study costs. Projects considered the most competitive will accumulate more itemized costs, Sims said, while those considered less viable could pay nothing additional beyond the flat fee.

“The way we are headed, we think, is to keep some flat fee structure plus detailed studied costs,” he said. “It will be somewhere between that zero and $30,000.”

Sims told the PC last month that PJM’s old tiered approach, approved in 2014, doesn’t account for the increased cost of the new comparison framework that involves an independent consultant’s review and legal and financial analyses. (See “New Fee Structure for Cost Containment Needed,” PJM PC/TEAC Briefs: May 16, 2019.)

PJM’s collected project proposal fees versus actual analysis expenses | *PJM*

Generation Interconnection Rules Endorsed

The PC endorsed revisions to Manual 14G to update PJM’s generation interconnection process and clarify the site control requirements. The changes expand rules for demand response in section 1.7 and refers on-site generators used to reduce load that participate as DR to Manuals 11 and 18 for further guidelines. The portion of such generators that inject power past the point of interconnection follow the interconnection process outlined in Manual 14G.

PJM also proposes a minimum site control term of three years — two years for projects of 20 MW or less — commencing on the first day of the new services queue in which the customer submits its request. Extensions must have been exercised by the developer when site control evidence is given to PJM if the initial term is less than the required minimum.

Despite some misgivings about site control extensions expressed during the May PC, stakeholders endorsed the revisions with only one abstention and zero objections. (See “Generation Interconnection Requests Update,” PJM PC/TEAC Briefs: May 16, 2019.)

Market Efficiency Process Enhancement Task Force Charter

The PC endorsed the updated charter for phase 3 of the Market Efficiency Process Enhancement Task Force.

Both the PC and the Markets and Reliability Committee approved phase 3 of the task force last month. Under its new charge, the group will explore possible alternatives to regional targeted market efficiency projects and consider changing the 1.25 benefit-cost threshold to measure energy benefits separately from capacity benefits, as well as other concerns raised with benefit-cost calculations. (See “Market Efficiency Process Enhancement Task Force Gets Phase 3,” PJM PC/TEAC Briefs: April 11, 2019.) The group will make recommendations to the PC by Dec. 12.

Reserve Requirement Study Assumptions

PJM’s assumptions for its reserve requirement study earned unanimous support at the PC.

The capacity benefit margin — the amount of transmission import capability reserved to capture the reliability benefit of emergency sales — modeled in the study will be 3,500 MW. PJM will also use a load forecast error factor of 1% and base load models on assessment work performed by staff and reviewed by the Resource Adequacy Analysis Subcommittee.

Staff will use the PRISM model to develop a cumulative capacity outage probability table for each week of the year except the winter peak. During the winter peak, staff will create a table based on RTO-aggregate outage data collected between 2007/08 and 2018/19 to better account for the risk caused by the large volume of concurrent outages observed during the winter peak week.

The results of this study will be used to determine the forecast pool requirement for the 2020/21, 2021/22, 2022/23 and 2023/24 delivery years. A final report will be presented to the PC in September.

Dayton, Dominion, AEP Solutions

Dayton Power & Light, Dominion Energy and American Electric Power presented proposed supplemental projects during the Transmission Expansion Advisory Committee.

Dayton said AEP will re-energize a dead section of the Stuart-Marquis 345-kV line to bypass the now-defunct Killen substation near Wrightsville, Ohio. The $200,000 project will consist of Dayton installing guy stub poles for tension on the open section of the 345-kV loop.

PJM — Dayton Power & Light and American Electric Power presented a solution to transfer power from the retired Killen substation near Wrightsville, Ohio. | *AEP*

A cheaper solution, Dayton said, would be to de-energize the Killen substation, update relay settings on the Stuart end of the line, install new tie-line meters and work with AEP to complete end-to-end relay testing for a cost of $100,000.

AEP estimates its share of the work — re-energizing the line, upgrading relay at the Don Marquis station and retiring intercompany metering — will cost approximately $1 million.

Dominion proposes installing a 3,000-amp, 50-kAIC circuit breaker to feed a requested new transformer at Chickahominy substation in Charles City County, Va., for an estimated cost of $750,000.

– Christen Smith

June 17, 2019March 20, 2024

Ending the Universal Service Model?

By Rich Heidorn Jr.

PHILADELPHIA — Has weather become so extreme that utilities should end the universal service model and stop serving at-risk locations?

It’s something that should be considered, Margaret Peloso, a partner in Vinson & Elkins’ Environmental & Natural Resources practice, told the Edison Electric Institute 2019 meeting last week.

Peloso cited the National Oceanic and Atmospheric Administration’s National Climatic Data Center, which found that between 1980 and 2018, the U.S. averaged 6.2 extreme weather events per year that resulted in $1 billion or more in damages (inflation adjusted to 2019). In 2014-18, the count of $1 billion events doubled to 12.6 per year, and in 2018 alone, there were 14 such events, including hurricanes, severe winter storms, floods and wildfires.

“We are seeing an increase in these really big, really high-dollar-value events,” Peloso said. “When you start to look at our structures for disaster relief and how we socialize disaster costs, we’re going to run out of money. And it raises the question: Who should pay for it?”

Peloso said the problem is a combination of climate change producing more severe events and more people living in high-hazard areas because of poor land use policies stemming from “misaligned” incentives. Local governments, which control zoning, benefit from an increased tax base and thus tend to be permissive and reluctant to risk litigation by denying landowners the right to build on their properties. And when there are losses from flooding or wildfires, much of the cost is externalized to the state and federal government.

In addition, research has shown that people underestimate risk and underinvest in insurance and risk mitigation, Peloso said.

“If you’re really looking at managing the risks for your company, as the CEO, I think it’s time to reconsider the universal service model and ask: Are there some areas that are just too exposed to natural hazards and risk to really be served?

“There’s actually a small utility in California … that couldn’t get general liability coverage this year because of wildfires,” Peloso said. The utility identified about 600 customers in high-risk areas. “They gave them all generators. And they said, ‘We’re going to shut your power off’” at times. (See related story, Fire Season Starts in Calif. with Power Shutoffs.)

“Let’s try to move away from this paradigm … of putting things exactly back where they [were],” she said. “Maybe that’s not where we really want people to live.”

Combining Efforts

The consequences of the current policies are stark. After a wildfire is extinguished, “we’re left with a landscape that’s going to take, in many cases, several decades to recover,” said Barnie Gyant, deputy regional forester for the U.S. Forest Service. “In some of the cases where we’ve had really large fires … it will be 100 years before we have a forest again.”

Gyant said government agencies need to work more closely with utilities and the owners of forest lands to coordinate preventive measures. In California, he noted, his department manages more than 60% of forested landscape and 20% of the landmass, giving it overlapping responsibilities with state and federal fish and wildlife agencies and utilities.

He cited the 2017 memorandum of understanding the Forest Service signed to improve coordination with Sierra Pacific Industries, which manages nearly 1.9 million acres of timberland in California and Washington. Other industrial landowners have signed the MOU since.

“Most everyone has five- or 10-year plans, but those plans are done in a vacuum. They’re not connected,” Gyant said. “When you look at the amount of money and resources those different entities have, I think we can make a difference with the fires in California. … We’re not saying we’re going to stop fires. But I do think we can be strategic in where we place our treatments to reduce the size of those fires, help protect communities and help protect infrastructure.”

Peloso agreed, saying policymakers should resist “throwing dollars at things like management per mile as opposed to trying to be smart about where the highest risks are.” Spending should be based on “where you get the most meaningful risk reduction instead of doing things [that] we think will generally reduce threats,” she said.

Resistance to Vegetation Maintenance

Former Florida Public Service Commissioner Ronald Brisé, now a government affairs consultant for Gunster, said utilities and regulators often meet resistance from local government over vegetation management efforts.

“Some cities will tell you … I’m going to sue you if you cut my trees,” he said.

Some areas that suffered outages following Hurricanes Irma and Wilms “are the same cities [where] their citizens are reacting because of vegetation management.”

IDACORP CEO Darrel Anderson, who moderated the discussion, complained of having to deal with separate sets of rules for his company’s operations in Idaho and Oregon.

In Idaho, the company can use a soil sterilant to prevent vegetation growth around its poles, a technique he said is proven to reduce the impacts of fire on electric lines. “In Oregon, we can’t do that unless we do a separate environmental study on each pole,” he said.

June 17, 2019

Calif. Fire Season Starts with Power Shutoffs

By Hudson Sangree

California’s annual wildfire season kicked off last week with high winds, a heat wave and precautionary power shutoffs by Pacific Gas and Electric to thousands of customers.

Members of the California National Guard search debris after the deadly Camp Fire, which led PG&E to institute emergency power shutdowns days later. | *California National Guard*

Southern California Edison and San Diego Gas & Electric have shut down power before when Santa Ana winds blew. (See Fire Season Becomes Blackout Time in California.)

Power shutoffs are now part of the utilities’ annual wildfire mitigation plans approved by the California Public Utilities Commission. (See California Regulators OK Utility Wildfire Plans.)

California, which last year mandated greater dependence on renewable energy sources going forward, offset the spike in demand largely with natural gas peaker plants, according to CAISO.

June 17, 2019

NY Utilities Dinged for 2018 Reliability, Safety

By Michael Kuser

The utilities being dinged for their performance include New York State Electric & Gas, Central Hudson Gas & Electric, Orange and Rockland Utilities, and National Grid’s Long Island gas operation.

Last year ranks third in customer-hours of interruption in the last 20 years, behind Hurricane Irene and Tropical Storm Lee in 2011 and Hurricane Sandy in 2012.

‘Right Kind of Oversight’

O&R’s shareholders will be required to pay $450,000 for the performance shortcoming.

Barring ESCOs?

The commission has the authority to regulate ESCOs’ access to utility distribution systems, including the power to require them to meet price caps set at utility prices.

The PSC directed that Atlantic explain why the commission should not ban it from operating in New York or take other remedial action (Case 16-M-0618).

In March 2017, the commission ordered Atlantic to cease marketing to and enrolling customers. On March 4, DPS staff identified apparent violations of the order.

Atlantic does business in the service territories of Central Hudson, Consolidated Edison, and National Grid’s KeySpan Gas East and Brooklyn Union Gas. It has 30 days to counter the DPS findings.

Sayre Farewell

The PSC currently has four members: three Democrats and one Republican.

June 16, 2019

EEI Speakers See Cause for Optimism on Climate Policy

By Rich Heidorn Jr

PHILDELPHIA — U.S. Rep. Paul Tonko (D-N.Y.) knows the kind of dramatic action needed to address climate change won’t happen with Donald Trump in the White House and Republicans in control of the Senate.

But he also doesn’t want to make the mistake that Republicans made when they nearly repealed the Affordable Care Act without having an alternative to replace it, he told the Edison Electric Institute’s 2019 conference June 10.

Rep. Paul Tonko talks climate at EEI conference — Paul Tonko | © *RTO Insider*

“I hope that [is] instructive to all of us sitting in this session of Congress: to develop a plan of attack while there isn’t the means to get it done so that when the political climate … is ripe, we’re ready to go. We have no time to waste.”

For now, he says, he chooses to avoid “rhetorical” debates over the Green New Deal and try to make progress on “what lies in the realm of possibility” under the current balance of power.

What’s that?

Tonko, chair of the House Energy and Commerce Committee’s Subcommittee on Environment and Climate Change, says he sees bicameral, bipartisan support for clean energy research; investments in EV charging infrastructure and grid modernization; workforce development; energy efficiency; and investment tax credits for energy storage.

“I don’t want to get trapped in the rhetoric of Green New Deal, no Green New Deal. l embrace many of the principles of the Green New Deal. But let’s move forward and develop science-based, evidence-based … policies that take us forward.”

Tonko wasn’t the only speaker who saw reason for optimism on climate policy, even at a time when CO₂ levels have reached the highest level in 400,000 y e ars.

Rich Powell agrees that climate change is real at EEI — Rich Powell | © *RTO Insider*

Rich Powell, executive director of ClearPath, which supports nuclear power and “small government, free market” policies to nurture clean energy innovation, said he’s seen a change in Washington recently.

“If you watch the rhetoric in D.C. for the past six months, something pretty surprising has happened,” he said, recounting his experience testifying as a Republican witness at two House hearings on climate change.

“There was generally consensus that climate change is real; that global industrial activity from … human sources is a significant contributor to that, and that the federal government ought to take significant, ambitious action beyond what it’s doing now to tackle that challenge. I think there was consensus on that issue. So now I think we’re at a space where we can begin to move from a vigorous discussion of whether there is a problem meriting federal action to a vigorous discussion about the right solutions to that problem.”

“If you really just look at the environmental provisions … [the Green New Deal is] not actually that crazy,” said Aliya Haq, director of the Natural Resources Defense Council’s Climate and Clean Energy Program. “It’s extremely ambitious. But there’s no prescription. No policy about how we get there. It’s a blank slate for how we achieve these goals.”

Sarah Ladislaw shares her perspective on climate policy at EEI — Sarah Ladislaw | © *RTO Insider*

Sarah Ladislaw, a senior fellow in the Energy and National Security Program at the Center for Strategic and International Studies, said the economic justice goals of the GND are also important.

“As we observe technological resource base changes that are taking place in the U.S., there’s actually a fair degree of commonality at the state and local level about what direction we should take,” she said. “It should broadly be lower carbon. It should definitely create jobs and economic opportunity. And it should make communities feel like they have a competitive part in this future.

“The problem, though, is that energy alone can’t sustain economic vitality at the local level. … So, one of the most attractive things about the Green New Deal is … the part of it that’s about trying to secure economic security and a greater degree of equality. … That’s the bigger political moment that we’re living in, and energy [policy] has this tendency to get carried along with those types of political sentiments.”

Bringing Clean Energy to the Developing World

Powell acknowledged setbacks, citing the loss of carbon-free nuclear generation and the expansion of coal-fired generation in the developing world.

“Right now, for a lot of the developing world, the right thing for pure [economic] development is coal. There are hundreds of new coal-fired power plants being built around the world. China has 250 more in its domestic pipeline in addition to the terawatt of … coal — average age 11 years — that are already [operating]. … They’re building at least another 100 GW around the world for their Belt and Road initiative.

EEI — Discussing the Green New Deal are from left to right: Dominion Energy CEO Thomas Farrell; U.S. Rep. Paul Tonko (D-N.Y.); Sarah Ladislaw, Center for Strategic and International Studies; Aliya Haq, NRDC; and Rich Powell, ClearPath. | © *RTO Insider*

“Too often in the past these facts — and they are brutal facts, they’re intimidating facts — have been used to shield against climate action. They’ve been used to saying, ‘Well, it doesn’t matter what we do here in the United States because all the other countries are going to make their own decisions.’ And I refuse to accept that. … Actually, we can do quite a bit about climate change.”

The solution, he said, is innovation that makes clean alternative generation as cheap as coal. “And that can be done, because we’ve done it here in the United States.”

Role for Innovation

Powell called for “technology-inclusive tax credits that cover all innovative, clean or very low-emission energy technologies and that permanently changes the incentive set for utilities … whenever they’re going to be building anything new.”

“I agree with Chairman Tonko that this is clearly a bicameral, bipartisan place where we can make a lot of progress on this issue,” he continued. “And I say that because we made a lot of progress on this issue in the last Congress,” citing passage of the 45Q Carbon Sequestration Tax Credit, the 45J N uclear P roduction T ax C redit and other legislation on nuclear and storage innovation.

“So, we think there’s a broad, robust agenda where we can get started … on climate change immediately and use the United States as a test bed for global clean energy technology that can help decarbonize the rest of the world.”

Sacrifices

Dominion Energy CEO Thomas Farrell, who moderated the EEI discussion, said it will be impossible to meet climate goals without nuclear power, citing research that electrification of transportation and other sectors could increase electric demand by 50%.

“To do that with zero-carbon [energy] — unless you can figure out a magic switch, carbon capture or something — you will need more and more and more renewables, which use enormous amounts of land,” he said. “Those of us who are actually doing this for a living are already getting very significant pushback from local jurisdictions saying, ‘I’m not going to change the zoning. … We have enough solar in our town; we don’t want any more solar.’”

NRDC’s Haq offered a cautionary note, citing research that even climate change “alarmists” are resistant to higher taxes on gasoline.

More sobering news came June 11 from Deloitte’s annual resources survey, which reported that while most businesses have increased their initiatives on sustainability, the action by residential consumers has lost momentum.

“Consumer complacency may be settling in as costs outweigh climate as a motivator in adopting new technologies and cleaner energy sources,” said Marlene Motyka, Deloitte’s U.S. and global renewable energy leader. “On the other hand, most businesses don’t perceive a choice between climate and cost. They see green energy choices as a win-win: Doing the ‘right thing’ is good for the environment and the bottom line.”

June 16, 2019

MISO Floats MTEP Time Trade-off

By Amanda Durish Cook

CARMEL, Ind. — MISO is toying with the idea of foreshortening its 2020 Transmission Expansion Plan (MTEP) process in order to maximize time spent on the 2021 cycle of transmission projects.

The RTO last week said it wants stakeholder approval to stop work on the four 15-year future scenarios used in the 2020 MTEP (requiring it to instead rely on an older version of futures) and to forego the usual planning studies in favor of smaller, specialized studies to identify projects.

MISO Planning Manager Tony Hunziker said the idea is to finish MTEP 20 work early to provide more time to completely retool the future scenarios in time for the 2021 cycle.

“Throughout this process, there’s been this building momentum and increased interest in starting MTEP 2021 futures as early as possible,” Hunziker told stakeholders at a Planning Advisory Committee meeting Wednesday.

Stakeholders asked if the 2020 plan would still contain an Appendix A, the annual list of transmission projects recommended to the Board of Directors for review and approval.

“There would certainly be an Appendix A and the usual reliability projects. This would more impact economic projects,” Hunziker said.

If MISO stops work on MTEP 20, it won’t have the usual Market Congestion Planning Study for the cycle.

“In its place, we could do a couple targeted economic studies,” Hunziker suggested. “We haven’t completely thought through everything yet. We wanted to put this out there and judge stakeholders’ interest.”

He assured stakeholders that MISO wouldn’t skip economic transmission planning for the year; it would just come in a different form.

“We’re still very committed to the economic planning process,” Hunziker said.

He said moving forward with MTEP 20 futures development would “tie staff up until mid- to late summer.”

“If we continue down the path of completing MTEP 2020 futures, it’s going to slide down the time that we can start on the 2021 futures,” Hunziker said.

Stopping work on MTEP 20 would pull staff’s focus entirely to developing MTEP 21 futures, he said. Staff have previously promised stakeholders an extensive rework of the four futures that guide the annual transmission planning process in time for 2021.

MISO had been using the same set of futures with only minor edits for the last three years to evaluate transmission projects. The RTO developed the futures in collaboration with stakeholders with long-term use in mind. (See MISO: Minimal Change to 2019 Tx Planning Futures.)

In April, MISO said it would boost renewable generation estimates in each of the four 15-year future scenarios, bumping minimum penetration levels from 15 to 35% of the generation mix to 20 to 40%. (See Renewables Outlook to Get Boost in MTEP 20 Futures.) However, MISO’s pivot puts that proposal in doubt, with Hunziker saying it could either keep or discard the larger renewable assumptions.

In halting further efforts on MTEP 20, MISO would likely begin 2021 futures discussions in July and schedule four special workshops in fall to gauge stakeholder expectations around a new set of futures.

“Either way we go, we’ll start the MTEP 2021 futures discussion early,” Hunziker said, adding that MISO would begin discussions on MTEP 21 with or without a MTEP 20 work stoppage by September. MISO usually begins futures development in January of each year for the upcoming year’s transmission planning cycle.

A Hijacking?

Some stakeholders pointed out the move would give MISO 27 months to develop futures, risking that enough time could pass for the freshly developed futures to themselves become stale. But Hunziker said the first few months would be spent on how to improve the process and settle on what new data should inform the scenarios.

Clean Grid Alliance’s Natalie McIntire asked how the move would affect MISO’s annual interregional transmission planning efforts with SPP and PJM. She said that because MISO no longer builds a joint model with its neighboring RTOs, it should keep up with grid modeling.

MISO staff said they weren’t yet sure how the new course of action would interact with next year’s interregional planning.

“I’m really surprised and concerned by this,” McIntire said. “It’s concerning that a small number of stakeholders can hijack the process,” suggesting that only a few influential members were in favor of truncating MTEP 20.

However, Xcel Energy’s Drew Siebenaler thanked MISO for proposing a “pared-down” MTEP 20. He said the move would give the RTO the time necessary to evaluate several new state and company renewable targets, new resource retirements and recent zero-carbon commitments for use in its futures.

“Who says we’re going to have that kind of clarity in five months?” consultant Roberto Paliza challenged. “I just don’t see that we’ll have a new set of futures that are radically different.”

“We’re just about done with the MTEP 20 discussion here,” McIntire said. “The whole idea that we would get rid of a big part of MTEP 20 … I don’t think that extra two months [for MTEP 21 futures] is going to be that significant.”

But Hunziker pushed back on that assertion, saying his staff don’t have time to properly facilitate both MTEP 20 futures and studies and early preparations on MTEP 21. He asked for more comments on the issue by June 28.