FOLSOM, Calif. — CAISO’s 2019 revenue requirement will be less than this year’s, despite hiring and costs associated with its planned new role as reliability coordinator for most of the West, staff members told the ISO’s Board of Governors on Thursday.
The ISO’s proposed revenue requirement for 2019 is $193.5 million — $3.7 million less than in 2019. That’s within “the tight range that the ISO has maintained over the past 13 budget cycles and beneath the FERC-approved cap of $202 million,” CFO Ryan Seghesio wrote in a memo to the board.
Total outlays will grow to $230.9 million from $217.4 million in 2018, but new revenues from the RC business as well as increased gains from the Western Energy Imbalance Market and other increased revenues will offset that spending rise by $7.2 million. A $13.5 million operating cost reserve adjustment for overcollection this year will provide an additional offset.
Operations and maintenance costs will rise by $10.5 million, April Gordon, director of financial planning and procurement, said at the board meeting. CAISO CEO Stephen Berberich added that the additional spending was primarily from “adding headcount” for the ISO’s new RC component.
The ISO is set to take over RC services from Peak Reliability for the bulk of Western Interconnection states, starting in California in July. (See RC Transition Fraught With Pitfalls, WECC Hears.)
CAISO’s telecommunication, outsourcing and contract costs also will increase in 2019 because of the RC transition, Gordon told the board.
Another cost driver is the expansion of the EIM, with new entities joining the market and increasing administrative expenses, Gordon said. Powerex and Idaho Power began trading in the EIM this year, and the Sacramento Municipal Utility District will join in April 2019, she noted. (See Idaho, Powerex Began Trading in Western EIM.)
The board unanimously passed the ISO’s 2019 budget proposal. It also heard about 2019’s policy initiatives from Greg Cook, CAISO’s director of market and infrastructure policy. A major effort involves proposed changes to the day-ahead market, including 15-minute scheduling and flexible ramping.
“We’re looking at significant enhancements to our day-ahead markets,” Cook said.
CAISO Governor Angelina Galiteva asked Cook whether ISO staff were aligning their policy initiatives with outside developments, particularly California’s adoption of a rule requiring all new homes to have rooftop solar panels starting in 2020. The state Building Standards Commission approved the rule, the first of its kind in the U.S., on Dec. 5.
“It may catch up with us before we even know what’s going on,” Galiteva said.
In addition to solar panels, many households will eventually get in-home electricity storage units, she said. “My sense is people are going to start installing storage and a lot of it,” she said.
Berberich responded, “Governor, I think you’re probably appropriately worried.” He said behind-the-meter storage, linked to home solar panels, would complicate CAISO’s forecasting.
“Storage is going to be the biggest issue for us to sort out,” the CEO said. Policies may be needed to govern the charging and discharging of storage units, including financial incentives for homeowners, he said.
“I’m not suggesting we send real-time prices to retail customers,” he said. “I’m not sure that works.”
But policymakers may need to “signal to the retail level as best we can,” he said. “Then you can shape the behavior and usage.”
The California Public Utilities Commission (CPUC) on Thursday voted to examine its rules allowing the state’s investor-owned utilities to de-energize power lines in cases of dangerous wildfire conditions “that threaten life or property.”
The practice of de-energization will get a dedicated proceeding, separate from another rulemaking effort set out in Senate Bill 901 to address utility wildfire mitigation. De-energization will be discussed in the SB901 proceeding as one of a broader set of fire prevention measures.
Carla Peterman
“We can’t not act” on the de-energization issue, Commissioner Carla Peterman said during the Thursday voting meeting, her last with the commission. De-energization “is an option we don’t want to exercise often, but we do want the option to exercise.”
Cliff Rechtschaffen
Commissioner Cliff Rechtschaffen said the issue was “worthy” of its own proceeding because de-energizing a line is a “significant event [with] significant consequences.”
“I support having this as a separate proceeding. … It is a requirement as part of the wildfire mitigation plans that the utilities now have to submit yearly that they include their de-energization protocols,” Rechtschaffen said. “[CPUC] President [Michael] Picker and I are the assigned commissioners partnered on the wildfire safety plans, and we’re committed to making sure that this proceeding is closely coordinated with that proceeding as we go forward.”
Proactive
The CPUC adopted the de-energization rules in July in response to the growing threat of wildfires throughout the state, especially in the expansive Pacific Gas and Electric and Southern California Edison service areas. Regulations around “proactive” shutoffs had previously applied only to San Diego Gas & Electric, which serves a historically highly fire-prone area.
Elizaveta Malashenko
“Since then, the topic of proactive power shutoff has reached a lot of people and has become a [hot] point of discussion,” CPUC Director of Safety and Enforcement Elizaveta Malashenko told the commission.
Among other mandates, the July rules require all IOUs to notify customers before de-energizing facilities and report to the commission after the fact (Res ERSB-8).
But Malashenko noted that industry stakeholders and members of the public have raised “a range of concerns” about the program, and that utilities are increasingly “proactively de-energizing” their lines. (See Fire Season Becomes Blackout Time in California.)
“In my mind, the type of issues that would come up in [this] rulemaking as related to de-energization is how much the utilities should be using that as a tool, as opposed to mitigating wildfires in other ways, such as introducing coated conductors or undergrounding lines, or increasing their ability to detect faults faster, and things like that,” she said.
A CPUC staff report on the new rulemaking indicates the proceeding will focus on:
Examining conditions under which planned de‑energization is practiced;
Developing best practices and ensuring an orderly and effective set of criteria for evaluating de‑energization programs;
Ensuring electric utilities coordinate with state and local level first responders, and align their systems with the Standardized Emergency Management System framework;
Reducing the impact of de‑energization on vulnerable populations;
Examining ways to reduce the need for de‑energization;
Ensuring effective notice to affected stakeholders of possible de‑energization and follow‑up notice of actual de‑energization; and
Ensuring consistency in notices of and reporting of de-energization events.
Digitize the Landscape
During the meeting, Picker emphasized the importance of learning from SDG&E’s experience from de-energization — without leaning too heavily on it.
Michael Picker
“Utilities have always de-energized,” Picker said. “We have so far required them to plan a little ahead and to provide notification, but what could we learn from San Diego? What should be applied elsewhere? And how do we know what will work in other parts of the state?”
Picker pointed out that in order to avoid de-energizing lines, SDG&E “digitized the landscape” in its service territory.
“They put sensors in a number of places,” he continued. “They put weather monitors, wind monitors, moisture monitors and cameras in places you wouldn’t expect to see that. They began to collect information. They began to look carefully at very granular conditions in specific parts of their service territory at a much finer level than has ever been modeled before.”
Picker said SDG&E over time developed “a much finer sense of where and when to de-energize, and what were the consequences.” But he also acknowledged that SDG&E has a much smaller service territory than either PG&E and SCE.
“When you begin to look at the service territories of the other regulated utilities … we may be able to expedite their processes, but they’re still going to have to go through that data-monitoring, data collection, analysis, modeling and eventual testing process,” Picker said.
“I want to be honest about what we’ll be able to achieve. I don’t think we’ll have a perfect set of rules right away.”
FOLSOM, Calif. — CAISO’s efforts to rein in congestion revenue rights insufficiencies seemed to show progress this summer and early fall but fell short in the last months of 2018, the ISO reported Tuesday during its quarterly Market Performance and Planning Forum.
Historically CRR revenues have been inadequate to meet payouts, Guillermo Bautista Alderete, CAISO’s director of market analysis and forecasting, told meeting attendees at ISO headquarters.
That changed in the middle of this year because of high levels of summer congestion, he said.
“From July to October we actually flipped the condition, especially in July and August,” when there were significant surpluses, Bautista Alderete said. A graph he displayed showed a surplus in July of about $15 million and close to $40 million in August, which amounted to about 140% of revenue adequacy. Those figures did not include auction revenues.
The good news turned grim in November, when “we had insufficiency in the range of 80%,” he said. “Even if we account for auction revenues, we were still marginally short.”
The chronic shortfall in CRR revenues, leaving ratepayers footing the bill, has been an ongoing problem for CAISO. This year the ISO sought FERC’s approval for changes it hoped would help in 2019, but the commission was loath to give it everything it wanted.
In September, FERC rejected a CAISO plan to eliminate full funding of CRRs and instead scale payouts to align with revenue collected through the day-ahead market and congestion charges. (See FERC Rejects CAISO Congestion Revenue Scaling Plan.)
The congestion revenue rights market saw an inadequacy in November compared to surpluses this summer, CAISO said. | CAISO
CAISO noted in its filing that CRR revenue shortfalls have continued into this year, and it urged the commission to quickly approve the revised plan to relieve ratepayers from paying costs for fully funding CRRs in 2019.
The ISO’s Department of Market Monitoring has estimated that CRR revenue shortfalls, which are allocated based on power consumption, cost California ratepayers about $100 million a year.
“We agree with CAISO that the proposal reasonably distributes the burden resulting from congestion revenue insufficiency and will help improve the revenue insufficiency and auction revenue shortfall,” FERC said. “Rather than relying solely on [load-serving entities] to make whole CRR holders in the event those obligations are revenue insufficient, CAISO’s proposal distributes the burden to all CRR holders.”
EIM prices were stable in the fourth quarter after spikes over the summer. | CAISO
Other results reported at Tuesday’s meeting included a stabilization in Western Energy Imbalance Market prices after a big spike at the end of July caused by high summer demand.
“As we have passed those summer months, the prices are generally stable,” Rahul Kalaskar, CAISO manager of market validation analysis, told those gathered and on the phone.
FERC on Monday denied SPP’s request for waivers from regulations guiding the confidential treatment of information in its explanation of how it allocated costs related to a NERC fine, the amount of which has not been publicly disclosed because of grid security concerns (ER19-97).
SPP filed the Section 205 request in October with an explanation of its allocation of costs from a NERC fine for violating reliability standards. The heavily redacted public version of the request shows the RTO asked for waivers from the requirement to include a protective agreement and from the regulations authorizing release of the filing’s confidential version to entities signing a nondisclosure agreement. SPP claimed that disclosing the information could jeopardize its system’s security.
But FERC ruled that “SPP has neither adequately supported its concerns nor justified the adverse effect that its waiver request would have on participants in this proceeding.” As the cost allocation plan did not include a proposed protective agreement, the commission dismissed it. It did so without prejudice, meaning SPP can refile its proposal for covering the penalty without the waiver request.
FERC noted intervenors would be willing to sign a protective agreement to review SPP’s filing and evaluate its proposed cost allocation.
SPP’s headquarters in Little Rock, Ark. | WER Architects
In the cost allocation filing, SPP said it paid the penalty costs using surplus funds, although a Tariff provision allows the recovery of such costs by direct assignment or cost allocations to members or market participants. The RTO’s Board of Directors approved offsetting the costs with employee compensation funds for 2018, an approach SPP said it adopted from FERC Order 693, which it said suggested RTOs and ISOs could tie employee compensation to compliance with reliability standards as a means of reducing repeat incurrences of penalties. The order also declined to provide grid operators blanket authority to recover penalty costs from members on a generic basis.
Under the board’s recommendation, the reduction in compensation would be reflected as a surplus in the administrative fee’s true-up for 2018, which would reduce the fee for 2019.
The West Texas Municipal Power Agency (WTMPA), created by the cities of Lubbock, Brownfield, Floydada and Tulia to increase their negotiating strength, intervened in the docket. While it did not protest the cost allocation plan or waiver request, it urged FERC to “strictly and expressly limit such findings to this case” if it approved them. The agency asked that interested parties be allowed access to information about the penalties and cost allocation, contending that it would be otherwise impossible for ratepayers to determine whether the penalty’s allocation was just, reasonable and not unduly discriminatory.
FERC regulations provide that any participant in a proceeding can make a written request to the filer for a copy of the document’s complete, nonpublic version. The request must include a signed copy of the filer’s protective agreement and a statement of the person’s “right to party or participant status or a copy of their motion to intervene or notice of intervention.”
SPP members Evergy, Oklahoma Gas & Electric and Western Farmers Electric Cooperative also intervened in the docket.
FERC on Tuesday ordered a closer look into whether We Energies accurately estimated customer savings stemming from the retirement of the Pleasant Prairie coal plant in southeastern Wisconsin.
The commission’s Dec. 11 ruling accepted, then suspended, We Energies subsidiary Wisconsin Electric Power Co.’s new wholesale tariff that includes the remaining costs on the plant, setting the rate for hearing and settlement judge procedures over the company’s claims of ratepayer savings related to the shutdown (ER19-103).
We Energies in April permanently closed the 1,190-MW coal plant, which entered service in 1980.
Pleasant Prairie Power Plant | We Energies
At retirement, Pleasant Prairie had an unamortized plant balance of approximately $665 million, which We Energies sought to amortize over about 23 years through an adjustment to its rate base. The company contended the recovery is just and reasonable, citing FERC’s 1996 decision to allow Yankee Atomic Electric Co. to recover from ratepayers 100% of its remaining unamortized investment in its nuclear plant after a study showed the plant’s operating costs exceeded the value of the its energy output.
Between 2003 and 2007, We Energies invested $365 million worth of capital, environmental and reliability investments into Pleasant Prairie, all of which were approved by the Public Service Commission of Wisconsin.
“Although Pleasant Prairie has reliably served Wisconsin Electric’s customers for nearly 38 years, its value to customers began to decrease significantly after 2008 due to a significant loss of industrial load following the recession in 2007-2008 and improvements in energy efficiency; declining energy prices in MISO as a result of increased competition from natural gas and renewable energy resources; and a corresponding reduction in Pleasant Prairie’s dispatch in MISO markets,” the company told FERC.
We Energies says Pleasant Prairie’s retirement will save retail and wholesale customers anywhere from $2 billion to $3.2 billion.
But wholesale customer Great Lakes Utilities challenged the customer savings estimates, arguing that We Energies’ assumptions of a hypothetical carbon tax imposed in 2028 and other pricey environmental regulations on the coal plant are “not sufficiently supported.”
The commission agreed that the cost-savings assumptions could use more evaluation.
FERC said it “cannot determine on the record before us whether the third prong of the test set forth in Yankee Atomic has been satisfied such that there will be substantial savings for customers as a result of Pleasant Prairie’s retirement.”
In the Yankee Atomic decision, FERC said a 100% recovery of a prematurely retired plant’s unamortized balance is warranted when three criteria are met: the investment and retirement decisions are prudent, the plant has already provided years of beneficial service to customers and the retirement results in “substantial cost savings to customers.”
While FERC said We Energies demonstrated prudent investment and retirement decisions, and that Pleasant Prairie was beneficial to customers over its nearly four decades of reliable operation, it could not definitively answer without further proceedings whether the company would achieve substantial customer cost savings from retirement of the plant.
CARMEL, Ind. — MISO officials are still hashing out how they can best model and analyze energy storage-as-transmission in the RTO’s transmission planning process.
During a Dec. 10 Reliability Subcommittee meeting, MISO Senior Manager of Expansion Planning Edin Habibovic said planning for storage-as-transmission boils down to four key modeling factors:
Determining the voltage, thermal or stability need;
Asking if storage is the most effective, efficient and economical solution;
Examining what level of megawatt or mega volt amps of injection is needed to resolve the issue; and
Investigating how long the reliability issue usually lasts.
Habibovic said MISO also must study how frequently a storage asset would have to operate to resolve a reliability issue and how that cycling may impact the operational life of the asset. He also said MISO will need to look into seasonal load levels to estimate how often the asset may be dispatched in scenarios under the RTO’s annual Transmission Expansion Plan (MTEP).
Storage solutions would also be evaluated to make sure charging and discharging don’t cause harm either to the MISO transmission system or to generation projects in the definitive planning phase in the interconnection queue, Habibovic said.
“Just like any other reliability project, it can’t solve one problem and cause another,” he said.
But storage could be dispatched to minimize transmission system upgrade needs from generation projects in the definitive planning phase of the interconnection queue, he said. The result would be more flexibility in modeling the definitive planning phase.
WPPI Energy’s Steve Leovy asked if MISO would employ a storage-as-a-transmission-asset (SATA) study process on solutions submitted for MTEP 19. Habibovic said MISO would study storage projects and might provide additional MISO assessments and discussions about the study results and feasibility of such projects. MISO already has at least one proposed storage project lined up for study under Appendix A of MTEP 19.
So far, MISO is only proposing a model for storage to act as a transmission reliability solution, solving thermal, voltage or stability issues. The RTO is leaving more complex SATA issues for later rules. (See Few Clear Lines in MISO Storage as Tx Plan.)
MISO is accepting stakeholder comment on the challenges and benefits of incorporating transmission-level storage in reliability planning through Jan. 7.
Inverter Projects to Prove Stability
MISO has added an option for owners of inverter-based generation to prove the system won’t suffer degraded reliability because of their projects.
In October the RTO said it was mulling requiring owners of inverter-based resources to supply their short-circuit ratios at the point of interconnection before completing an application to enter the queue. (See MISO Moving to Head off Inverter-based Instability.)
Interconnection customers with an inverter-based project can now demonstrate a stable interconnection later in the queue process using one of two demonstration methods.
According to MISO interconnection engineer Warren Hess, project owners can either submit an Electromagnetic Transients Program (EMTP) study report confirming stable operation or, by the first decision point about 120 days into the queue, submit a short-circuit ratio at the point of interconnection and a manufacturer’s letter stating the equipment operates reliably.
As with the first proposal, any project owner unable to prove stable operation must either add equipment to raise the short-circuit ratio or reduce the size of the project.
MISO is accepting another round of feedback on the proposal through Jan. 2.
NYISO said Tuesday it will have adequate capacity on hand to meet its forecasted peak demand of 24,269 MW for the 2018/19 winter season, well under last winter’s peak of 25,081 MW.
The ISO expects capacity resources, including imports and demand response, to total 43,943 MW this winter, ISO Vice President of Market Operations Emilie Nelson said in a review of the winter outlook.
Installed generation amounts to 41,539 MW, while the ISO has acquired external capacity of 1,519 MW for the winter. Projected demand response resources equal 884 MW, Nelson said.
NYISO long-term winter forecast for 2018 to 2025, including transmission and distribution losses. The low and high forecasts are at the 10th and 90th percentiles for extreme weather conditions, respectively. | NYISO
The ISO forecasts a capacity margin of 11,436 MW based on a 50/50 winter peak forecast with average winter weather conditions consisting of composite statewide temperatures of 15 degrees F. More extreme temperatures in the model (approximately 5 degrees statewide) result in a higher forecasted 90/10 peak load of 25,884 MW, with marginal capacity of 9,821 MW.
“Last winter’s peak [on Jan. 5] occurred during a two-week cold snap, and the all-time winter peak of 25,738 MW occurred in January 2014, during what was called the polar vortex,” Nelson said.
In response to the harsh winter five years ago, “we have fine-tuned many of the things we do in advance of the winter season,” Nelson said. The ISO enhanced its winter reliability planning by providing stronger incentives for generators to secure fuel for winter peak demand needs and improved its monitoring of the natural gas system and checking of generator fuel inventories.
“In preparing for the winter 2018/19, we start by conducting a generator fuel survey … and also we like to understand any arrangements they have in place for replacement fuel,” Nelson said. “This is particularly important in New York, because so many of our generators are located along waterways that allow replenishment of fuel storage through the winter.”
When considering resupply, the focus is on oil, which is typically used as a backup fuel in New York, prompting the ISO to differentiate between resources with fuel tanks that will be drawn down throughout the season and those that can resupply from barges as needed, Nelson said.
In the spirit of testing for extremes, the ISO forecast models a loss of natural gas scenario, which is less about replenishment than demand coming from both homes and power generators, she said.
FERC on Monday denied SPP’s request for waivers from regulations guiding the confidential treatment of information in its explanation of how it allocated costs related to a NERC fine, the amount of which has not been publicly disclosed because of grid security concerns (ER19-97).
SPP filed the Section 205 request in October with an explanation of its allocation of costs associated with a NERC fine for alleged violations of reliability standards. The heavily redacted public version of the request shows the RTO asked for waivers from the requirement to include a protective agreement and from the regulations authorizing release of the filing’s confidential version to entities signing a nondisclosure agreement. SPP claimed that disclosing the information could jeopardize its system’s security.
But FERC ruled that “SPP has neither adequately supported its concerns nor justified the adverse effect that its waiver request would have on participants in this proceeding.” As the cost allocation plan did not include a proposed protective agreement, the commission dismissed it. It did so without prejudice, meaning it did not rule on SPP’s approach to covering the penalty cost.
FERC noted intervenors would be willing to sign a protective agreement to review SPP’s filing and evaluate its proposed cost allocation.
SPP’s headquarters in Little Rock, Ark. | WER Architects
In the cost allocation filing, SPP said it paid the penalty costs using surplus funds, although a Tariff provision allows the recovery of such costs by direct assignment or cost allocations to members or market participants. The RTO’s Board of Directors approved offsetting the costs with employee compensation funds for 2018, an approach SPP said it adopted from FERC Order 693, which it said suggested RTOs and ISOs could tie employee compensation to compliance with reliability standards as a means of reducing repeat incurrences of penalties. The order also declined to provide grid operators blanket authority to recover penalty costs from members on a generic basis.
Under the board’s recommendation, the reduction in compensation would be reflected as a surplus in the administrative fee’s true-up for 2018, which would reduce the fee for 2019.
The West Texas Municipal Power Agency (WTMPA), created by the cities of Lubbock, Brownfield, Floydada and Tulia to increase their negotiating strength, intervened in the docket. While it did not protest the cost allocation plan or waiver request, it urged FERC to “strictly and expressly limit such findings to this case” if it approved them. The agency asked that interested parties be allowed access to information about the penalties and cost allocation, contending that it would be otherwise impossible for ratepayers to determine whether the penalty’s allocation was just, reasonable and not unduly discriminatory.
FERC regulations provide that any participant in a proceeding — or that has filed a motion to intervene or notice of intervention — can make a written request to the filer for a copy of the document’s complete, nonpublic version. The request must include a signed copy of the filer’s protective agreement and a statement of the person’s “right to party or participant status or a copy of their motion to intervene or notice of intervention.”
SPP members Evergy, Oklahoma Gas & Electric and Western Farmers Electric Cooperative also intervened in the docket.
Commissioner Kevin McIntyre, who has been battling health issues, did not vote on the order.
CARMEL, Ind. — Several MISO stakeholders are criticizing Tariff filings the RTO plans to make by the end of the year to free up an additional 5 to 10 GW of capacity in time for the spring outage season.
The discord played out in meetings as part of MISO Board Week and during a special conference call of the Reliability Subcommittee on Dec. 7.
At the Dec. 5 Advisory Committee meeting, Reliability Subcommittee Vice Chair Ray McCausland, of Ameren, said MISO worked unusually fast on the short-term resource availability and need filing.
“For those used to MISO running at the lightning pace of a glacier, MISO has flown through this,” he joked. McCausland also acknowledged stakeholder concerns about the pace of the filing. He said a few have voiced skepticism that the new load-modifying resource (LMR) treatment and outage coordination can in fact free up the capacity the RTO has cited as the reason for the Tariff filing.
Earlier this month, several stakeholders criticized MISO’s plan to require more testing of and data from certain LMRs and impose stricter notification times for planned outages. (See Stakeholders Critical of MISO Resource Availability Filing.)
Because of stakeholder pushback, the RTO said later in the Dec. 7 conference call that its originally planned Tariff filing will now become three separate Tariff filings: one each for demand response capability testing, LMR seasonal availability documentation and a new 120-day notice time for planned outages.
Kevin Murray, representing the Coalition of MISO Transmission Customers and the Eligible End-User Customers sector, called the original filing “controversial.” He said a full filing runs the risk of garnering so many protests that FERC will refuse to act on it, especially considering a D.C. Circuit Court of Appeals ruling last year that the commission overstepped its authority in its approval of PJM revisions to its minimum offer price rule. (See PJM MOPR Order Reversed; FERC Overstepped, Court Says.)
“I’m here to express my profound disappointment that we’re here today,” Murray said during the Advisory Committee meeting. He added that the RTO should do something about its lack of fast-start resources as winter approaches, particularly in MISO South.
Coalition of Midwest Power Producers CEO Mark Volpe said MISO’s proposed limits on outages may be punitive to generation owners. “We’re going way too fast here on something this serious,” Volpe said.
Jim Dauphinais, a consultant with Brubaker and Associates representing end-use customers, said the filing seeks to unnaturally force improved availability.
Imagining Blackouts
Board members who heard the discord urged stakeholders to work through their differences with MISO.
Director Baljit Dail asked stakeholders to imagine how they would respond today if the RTO experienced rolling blackouts. “How would you approach this problem differently? How would you change your answer?” he asked.
“I appreciate that no one wants rolling blackouts in the press … but I think there’s an unintended consequence here,” Madison Gas and Electric’s Megan Wisersky said. She said more rules for LMRs would drive some out of the market, resulting in reduced resources.
“I urge caution here,” she said.
However, representatives of the State Regulatory Authorities sector said they were supportive of a filing. Minnesota Public Utilities Commissioner Matt Schuerger said stakeholders cannot deny the urgency of needing changes.
Speaking at a Dec. 4 meeting of the board’s Markets Committee, MISO Executive Director of System Operations Renuka Chatterjee said “availability of resources is the key to avoiding real-time shortages.”
“We’re seeing an increase in unavailable megawatts for each of the last three winters,” Chatterjee told the committee.
Almost 12 GW (about 9%) of MISO resources are classified as LMRs, accessible only as part of emergency load management. The RTO had not called on LMRs for a decade after a localized Wisconsin emergency in February 2007 but has relied on them three times since 2017, most recently in MISO South in mid-September. Independent Market Monitor staffer Michael Wander said most MISO South LMRs were unable to respond in time during the September event because the units have long start-up times.
MISO has seen a 4.6-GW decrease in installed capacity from existing resources since 2017.
“We’ve experienced retirements of what we considered excess capacity,” RTO President Clair Moeller explained to board members.
Dail said the situation underscores the need for MISO to be able to better supervise planned outages. “This just looks like it’s going to get more complicated as we go forward,” he said.
Responding to a question from Director Barbara Krumsiek about whether MISO’s neighbors face similar availability challenges, Moeller said SPP has a similar experience of growing renewable resources paired with conventional generation retirements.
Seeking Clarity
MISO discussed a few recent additions to the possible multiple filings during the Dec. 7 conference call.
Staff said they propose to issue scheduling instructions up to 12 hours in advance based on resource lead times but would not actually call on the resource until two hours before it’s needed. Demand response resources that acknowledge scheduling instructions but are not ultimately called would nevertheless receive credit toward the five deployments per year that would be required of LMRs.
DR would also prove demand reduction capability by “performing to its requirements when called upon during the prior planning year” in addition to MISO’s original proposal of participating in a real power test. Testing of DR resources would begin for resource qualification in the 2020/21 planning year.
But stakeholders said the new demonstration option was vague, with some asking about the minimum number of performance hours and how MISO would account for performance when it calls up partial demand-reducing output.
MISO Director of Resource Adequacy Coordination Laura Rauch said the RTO’s testing requirements would require full output of a DR resource for at least an hour.
Xcel Energy’s Kari Hassler asked what would happen if a properly scheduled planned outage takes more time to complete under the original scope of work and an emergency event occurs during the outage extension.
Rauch said the outage extension would likely fall under MISO’s “high-risk” determination, and the outage could be rebranded as a forced outage for the time it overlaps a maximum generation emergency, which would count against a resource’s accreditation.
However, she also said MISO is still working through revisions of its proposed filings and may choose to delay the outage coordination piece until January, still targeting changes by the spring outage season. She said the RTO will accept another round of feedback through the end of the week. MISO is planning to post an updated version of its filing or filings by Wednesday and will use stakeholder feedback in final revisions.
[Editor’s Note: An earlier version of this story incorrectly identified Jim Dauphinais’ affiliation and misnamed the Coalition of MISO Transmission Customers.]
WASHINGTON — When it comes to the smart grid, count consumer advocate David Springe as a nonbeliever.
He began his talk at gridCONNEXT 2018 last week with a vendor’s definition: “Smart grid is the convergence of information and operational technologies applied to the electric grid, allowing sustainable options to customers and improved security, reliability and efficiency to utilities.”
Then Springe gave the consumer advocate’s definition: “Smart grid employs new technologies that are more expensive and less secure than the current technologies to give pricing flexibility that customers don’t want, to communicate with small and smart appliances customers don’t own.”
Although he wrote that definition eight years ago, Springe, executive director of the National Association of State Utility Consumer Advocates (NASUCA), said it still applies. “The vast majority of customers don’t interact with their meters; [they] aren’t on time-of-use rates,” he said.
Customers, he said, have seen little benefit from replacing $100 analog meters that were depreciated over 30 years with digital meters that cost twice as much and are depreciated over only five years. “Frankly, all that meter infrastructure was pretty much used to read meters once a month. We spent a lot of money. If we did it under the premises of providing something that consumers wanted, we failed.
“There’s a million great ideas out there that only need somebody’s money to make it happen,” he continued. Consumer advocates “see this at the ground level where all these grand ideas that are being shared in this room show up on the utility balance sheet, show up on the utility bill.”
Instead of lusting after new technology, Springe said, utilities and regulators should focus on increasing efficiency and reducing costs through outsourcing and cloud computing. “Why does every utility have its own communication system? Meter system? Back office systems?” he asked.
Springe said consumers are seeing reduced generation costs swamped by increases in distribution and transmission charges.
That’s due in part to antiquated cost-of-service ratemaking that is preventing innovations that could save consumers money, said former FERC Chair Jon Wellinghoff, who shared a panel with Springe.
Wellinghoff is much more bullish on new technology, such as transmission devices that can add capacity without reconductoring or adding new substations.
He cited a project that Pacific Gas and Electric is building in West Oakland, which will combine distribution-level storage, behind-the-meter controls for demand response and distributed generation, and the aggregation of rooftop solar to address reliability concerns over the retirement of a Dynegy generator. The $100 million project won out over a $300 million proposal to add a new 230-kV transmission line.
That was good news for consumers, but not for PG&E, which won’t get to earn a return on the more expensive transmission investment, said Wellinghoff, who served for seven years as Nevada’s consumer advocate before joining FERC.
“We have to reconcile this somehow … so that utilities will have … incentives aligned with what we all would like to have for consumers, which is [an] efficient, cost-effective system that is clean,” he said.
Narrow Window for Energy Legislation in 2019
The conference also featured discussions on prospects for energy legislation in the new Congress.
The new Democratic House majority will have only a few months to work with Senate Republicans and President Trump on energy policy before the 2020 presidential election intrudes, said Jason Hartke, president of the Alliance to Save Energy.
Hartke said likely Speaker Nancy Pelosi (D-Calif.) will face a challenge managing the tension between “a whole lot of excited new members who want to do things like build the Green New Deal versus [veteran Rep. Paul] Tonko [D-N.Y.] talking about singles and doubles.” (See Optimism Rising on EVs as Sales Hit 1 Million Mark.)
Hartke said a bipartisan infrastructure bill that includes spending for grid modernization and electric vehicle charging is “the one opportunity for a home run.” But he said the fate of such legislation hinges on whether Trump engages and can win the support of the Republican-controlled Senate.
“We’re working hard now for a tax extenders package that makes sense. Right now, the House package is looking backwards, so it’s retroactive [extending already expired tax breaks]. We want it to look forward, so you could actually change behavior.”
Attorney Andrew Shaw, senior managing associate with Dentons, said new members who campaigned on bold action on climate change will be motivated to support smaller changes so they can take credit for legislative accomplishments.
“Something like an infrastructure bill — which faces a lot of hurdles undoubtedly — is a vehicle that you could maybe get some of those wins, because everybody wants to be able to go back home and be able to talk about what they’re doing,” Shaw said.
“It’s not a given that energy’s going to be in the mix” in an infrastructure bill,” said Amit Ronen, deputy chief of staff to Sen. Maria Cantwell (D-Wash.) in a separate discussion. “It’s something we’ve got to educate members … on.”
Ronen noted that Cantwell, the ranking member of the Energy and Natural Resources Committee, cosponsored the $7,500 passenger EV tax credit with Orrin Hatch (R-Utah).
“So now we’re looking at, is there a role for the government in incentivizing electrification of other transportation? We’re talking about boats, trucks, buses, even planes, which two years ago I wouldn’t have even thought … was possible.”
Shaw said there has been some progress in the last six years in building consensus on climate change, noting the introduction last month of a bipartisan bill that would set a carbon tax beginning at $15 per metric ton in 2019. The bill is based on the carbon dividend proposal offered last year by Republican party elders James A. Baker III and George P. Schultz. (See Lott, Breaux Join Push for Baker-Schultz CO2 Dividend Plan.)
“Unfortunately, in the House we did lose some more moderate [Republicans] who do believe in climate change science and were willing to engage,” Shaw acknowledged.
Companies are “being forced to act [on decarbonization] because government has failed us,” said Amy Davidsen, North America executive director for the Climate Group, which manages RE100, a collaborative of more than 150 businesses that have committed to using 100% renewable electricity.
Bill Weihl, former Google “green energy czar,” predicted RE 100 companies will grow to more than 300 in the next several years.
Weihl said the big innovation the last few years has been less about technology and more about development of new products, such as the two dozen “green” tariffs in 15 states.
But Hans Royal, director of strategic renewables for Schneider Electric, said many of the tariffs are too expensive or put too much risk on corporate buyers to be effective.
Electrifying Bus Transit
The two-day conference also provided an update on accelerating efforts to electrify city bus fleets.
“The orders for battery electric [buses] are ramping up really rapidly,” said Lisa Jerram, director of bus, paratransit and surface transit for the American Public Transportation Association.
Jerram said only about half of city transit buses are now pure diesel, down from 90% 10 years ago.
Compressed natural gas powers about 25% of fleets now, with hybrid diesel-electrics comprising about 20%, according to Jerram and Ryan Popple, CEO of electric bus maker Proterra.
But Jerram said many transit agencies need utilities’ assistance to make the transition. “They don’t understand utility systems that well; they don’t understand rate structures,” she said. Utilities also can help bus operators manage the logistics of charging in their depots and on routes, she said.
Popple said his company has received orders from 39 states. “If you add up the cities that have already mandated that they’re going electric — that includes … cities like Seattle and New York City — 10,000 of the 70,000 buses on the road are already politically mandated to go electric. So it’s coming. And the things that we figure out on the bus side you’ll need to them again at larger scale in school bus and truck [conversions].”
Europe’s Challenges
The conference heard a keynote address from Laurent Schmitt, secretary-general of the European Network of Transmission System Operators (ENTSO-E), which he described as “kind of the FERC of Europe.” The organization has 43 transmission system operators in 36 countries.
Schmitt said although the Nordic countries are blessed with offshore wind, it is a challenge to move the power to load centers. “Our system does not get planned as efficiently as what we would like, and it’s getting very hard to get transmission lines [sited] in Europe, especially getting people from certain states understanding that they have to build the line for the sake of other Europeans,” he said.
Schmitt said Europe does not use LMPs, “but I think we will have to go into a similar model in the future” to address scarce grid capacity.
Europe also faces challenges as renewables replace traditional generation, he said. Fossil fuels (coal, gas, oil, mixed fuels and peat) were responsible for 43% of Europe’s energy production in 2017, with renewables adding 33% and nuclear 22%.
“Are we going to be able to maintain frequency … when we have no rotating mass?” he asked.
