MISO Bends to Renewable Realities in ’20, ’21

In 2020 MISO promised a turnaround in its approach to a changing resource mix and clean energy targets by states in its footprint.

As the ‘20s roared in, the grid operator managed several intricate discussions in remote format, among them redefined reliability standards, a capacity market subdivided by season, and the launch of its first long-term transmission planning effort in a decade.

President Clair Moeller said the RTO is emerging from being “a victim of circumstance” of future renewable realities.

“We haven’t spent a lot of time trying to anticipate. That changes now,” Moeller said during the December board meeting.

‘Not Farewell, But Good Riddance’

“If we could have gone back 12 months and say that we’d be able to accomplish all this, we’d all be happy,” MISO CEO John Bear said during MISO’s annual members meeting in December. “We can choose to see 2020 as a time of resilience that we’d never want to repeat, or we can view it as preparation for changes. I think we’ll view it as the latter.”

“This year MISO wrote the playbook on how to safely and reliably serve load in uncertain times,” Transmission Owners representative Stacie Hebert said.

MISO control room | MISO

With pandemic-induced lockdowns and bans on in-person gatherings, MISO load bottomed out to about 10% below historically normal levels from March through May. The coronavirus’ impact decreased during summer and early fall, but with the contagion spreading unabated, load now tracks about 5% below normal.

“This is definitely not a year-over-year situation,” said MISO Executive Director of Market Operations Shawn McFarlane in May.

Through the upheaval of 2020, MISO supervised 72,000 miles of high-voltage transmission and about 184 GW of generating resources.

Hebert joked all MISO members were ready to say “not farewell, but good riddance” to 2020.

MISO rolled out a live, informal stakeholder polling feature during some online committee meetings.

“When we’re in person, it’s a lot easier to read body language and get a sense of the room,” said WEC Energy Group’s Chris Plante, chair of the Resource Adequacy Subcommittee, in August. “Are people frowning? Are they smiling? Are half of them out in hallway?”

Long-Range Transmission in the Works

MISO executives said the footprint cannot afford to wait on transmission investment and risk the system buckling under the pressures of interconnecting renewable resources. In July, it announced its first long-term transmission planning effort since 2011.

“If you love renewables, then you have to love transmission. Although no one wants to have transmission built next to them, it must happen,” Bear said during the board meeting in December. He added that MISO planners would try their best to leverage and expand existing transmission corridors. (See MISO Prepares Members for Pricey Transmission Expansion.)

“In case no one has noticed, we’re using words like ‘urgent’ and ‘imperative,’” Moeller said of the need for new transmission to achieve clean-energy goals.

MISO’s 2005 generation mix compared to 2019 | MISO

He noted Entergy is the latest MISO utility to pledge carbon neutrality by 2050.

“It’s important to understand that the whole of the footprint is making changes even though they’re not identically the same. This is going to take a team sport,” Moeller told the MISO Board of Directors.

He said planning long-range transmission is going to be about “dollar flow, not power flow,” predicting that determining new transmission’s cost allocation will be thorny.

It’s been a decade since the RTO last explored how the costs of long-term transmission projects should be shared.

The Organization of MISO States has convened a special cost-allocation committee to draw up principles on how MISO should approach sharing costs of long-term projects.

OMS has heard from staff about the MISO’s history of transmission project classification and cost allocation, from FERC Order 2003 — which standardized generator interconnection procedures —to this summer’s cost-allocation overhaul, which lowered the voltage threshold for market efficiency projects from 345 kV to 230 kV, added two new benefit metrics and eliminated a previous 20% postage stamp allocation. (See MISO Cost Allocation Plan Wins OK on 3rd Round.)

Indiana Utility Regulatory Commissioner Sarah Freeman said the OMS will be ready with suggestions on cost allocations in the first quarter of 2021.

Several regulators have asked that MISO take care to ensure that beneficiaries of new lines pay for them. Some have suggested allocating some GI upgrades to load and some backbone transmission projects to generation. Others have kicked around the prospect of allocating projects on a subregional basis because of the footprint’s hourglass geographic shape.

Staff have said the new cost-sharing method could see the RTO approving more transmission projects.

On the other hand, MISO and SPP again failed to identify any beneficial cross-border transmission projects after a fourth interregional study this year.

The grid operators have somewhat assuaged stakeholders by announcing a new joint study targeting the RTO’s GI challenges. (See MISO, SPP Heads Present Unified Front on Seams.)

Unparalleled Storm Season

The U.S. experienced 30 named tropical storms in 2020, three of which — Hurricanes Laura, Delta and Zeta — pummeled MISO’s Gulf of Mexico states.

“I hope everybody got to learn their Greek alphabet this year,” J.T. Smith, MISO’s director of operations planning, said wryly during a Markets Committee meeting in December.

August saw MISO’s first-ever load shedding orders as a result of Hurricane Laura’s landfall in Louisiana. Following landfall, the RTO declared local conservative operations for a month to support restoration efforts. (See MISO Enacts Rolling Blackouts in Laura Aftermath.)

Hurricane Laura’s path and transmission destruction | MISO

“She took out every electrical element in her path. … We had thousands of structures down,” Smith said of the destruction. He defended MISO’s decision to shed load. “It’s something we’d do again,” he said. “We knew load was going to come offline in southwest Louisiana.”

MISO said Laura was the strongest storm to hit the Louisiana coast since 1856. The RTO’s director of grid operations, Durgesh Manjure, said the hurricane produced “drastic images of towers twisted and bent,” but Entergy acted quickly to reenergize a 500 kV line.

“This is the first time in MISO’s history that we directed a load-shed event,” Manjure told the Midwest Reliability Organization in November. “I hope this is a once-in-a-lifetime or once-in-a-career event.”

He said the storm made it clear that MISO’s market rules and pricing are not “geared” toward catastrophic weather events. He said staff are meeting with MISO South members to discuss possible changes.

The stakeholder community was already in discussions about updating MISO’s current $3,500/MWh value-of-lost load (VOLL) when the storm led to rolling blackouts in a load pocket spanning the Texas-Louisiana border. The RTO has not updated its VOLL pricing since 2009 and may file to increase it in 2021.

In all, Laura spawned about 900,000 customer outages, 6.8 GW in generation outages and 365 transmission line outages. Some of the transmission outages were not returned to service until late October.

Smith said Hurricane Delta’s Louisiana landfall in early October was just 12 miles east from Laura’s path more than a month prior. He said this time, MISO was prepared. The Category 2 storm produced about 600,000 customer outages, 2 GW in generation outages and 54 transmission line outages.

Hurricane Zeta lashed New Orleans later in October and set off 600,000 customer outages, 1 GW of generation outages and 33 transmission outages.

New Risk Regimen

MISO said “an active, record-breaking 2020 hurricane season highlights the importance” of its efforts to establish a new reliability imperative, which may include a seasonal capacity auction and using operating hours that contain heightened risk. The grid operator currently uses a single peak summer day to define loss-of-load risk. (See MISO Nearing Decision on Seasonal Capacity Auction.)

Richard Doying, executive vice president of market and grid strategy, said an ever-changing resource portfolio paired with aging thermal generation’s more frequent outages means that risk is expressing itself in winter as well as summer. He said staff may adjust resource accreditation based on how much of resources’ nameplate capacity is useful.

“We see that migration of risk,” Doying said in December. “I think our stakeholders are comfortable with the fact that the world has changed.”

Doying also said that he’d like to see more price-responsive demand in MISO’s markets and not forcing grid operators to wait for an emergency before accessing demand-response resources. He said those moves would keep MISO markets pliable.

Staff’s Dustin Grethen, a market design adviser, said that the catalyst for the resource-adequacy initiatives is that MISO went several years without maximum generation events before encountering its first in four years in 2020.

Grethen likened the proposals to a person standing on one end of the Golden Gate Bridge and looking to the other side mired in fog. He said while MISO can’t perfectly predict what will be necessary for its market, operations and planning in the long-term, it can see how to begin crossing the bridge.

Market and resource adequacy changes will be managed on MISO’s new market platform, which is being phased in over six years. The grid operator plans to incrementally swap out systems and eventually retire its legacy platform by 2023. The legacy platform relies on ‘90s-era technology and was built in an age of conventional resources, but staff determined in 2016 that it was not able to keep up with the evolving grid’s demands

MISO’s modular platform is being developed in conjunction with other ISOs/RTOs. IT Senior Director Curtis Reister said it’s a cost-conscious move that has the RTO splitting development costs with ISO-NE and PJM.

“By doing this, we can create a more standardized product and reduce the need for customization,” Reister said.

Complicating matters, MISO expects to lose about 30% of its operators through retirement over the next few years.

“Lots of baby boomers in control rooms,” Moeller observed during the board meeting in December.

January 3, 2021

UCS Urges Broad Midwest Energy Legislation in 2021

The Union of Concerned Scientists (UCS) is making a pitch to Midwestern states in hopes that they pass sweeping clean energy bills in 2021.

A UCS year-end report says progress along the clean energy front was a mixed bag in 2020 in the Midwest, though some scattershot advancements were made

UCS analyst Jessica Collingsworth said while Midwestern utilities made several carbon-cutting commitments in 2020, they’re no substitute for state legislative packages. She advised Midwestern states “to make large commitments to moving clean energy policy in 2021.”

“Unfortunately, none of those states passed a large clean energy policy in 2020. But I think there’s potential in each of these states to do this. To get the social and economic benefits, we need to be bold in 2021 and pass comprehensive clean energy policies,” Collingsworth said in an interview with RTO Insider.

“I think there’s broad public support for the transition and combatting climate change. I think that there’s going to be more and more clean energy from states and at the national level. This isn’t a coastal thing,” she said. “I have a lot of hope for Illinois and Minnesota.”

Midwest Clean Energy — | *Pattern Energy*

This year, Minnesota’s Great River Energy announced that it will retire its 1.1 GW Coal Creek Station in North Dakota by 2023 and replace the output with wind power. Collingsworth said Xcel Energy’s pending integrated resource plan before the Minnesota Public Service Commission phases out its coal generation in Minnesota by 2030 while expanding solar resources.

Xcel also said this year that it will operate its coal plants on a seasonal basis until their retirement.

Illinois’ currently pending Clean Energy Jobs Act proposes to achieve a carbon-free power sector by 2030 and reach 100% renewable energy by 2050. Collingsworth predicted the package would pass sometime in 2021.

“There’s a lot of support behind it,” she said.

Collingsworth said Midwestern state legislation may have faltered in 2020 because legislative sessions were cut short by pandemic protocols. She said the legislative bodies may gain momentum as coronavirus transmission retreats.

“It’s a question mark what legislative sessions will look like in 2021,” she said.

Even without a law, Vistra Energy said it will wind down operations at seven coal plants in Illinois and Ohio by 2027, blaming in-part an “irreparably dysfunctional” MISO capacity auction design. (See Vistra Declares End of Midwest Coal Fleet.)

“While that’s welcome news, it’s critical that the Clean Energy Jobs Act passes in 2021 to support a just transition for coal plant workers and coal communities,” Collingsworth said.

Additionally, the Illinois Commerce Commission in December ordered Ameren Illinois to restore full retail net metering for new customers. Ameren announced late in the year that it had attained 5% distributed solar generation, which would have allowed it under state law to discontinue issuing credits for new customers.

Collingsworth praised Michigan Gov. Gretchen Whitmer’s goal to achieve economy-wide decarbonization by 2050 and her formation of the state’s Council on Climate Solutions to help reach the target. Collingsworth also called attention to Wisconsin’s Task Force on Climate Change, which recently advised the state to adopt more than 50 initiatives, including requiring utilities to lower their emissions 60% below 2005 levels by 2030 and 100% by 2050.

She predicted that the grid will look much different in the coming years as more distributed energy enters and climate policies materialize.

“I think it will help to have some strong climate leadership at the federal level, and I think Illinois can be a real leader and show how it’s done and adopt clean energy policy,” Collingsworth said. “Clean energy policies in one state help another state. Our clean energy goals in Illinois will help neighboring states.”

December 27, 2020

FERC Approves SPP’s Western Market Tariff

FERC handed SPP an early Christmas present Wednesday when it approved the RTO’s second version of a tariff for its five-minute Western Energy Imbalance Service (WEIS) market.

The commission accepted as just and reasonable the proposed tariff, the Western joint dispatch agreements (WJDAs) executed by eight entities and a charter for the Western Markets Executive Committee (WMEC). FERC found the WEIS market will yield “diverse benefits to the participating utilities and customers in the Western Interconnection” (ER21-3, ER21-4).

FERC said SPP’s proposal addressed its concerns with the RTO’s first filing, which it rejected in July. The commission said the earlier version failed to respect the transmission rights of nonparticipants and could improperly burden reliability coordinators, among other issues. (See FERC Rejects SPP’s WEIS Tariff.)

This time, FERC said SPP’s tariff “presents a just and reasonable regional solution.”

“We expect that the WEIS market will improve energy imbalance management by making a broader pool of resources available to serve load, enabling participating utilities to meet their energy imbalance needs at lower cost,” the commission said. “Additionally, we expect that the WEIS market will improve reliability by managing resources that could relieve transmission constraints more effectively, leveraging a larger, more diverse set of resources to operate the system within limits and creating price signals that lead to actions that could enhance reliability.”

The commission agreed with SPP that the WEIS market will help integrate and manage increasing levels of variable energy resources “by pooling variability over a larger area and re-dispatching resources to help manage imbalance energy caused by variable energy resources.” It said it expects the market to realize similar benefits as those of other energy imbalance markets.

The order keeps SPP on schedule to launch the WEIS market on Feb. 1. It had asked for a response from FERC by Dec. 3.

Bruce Rew, SPP’s senior vice president of operations, said in a statement that the grid operator is pleased with the order and “excited to be able to proceed with our implementation efforts, which are well on their way.”

The tariff defines rates, terms and conditions for the WEIS market and sets the rules and obligations for market participants. It includes a market participant agreement effective on the date participants begin their WEIS involvement. The tariff will be administered separately from SPP’s tariff in the Eastern Interconnection.

WEIS market participants began parallel operations earlier in December, giving them a chance to test their systems and train staff in the market’s production environment.

SPP will launch the WEIS with eight members covering the Western Area Power Administration’s Colorado Missouri (WACM) and Upper Great Plains West balancing authority areas. SPP said in November that several of its WEIS market participants are evaluating full membership in the RTO.

SPP also serves as an RC for about 12% of the Western Interconnection. It will add about 3.45 GW of generating capacity to its RC footprint — eight generating resources that are part of Gridforce Energy Management’s BA in Washington, Oregon, Arizona and New Mexico — effective April 1, 2021. (See SPP Expands its Western RC Footprint.)

SPP WEIS Tariff — SPP’s market footprints | *SPP*

Protests Rejected

Several intervenors protested the filing, including Xcel Energy-Colorado, Colorado Springs Utilities and Black Hills Energy, which plan to join CAISO’s Energy Imbalance Market (EIM).

Black Hills complained that its costs for energy imbalance service will significantly increase under the WEIS through the WACM BA, even though they are nonparticipants and that SPP did not conduct the kind of detailed cost-benefit analysis that was used to support CAISO’s EIM.

Filing jointly, Earthjustice, Natural Resources Defense Council, Sustainable FERC Project, Western Grid Group and Western Resource Advocates said SPP should allow them and other stakeholders to help develop a cost-benefit analysis.

The commission said a centralized imbalance market “can deliver significant benefits, including reliability benefits that are not easily quantified.”

“We do not find protesters’ arguments that SPP must demonstrate quantifiable net benefits persuasive. Although the commission carefully considers evidence of costs and benefits, it does not require a quantified cost-benefit analysis of proposals.”

FERC said SPP’s proposal to allocate costs based on net energy for load “reasonably reflects cost causation because net energy for load correlates to the size of the market.”

It rejected complaints that costs would be passed through to nonparticipants, saying there is “nothing in the WJDAs assesses costs to nonparticipants. To the extent WEIS market costs will be passed through to nonparticipants through other agreements, those agreements are not part of SPP’s filing and are not before the commission in the instant proceeding.”

The commission also rejected challenges to the SPP’s proposed governance structure, saying limiting voting rights to WJDA signatories “is reasonable because only WJDA signatories have made a financial commitment to the WEIS market.”

SPP provided ways for non-WJDA signatories to participate in open meetings, FERC said, noting the WMEC charter “is explicit in delineating that only portions of meetings voted as having a need for confidentiality by the WMEC will be closed to the public.”

The commission said SPP’s market mitigation provisions are “largely structured like those in SPP’s Integrated Marketplace but with additional measures, including a more stringent set of mitigation thresholds and a provision to address structural systemwide market power.”

It also rejected challenges to SPP’s proposal to include marginal losses in dispatch and LMPs, saying it was “necessary to ensure least-cost dispatch and will minimize imbalance costs, provide prices that accurately reflect marginal costs and preserve resources’ incentives to follow dispatch.”

SPP’s proposal to activate constraints to incentivize supply adequacy and prevent market participants from leaning on others was responsive to the commission’s July order, FERC said.

It also rejected a protest over SPP’s modeling of transmission availability, saying “if nonparticipants do not voluntarily offer their transmission for use in the WEIS market, the constraint enforced in [security-constrained economic dispatch] will not allow the WEIS market dispatch to utilize the nonparticipants’ transmission rights.”

Newly installed Commissioner Allison Clements did not participate in the proceeding.

December 22, 2020

Wind, Solar, EE, CO2 Storage Win Tax Breaks

Wind and solar generation, energy efficiency and carbon capture all won tax break extensions in an energy bill included in the massive stimulus and budget bill approved by Congress Monday night.

While far from the ambitions of the Green New Deal, the Energy Act of 2020 includes several measures to address climate change, including an agreement to phase out the use of hydrofluorocarbons used in air conditioning and refrigeration. That puts the U.S. in line with other nations whose efforts could help avoid as much as a half-degree Celsius in global warming by the end of the century. The bill also includes a “sense of Congress” statement that the Energy Department prioritize funding for research to transition to 100% “clean, renewable or zero-emission energy sources.”

The bill includes a two-year extension of the investment tax credit (ITC) used by solar power generators (keeping the ITC at 26% through year-end 2022 instead of falling to 22% in calendar year 2021), a one-year extender for the production tax credit (PTC) used by wind developers and a new 30% ITC for offshore wind projects that commence construction by the end of 2025.

In addition, the in-service window for the 45Q carbon capture and sequestration credit was extended by two years to the end of 2025 and waste-to-energy projects also will be eligible for the ITC.

The bill also re-authorizes the Advanced Research Projects Agency–Energy and the Weatherization Assistance Program through fiscal year 2025 and requires the secretary of the interior to seek to permit at least 25 GW of wind, solar and geothermal projects by 2025.

The provisions — consensus provisions from the Senate’s American Energy Innovation Act (S. 2657) and the House’s Clean Economy Innovation and Jobs Act (H.R. 4447) — were included as Division Z of the Consolidated Appropriations Act of 2021, a must-pass bill for Congress.

Sens. Lisa Murkowski (R-Alaska) and Joe Manchin (D-W.Va.), the sponsors of the Senate bill, called the legislation “the first comprehensive modernization of our nation’s energy policies in 13 years.”

Sens. Lisa Murkowski (R-Alaska) and Joe Manchin (D-W.Va.) sponsored some of the measures included in the Energy Act of 2020. | © *RTO Insider*

Murkowski, chairman of the Senate Energy and Natural Resources Committee, and Manchin, the ranking member, negotiated what they called a “six-corner” agreement with Reps. Frank Pallone (D-N.J.) and Greg Walden (R-Ore.), the chair and ranking member, respectively, of the House Energy and Commerce Committee, and Reps. Eddie Bernice Johnson (D-Texas) and Frank Lucas (R-Okla.), chair and ranking member of the House Science, Space and Technology Committee.

The bill “provides a down payment on the technologies that will be critical to reducing greenhouse gas emissions in the power sector, industry, and buildings and addressing climate change,” Manchin said in a statement. “This focus on research, development and demonstration will create high quality jobs and ensure the United States continues to lead the world in the clean energy future.”

“This is perhaps the most significant climate legislation Congress has ever passed,” Grant Carlisle, a senior policy adviser for the Natural Resources Defense Council, told The Washington Post.

“But, overall, the bill is a mixed bag because of provisions that prop up dirty fuels and unsafe technologies,” John Bowman, managing director for government affairs at NRDC said in a statement. “Given President-elect [Joe] Biden’s historic commitment to address our climate crisis, we look forward to working with him and the new Congress to promote the genuine clean-energy transition we need.”

Here is a list of some of the most significant provisions:

Among the other provisions:

Advanced Nuclear: updates the definition of “advanced nuclear reactor” to include small modular reactors; (See NRC OKs NuScale’s Small Modular Reactor Design.) authorizes an R&D program to help build a competitive fusion power industry
Carbon Capture, Utilization and Storage (CCUS): directs the Department of Energy to establish RD&D programs for carbon storage, carbon utilization and direct air capture, including a large-scale carbon sequestration demonstration program
Energy Storage: includes RD&D provisions for energy storage and qualifies storage for loan guarantees under Title XVII of the Energy Policy Act of 2005
Energy Efficiency: requires DOE to implement smart building technology in federal buildings and report to the president and Congress on each agency’s energy savings performance contracts, including their initial guaranteed savings compared to actual energy savings from the previous year; establishes rebate programs to encourage replacement of inefficient electric motors and transformers; formally authorizes the Federal Energy Management Program
Supply Chain: requires the executive branch designate a list of critical minerals and update that list every three years, an effort to rebuild domestic supply chains; expands and extends limitations on Russian uranium imports
Grid Modernization: re-authorizes the smart grid demonstration program in the Energy Independence and Security Act of 2007, and adds commercial application of distribution automation technologies to program goals; authorizes an RD&D and commercial application program on modeling emerging technologies for security and reliability and technologies to improve sensing, monitoring and visualization
Technology Transfer: creates programs to aid private sector access to DOE and its National Laboratories
FERC: authorizes FERC to modify compensation to attract and retain individuals with highly specialized skillsets

‘Sweeping Update’

The bill won wide praise from renewable energy supporters.

“Stable policy support will help ensure that wind and solar can continue providing the backbone of our country’s electricity growth,” said Heather Zichal, CEO of the American Clean Power Association. “We also applaud Congress for recognizing the enormous potential of offshore wind, America’s largest untapped electricity source.”

Gregory Wetstone, CEO of the American Council on Renewable Energy, said that 13% of the clean energy workforce is currently out of work because of the coronavirus pandemic. “Extending the solar and wind tax incentives and making the investment tax credit available for offshore wind projects is a bipartisan vote of support for the renewable industry and the hundreds of thousands of Americans building our clean energy future. These policies will help get people back to work,” he said.

“Clean energy was the biggest job creating sector in the economy pre-COVID,” said Rob Cowin, director of government affairs for climate and energy for the Union of Concerned Scientists.

“This omnibus legislation features a sweeping update and expansion of federal research, development and demonstration programs for carbon capture, removal, use and storage … along with enactment of a two-year extension of the 45Q tax credit,” Carbon Capture Coalition Director Brad Crabtree said. “While the coalition’s other top priority of a direct-pay option for 45Q did not make it into the final package, the measures included in the omnibus make this year-end legislation the most important accomplishment for carbon capture and removal since passage of the 2018 FUTURE Act that reformed and expanded the 45Q tax credit.”

December 22, 2020

Texas Public Utility Commission Briefs: Dec. 17, 2020

Texas regulators will begin the new year with a discussion of pricing issues within ERCOT following complaints from participants saying they were improperly charged for point-to-point (PTP) obligations in the day-ahead market (DAM).

The Public Utility Commission agreed during its open meeting Dec. 17 to pick up the conversation during one of its two meetings in January.

“I’m not saying I’m opposed to repricing, but I’d like to hear reasons we do it in some cases and a defense of it,” Commissioner Arthur D’Andrea said. “I worry about the day when we’re talking about really big numbers.”

DC Energy Texas and Monterey TX, both qualified scheduling entities (QSEs), complained that their PTP obligations in the DAM were improperly priced in excess of their not-to-exceed bid prices following a market software error in September 2019. ERCOT’s board approved price corrections for eight operating days affected by the error, along with 13 others. (See Directors Approve Price Corrections for 21 Operating Days,” ERCOT Board of Directors Briefs: Dec. 10, 2019.)

Staff’s Darryl Tietjen addresses the commission. | *Texas PUC*

The QSEs said the resettled prices left them $269,283.22 and $86,647.98, respectively, out of pocket, and took their complaints through ERCOT’s alternative dispute resolution process. The ISO determined in April that it had not violated any protocols in handling the resettlements and denied their requests.

The companies then filed complaints with the PUC in May. An administrative law judge in October found ERCOT had violated protocols when it issued the resettlement statements and said the QSEs were entitled to “a remedy that places them back in the position they would have been in had they never been awarded PTP obligations at prices more than $0.01/MWh above their not-to-exceed bid prices” (50871).

“I have a lot of sympathy with what the [judge’s decision] says,” D’Andrea said. “These [P2P obligations] are hedging instruments. Putting a price not to exceed is part of risk management, but to blow those up doesn’t feel right to me.”

D’Andrea said ERCOT runs an “incredibly complicated system” but added that “the protocols read like an owner’s manual for the atomic bomb.”

“One thing I’m convinced on, like previous cases, is that the Protocols could be clearer,” PUC Chair DeAnn Walker said, suggesting a rulemaking could be in order. “If everyone says this is an issue, but everyone says we can’t agree on what the solution is … that’s what we’re here for.”

In October, ERCOT’s Board of Directors approved two more sets of price corrections covering 25 operating days. Unaffiliated director Peter Cramton called for a strong policy on price corrections, while staff has responded by creating a monitoring group to review system design changes before they go live. (See “Board Approves 2 Sets of Price Corrections,” ERCOT Board of Directors Briefs: Oct. 13, 2020.)

PUC Rejects Rulemaking Petition

The PUC rejected energy storage developer Broad Reach Power’s petition for a rulemaking to clarify commission rules on how a transmission service provider’s (TSP) transmission tariff applies to wholesale storage entities. Staff said its rule is “clear and unambiguous” in that a TSP’s “tariff shall not apply to any entity engaging in wholesale storage” (51501).

PUC Chair DeAnn Walker kicks off the commission’s final meeting of 2021. | *Texas PUC*

Broad Reach filed the petition in November after Texas-New Mexico Power (TNMP) filed wholesale tariff revisions for transmission service that the energy storage developer said assessed distribution service charges to wholesale storage entities. Broad Reach said the changes were “inconsistent” with commission rules and applicable legal standards. (See “Commission Threatens TNMP with ‘Comprehensive’ Rate Case,” Texas PUC Briefs: Nov. 19, 2020.)

Gleeson Named Executive Director

The commissioners approved COO Thomas Gleeson as their new executive director. He replaces John Paul Urban, whose resignation was announced Dec. 9.

Gleeson joined the PUC in 2008. He previously was a legislative analyst for the Texas Senate and a budget analyst for the Legislative Budget Board.

Legislative Report Finalized

The PUC approved its biennial report to Texas lawmakers, who will begin their 87th legislative session on Jan. 12. The report includes a recommendation that the Legislature clarify that electric vehicle charging stations are not an electric utility or a retail electric provider and that use of such stations is not a transaction governed by existing retail electric policies.

“These changes will provide regulatory rightsizing and consistency across the state, in areas inside and outside competition, to facilitate deployment and competition of electric vehicle charging stations for customers,” the report says in edits offered by D’Andrea.

$307,500 in Administrative Penalties

The PUC hit three companies with a total of $307,500 in administrative penalties. The commission:

docked retailers Direct Energy, First Choice Power and Bounce Energy $250,000 for various infractions that involved enrolling customers in postpaid service plans without obtaining written and signed letters of authorization; distributing inaccurate lists of authorized pay stations and improper customer disconnections. Direct Energy and First Choice Power are affiliates within the same brand family, which purchased Bounce Energy and acquired its customers following the violations (51277).
agreed with TNMP on a $50,000 penalty for violating staff’s system average interruption duration index (SAIDI) standard of 54.77700 minutes (5% over the threshold) for the 2019 reporting year (51395).
assessed Twin Eagle Resource Management, a QSE, $7,500 for incorrectly opting out of a reliability unit commitment instruction (51154).

The PUC also approved rate case filing deadline extensions for Cross Texas Transmission (51534) and Electric Transmission Texas (51583).

December 22, 2020

New England ‘Future Grid’ Study Takes Shape

NEPOOL members got a look last week at what will ultimately underpin a new study to better understand the impact of New England’s ambitious greenhouse gas goals on the operation of the ISO-NE grid.

An expected dramatic reduction in New England GHGs by 2050 will recast the ISO-NE energy mix to include significantly more carbon-free resources, while electrification of the building and transportation sectors will drastically alter load volumes, peaks and profiles.

NEPOOL is embarking on a reliability study to better understand the implications of those changes as part of New England’s Future Grid Initiative. The study will examine whether current market revenues are sufficient to attract and retain the new and existing resources necessary to reliably operate the system. It will also identify operational and reliability challenges and outline possible ways to address them.

Peter Flynn, the consultant hired by NEPOOL and the New England States Committee on Electricity (NESCOE) to serve as administrator of the Future Grid project, presented the study’s stakeholder-developed framework document to the joint meeting of the Markets and Reliability committees on Thursday.

Flynn, former deputy general counsel for National Grid, said the study will eventually consist of several analyses using different computer models because “no single model can address the range of issues that NEPOOL stakeholders desire to assess.”

New England Grid Study — ISO-NE control room | *ISO-NE*

The analyses will be staggered, and the results from one will inform decisions about what to model in others. Close collaboration will be required between ISO-NE and any consultants retained by NEPOOL, according to the framework.

NEPOOL approved the objective and scope of the study, which will assess and discuss the future of the regional power system through the prism of state energy and environmental laws. The study’s scope is to define and evaluate the future grid by identifying the resource mix in the coming years and resource, operational and reliability needs.

Additional assumptions and scenarios are being developed through the stakeholder process at joint meetings of NEPOOL’s Markets and Reliability committees. A gap analysis will determine whether the existing markets are equipped to maintain system reliability and identify any deficits to be addressed to assure operations meet NERC, Northeast Power Coordinating Council (NPCC) and ISO-NE standards.

The study will feature economic analysis that includes production cost and ancillary services simulations, while a revenue sufficiency analysis will determine whether forecasted market revenues will be sufficient to attract and retain necessary resources.

An engineering analysis will include energy and ancillary services (EAS) simulations and a resource adequacy screen, while an availability and security analysis will answer questions about the conditions most likely to pose operational or reliability challenges.

EAS Market Simulations

The EAS market simulations will consist of nine matrix scenarios and 18 alternative scenarios.

The “Near Future Scenario” from National Grid assumes compliance with state requirements for 2035. The resource mix comprises approximately equal 8,000 MW amounts each of offshore wind, utility-scale PV and behind-the-meter PV, and 2000 MW of electric storage. It assumes about 16,000 GWh of building and transportation load.

Eversource’s “Distributed Pathway Scenario” is modeled to 2040 and represents a path toward reducing emissions consistent with an 80% economy-wide emissions reduction by 2050. The resource mix consists of approximately 12,000 MW of behind-the-meter PV solar, 9,000 MW of utility-scale PV, 8,000 MW of OSW and 4,000 MW of electric storage. It assumes 25,000 GWh of building and transportation load weighted toward transportation.

NESCOE’s “Offshore Pathway Scenario” is also modeled to 2040 and assumes carbon reduction that would put New England on course to comply with state law requirements by 2050. The resource mix consists of approximately 16,500 MW of OSW, 15,000 MW of utility-scale PV, 12,500 MW of rooftop PV and undetermined power amounts from electric storage and energy efficiency. It assumes approximately 76,000 GWh of building and transportation load, weighted equally, and load shapes consistent with such a high electrification level.

Next Steps

NEPOOL has asked stakeholders to provide feedback on these materials and assumptions on alternative scenarios by Dec. 31 to incorporate those comments and additional data in time for the RC/MC meeting on Jan. 19, 2021.

The committee expects study assumptions for the first phase of the report to be finalized by March 1. The final production cost simulation is scheduled for September 2021 to March 2022, and the ancillary services simulation from September 2021 to January 2022. MARS analyses will occur between October 2021 and January 2022. A final report is expected by May 2022.

For the second phase, dates have not been determined for the revenue sufficiency analysis and system security analyses, but they will not start before September 2021.

December 22, 2020

PJM MRC/MC Briefs: Dec. 17, 2020

Markets and Reliability Committee

Stability Limits in Markets and Operations

PJM stakeholders at last week’s Markets and Reliability Committee meeting heard a first read of manual language advanced regarding a stability limits capacity constraint proposal that some members are still challenging.

PJM and the Independent Market Monitor put forward the capacity constraint proposal, which was endorsed at the Market Implementation Committee meeting on Dec. 2 with 64% support. The proposal addresses the allocation of limits to multiple units by stating that the limit will apply to the sum of the output of the affected units plus ancillary service megawatts. (See “Stability Limits Review,” PJM MIC Briefs: Dec. 2, 2020.)

Joseph Ciabattoni, PJM | © *RTO Insider*

Joseph Ciabattoni, manager of interregional market operations for PJM, reviewed the proposed capacity constraint solution package and corresponding Operating Agreement and Tariff revisions. Ciabattoni said the units would be dispatched in economic merit order up to the stated stability limitation.

The package was the result of several months of discussion at the MIC on potential changes to how PJM curtails generating output to maintain stability during maintenance outages. Generating units are sometimes reduced below their normal economic max limit if a planned or unplanned transmission outage presents stability problems that could damage the units. (See “Stability Limits in Markets and Operations,” PJM MIC Briefs: May 13, 2020.)

Current rules require the RTO to implement a thermal surrogate to reflect the stability constraint in the day-ahead and real-time markets and to bind the constraint, affecting the unit’s dispatch.

PJM — Paul Sotkiewicz, E-Cubed Policy Associates | © *RTO Insider*

If a unit chooses not to remedy a stability limitation identified during the planning process, its operating restrictions — as documented in its interconnection service agreement — would be invoked prior to those for other units, Ciabattoni said.

Lost opportunity cost (LOC) credits would not be paid for any reduction required to honor the stability limit. Similarly, LOC is not paid for economic megawatts of a resource that cannot produce because of a ramp limitation.

Lisa Morelli, director of market design for PJM, provided an overview of the MIC’s work activities and related procedural history for the stability limits in markets and operations issue.

Carl Johnson, PJM Public Power Coalition | © *RTO Insider*

Paul Sotkiewicz of E-Cubed Policy Associates reviewed a proposed opportunity cost solution package. The proposal, presented by J-POWER and endorsed with 58% support at the December MIC meeting, was fundamentally the same as the PJM-Monitor package except for providing compensation for LOCs.

Sotkiewicz said if a generator is requested to take an outage when it can still run, the unit is in essence being asked to “misrepresent their true capabilities.” He said generation owners are very sensitive to the outage issue and that is why they’re seeking compensation for LOCs.

PJM — Consultant Roy Shanker | © *RTO Insider*

Carl Johnson of the PJM Public Power Coalition said he’s been “struggling” with how PJM can hold generators responsible when a contingency event is imposed. Johnson said he’s been ruminating on whether it’s never or always right to pay LOC.

Johnson said he’s also not certain that all contingencies can be identified at the time of generator interconnection because “the topology of the system changes.”

Consultant Roy Shanker said the stability limits issue seems more like a “contract matter” best dealt with when an interconnection agreement is signed.

PJM Monitor Joseph Bowring | © *RTO Insider*

“A better interconnection agreement would resolve all this going forward,” Shanker said.

Market Monitor Joseph Bowring said generators are “not held harmless” from all instances of being backed down because it’s not explicitly stated in the interconnection agreement. He said if there were no consequences in the agreement, the interconnection “would have cost a great deal more than it did.”

Bowring also noted that “there are no opportunity costs because the unit cannot run at a higher output and therefore there is no lost opportunity.”

Real-Time Values Market Rules

Laura Walter, senior lead economist for PJM, reviewed the solution package addressing real-time value (RTV) market rules endorsed at the November MIC meeting. Walter also reviewed proposed revisions to Manual 11 and the Tariff and Operating Agreement.

Stakeholders endorsed PJM’s package of updates to RTV that call for additional penalties for generation operators that abuse the rules. The MIC endorsed the RTO’s package with 73% support, and it received 55% support over maintaining the status quo in a nonbinding poll. (See “Real-time Value Market Rules Endorsed,” PJM MIC Briefs: Nov. 5, 2020.)

The issue charge and problem statement, originally endorsed last December at the MRC, said observations indicated RTVs were being used to consistently override unit-specific parameter limits or parameter-limited exceptions. (See “Real-time Values,” PJM MRC Briefs: Dec. 19, 2019.)

Walter said the original intent of RTVs was to provide a way for generation operators to communicate current operating capability to PJM if their resources could not meet their unit-specific parameter limits or exceptions. Generators opting to use RTVs forfeit operating reserve credits and make-whole payments.

The PJM package requires that market participants repeatedly failing to reflect actual operating conditions in their submitted operating parameters could be referred to FERC for enforcement. A market participant would be required to enter a forced outage ticket into PJM’s Generator Availability Data System (eGADS) for the period of increased notification, start-up time and/or minimum downtime.

PJM — Siva Josyula, Monitoring Analytics | © *RTO Insider*

For the timeline of an RTV submittal, Walter said, the package would require that the requested period not exceed one market day. She said that when an RTV is requested, it would be available for that one day, then the entire schedule would revert to the previous day’s values.

The package also calls for adding RTVs to the Tariff. Currently, RTVs are mentioned only in the manual, Walter said.

Siva Josyula of Monitoring Analytics said the Monitor is concerned that the changes proposed in the PJM package undermine the parameter-limited scheduling (PLS) rules used in RTVs. The PLS rules are part of the capacity performance rules requiring units to operate to defined parameters, he said.

PJM — David “Scarp” Scarpignato, Calpine | © *RTO Insider*

“The proposal we see essentially allows generators to circumvent the requirements without any justification during most of the days,” Josyula said.

Calpine’s David “Scarp” Scarpignato said RTVs are important to have in place because PJM needs to know what the units can and can’t do in real-time.

Scarp said it seems like the Monitor wants to penalize units that get paid for capacity that provide more flexibility compared to intermittent resources. He said the generators that are flexible are being held to a higher standard than other capacity resources that are less flexible.

“We push for a level playing field,” Scarp said.

Capital Recovery Factors

Jeff Bastian, senior consultant of market operations for PJM, provided an informational update regarding the capital recovery factor (CRF) for avoidable project investment rate (APIR) determinations from a statement PJM issued to stakeholders on Dec. 7.

PJM’s statement came in response to the Monitor’s letter Dec. 4 saying CRF values used by PJM do not reflect current federal tax law. The CRF is used to calculate the APIR as a component of the net avoidable cost rate (ACR) of a resource.

Bastian said the net ACR of a given resource sets the market seller offer cap and the minimum offer price rule (MOPR) floor offer price depending on which is applicable. Attachment DD of the Tariff includes tables of CRF values for resources to calculate the market seller offer cap or the MOPR floor offer price.

The Monitor said in its letter that the tables should have been updated in 2018 and need to be updated before the next capacity market auction takes place early next year.

“Correct CRFs will ensure that offer caps and offer floors in the capacity market are correct,” the letter said. “The required changes are clear and unambiguous.”

Bastian said PJM is officially introducing the table update issue at the January Markets Implementation Committee meeting and addressing the issue in a “quick fix process” with a same-day vote.

“We understand the IMM’s concern, but we also appreciate the need for stakeholder input before making any changes to the Tariff,” he said.

Sotkiewicz said he can envision a scenario in which a market seller decides to take the issue to FERC because of the changes to the Tariff. He said a challenge could potentially delay the capacity auction, which stakeholders want to avoid.

He then suggested taking the table update issue away from the 2022/23 capacity auction so it could operate normally and not face any challenges.

“We’ve had enough delays to last a lifetime already,” Sotkiewicz said.

Bowring said he has opposed further delaying the capacity auction and wants it completed as quickly as possible. He said the issue remains that the tables need to be updated and PJM does not have the authority to take the issue “off the table.”

“Our view is the table should be changed quickly so there’s no confusion, no uncertainty and no risk of litigation,” Bowring said. “It’s the low-risk path forward, and I’m not sure why anyone would oppose that.”

Manual 14C Delayed

Stakeholders voted to delay an endorsement of proposed revisions to Manual 14C: Generation and Transmission Interconnection Facility Construction as part of the biennial cover-to-cover review.

Members endorsed the motion to defer the revisions for a month with a sector-weighted vote of 3.67 (73.4%). The revisions were originally unanimously endorsed at the November Planning Committee meeting. (See “Manual 14C Endorsed,” PJM PC/TEAC Briefs: Nov. 4, 2020.)

Mark Sims, PJM’s manager of infrastructure coordination, said the committee proposed minor changes to Manual 14C, including an update of the latest Tariff provisions clarifying the filing process for title transfers and associated title documentation in Section 5. New sections on cost-tracking for baseline projects and another for supplemental cost-tracking were also proposed.

Greg Poulos, executive director of the Consumer Advocates of the PJM States, made the request to delay the endorsement by one month to work with PJM on some language suggestions. Poulos expressed concern about some of the proposed manual language.

PJM — Greg Poulos, CAPS | © *RTO Insider*

Poulos specifically referenced sections 6.1.2 and 6.2.1 dealing with tracking of supplemental projects. Both sections say, “PJM may request additional information regarding projects.”

“I know that I ‘may request’ things a lot, and it doesn’t mean I’m going to get it,” Poulos said. “I don’t necessarily understand where that fits into a manual. It feels like it’s weakening the standard.”

Jason Barker of Exelon said he was “a bit troubled” by the issue being brought to the MRC. Barker said the discussion over the language would have been more appropriate when it was first brought up at the PC.

Manual 28 Revisions Endorsed

Stakeholders unanimously endorsed proposed revisions to Manual 28: Operating Agreement Accounting to comply with FERC directives and address the allocation of real-time and day-ahead uplift to up-to-congestion (UTC) transactions. The revisions were originally endorsed at the December MIC meeting. (See “UTC Uplift Changes,” PJM MIC Briefs: Dec. 2, 2020.)

In its order issued in July, FERC determined that PJM’s current uplift allocation rules are unjust because they do not allocate uplift to UTCs (EL14-37). (See FERC Orders Uplift Charges on PJM UTCs.)

The commission directed PJM to submit a replacement rate that revises the RTO’s rules to allocate uplift to UTCs “in a manner that treats a UTC, for uplift allocation purposes, as if the UTC were equivalent to a [decrement bid] at the sink point of the UTC.”

PRD Credits Disposition

Pete Langbein of PJM reviewed a proposed solution package addressing the disposition of price-responsive demand (PRD) credits during a first read of the issue. Members unanimously approved an issue charge to address a disconnect in PJM’s settlement rules regarding payment for PRD at the July MIC meeting. (See “PRD Credits Disposition,” PJM MIC Briefs: July 8, 2020.)

PJM’s settlement rules call for revenues associated with PRD to be credited to the load-serving entity for an area and do not address the roles of electric distribution companies (EDCs) or curtailment service providers (CSPs), meaning some LSEs are paid for PRD service supplied by EDCs and CSPs. PRD providers represent retail customers that have the capability to reduce load in response to prices.

Langbein said PJM has an increasing share of load that is responsive to changing wholesale prices because of the implementation of dynamic and time-differentiated retail rates and utility investment in advanced metering infrastructure. Several EDCs cleared PRD as a capacity resource for the first time for the 2020/21 delivery year.

He presented revisions to Manual 11, Manual 18 and the Tariff. Stakeholders will vote on the revisions at the MRC meeting on Jan. 27.

Members Committee

Committee Elections

PJM stakeholders elected new members of the 2020/21 Finance Committee and the 2021 Sector Whips, with Erik Heinle of the D.C. Office of the People’s Counsel selected as the vice chair of the Members Committee.

The Finance Committee members elected include: Adrien Ford of Old Dominion Electric Cooperative (Electric Distributors); Poulos of the Consumer Advocates of the PJM States (End-Use Customers); George Kogut of the New York Power Authority (Other Suppliers); and Jim Benchek of FirstEnergy (Transmission Owners).

The sector whips elected include: Steve Lieberman of American Municipal Power (Electric Distributors); Susan Bruce of the PJM Industrial Customer Coalition (End-Use Customers); Michael Borgatti of Gabel Associates (Generation Owners); Brian Kauffman of Enel North America (Other Suppliers); and Sharon Midgley of Exelon (Transmission Owners).

Risk Management Committee Charter

Members unanimously endorsed the charter for the Risk Management Committee originally voted on at the MRC meeting in August.

Jennifer Tribulski, PJM | © *RTO Insider*

Jennifer Tribulski, senior director of member services for PJM, presented the charter establishing the Risk Management Committee (RMC) as a new standing committee. Though stakeholders unanimously endorsed the charter, PJM later determined the charter needed the MC’s approval to establish a new standing committee. (See “Risk Management Committee Charter,” PJM MRC Briefs: Aug. 20, 2020.)

The Risk Management Committee is set to meet for the first time on Jan. 26, taking the place of the Credit Subcommittee by expanding its scope to incorporate risk and changing its reporting structure. Under the revised charter, the subcommittee will report to the MRC rather than the MIC.

In her presentation, Tribulski said the Credit Subcommittee last met in March 2019 with much of the work around the RTO’s credit and risk rules accomplished through the Financial Risk Management Senior Task Force in the wake of the GreenHat Energy default.

She said the task force was established for the specific purpose of overhauling PJM’s rules for managing the credit risks of market participants and was not tasked with reviewing credit and risk management issues outside of its limited purposes. (See PJM Members OK Tighter Credit Rules.) She said PJM felt it was important to have a committee available to review and work on issues beyond those contemplated by the task force.

Chairman Lieberman

PJM — MC Vice Chair Katie Guerry | © *RTO Insider*

Lieberman, assistant vice president of transmission and PJM affairs for American Municipal Power (AMP), finished his last meeting as chairman of the MC. Katie Guerry, the current MC vice chair and head of regulatory affairs for Enel North America, will serve as the MC chairwoman for 2021.

Lieberman thanked the PJM Board and stakeholders for helping guide him through a year that saw major changes in operations with the onset of the COVID-19 pandemic, forcing discussions into a virtual setting. He said he had some “personal disappointment” that he was unable to chair the meetings in person.

“I hope I was still able to serve you in this role in a successful and professional way,” Lieberman said.

PJM CEO Manu Asthana thanked Lieberman for his service as chairman of the MC. Asthana said in working with him he came to find his “incredibly generous spirit” and an “amazing knowledge of the industry.”

Asthana said Lieberman played an important role in helping PJM navigate a “very difficult year.”

“We have been lucky to have you in the chair at the Members Committee,” Asthana said. “I know you didn’t get to govern in the personal manner to which you’re accustomed, but I know you have found a way to adapt and to project your character and personality through these phone calls.”

December 22, 2020January 15, 2025

SPP Out to Improve Competitive Tx Selection

Following the awarding of its second competitive project in four years, SPP has begun gathering stakeholder feedback as staff works to again improve its project selection processes under FERC Order 1000.

“We’re trying to mirror this process similar to what we did in 2016,” General Counsel Paul Suskie said during a webinar with stakeholders Friday.

Now, as in 2016, staff will gather member suggestions to improve its Order 1000 processes and other written comments, with a Dec. 29 deadline. The Markets and Operations Policy and Strategic Plan committees will coordinate the information before the January governance meetings, with a task force likely to be formed to present final recommendations to the Board of Directors.

SPP created a similar task force to improve its competitive transmission practices after its first Order 1000 project was canceled because of falling load projections. The task force’s chief recommendation was to allow re-study requests before issuing a notification to construct (NTC), which would have identified the change in load sooner. (See SPP Cancels First Competitive Tx Project, Citing Falling Demand Projections.)

“We knew we had to re-study, but [following the Tariff] we had to wait until the NTC was filed,” said Ben Bright, SPP manager of regulatory processes. He said the task force helped implement about half the 56 suggested stakeholder changes before it was disbanded in 2018.

The Sooner-Wekiwa project, running west of Tulsa | SPP

The board in October approved an industry expert panel’s (IEP) recommendation to grant SPP’s second competitive project, the 75-mile, 345-kV Sooner-Wekiwa project in Oklahoma to Transource Missouri, the panel’s “designated transmission owner. (See Transource Tapped for SPP’s 2nd Competitive Tx Project.)

SPP selects a five-person IEP, based on its expertise in engineering design, project management construction, operations, rate analysis and finance, to evaluate project proposals in those categories. Developer proposals submitted as detailed project proposals under SPP’s transmission owner selection process qualify for incentive points during the scoring.

Five entities — Transource, Xcel Energy Southwest Transmission (the Sooner project’s alternate builder), Liberty Utilities, LS Power-Southwest Transmission, and City Utilities of Springfield (Mo.) — have already submitted 18 proposals and staff added 13 more.

LS Power’s Pat Hayes suggested that the process of granting incentive points is “broken,” given the staff burden to evaluate proposals that number in the hundreds. He called for Tariff revisions requiring the IEP to justify its recommendation according to the projects’ efficacy and costs.

“The goal of the TSOP should be to deliver more efficient and cost-effective projects,” he said. “If it’s causing excessive costs and inefficiencies on SPP staff in the initial stage, we need to do something different. We think the easiest alternative is to scrap the incentive points altogether. There has to be some way to reduce the number of solutions and ideas.”

Bright said that after discussions with engineering support staff, SPP would “probably” recommend the removal of incentive points.

“If there’s a way to improve and provide value, we certainly want to have those conversations,” he said.

Bright said staff is also interested in revising the templates used in project submissions. He said the granular nature of confidential information resulted in a lack of transparency.

“The public version of the reports showed there wasn’t much there [behind the redactions],” he said. “It would be nice to differentiate publicly one proposal from another.”

LS Power and Xcel Energy both proposed changes to the intricate scoring matrix, which resulted in Transource winning the Sooner bid despite turning in the three most expensive proposals. They called for RFP respondents to be provided with details on how the IEP will evaluate and score their submissions.

Other suggested improvements included adding a resiliency metric and offering unsuccessful bidders an opportunity to meet with staff and review the strengths and weaknesses of their proposals.

Affected Systems Issues

Staff also visited with the Seams Steering Committee (SSC) and the Generation Interconnection Users Forum during their meetings last week to gather feedback on SPP’s affected system studies.

Staffer Jon Langford told the SSC that SPP is experiencing a “couple of core issues” in the affected system studies it uses to determine the effects of non-jurisdictional and neighboring interconnection requests on its transmission system. He said neighboring entities, transmission owners and customers have expressed concerns over the RTO’s interconnection queue priorities and the transmission services it studies.

Affected system studies are currently performed when needed and separately from SPP’s GI requests. They account for interconnection requests on neighboring grids, including MISO, Associated Electric Cooperative Inc. (AECI), Minnkota Power Cooperative and Northwestern Energy.

Langford said neighboring transmission providers and planning coordinators typically agree on a defined queue priority in their joint agreements. As an example, he said SPP’s priority practices with AECI are not documented.

“The big questions are those affecting our ability to respond to affected system study requests in a timely manner,” said SPP’s David Kelley, director of seams and Tariff services. “That’s creating disputes and consternation, if you will, from customers on both sides of the equation.”

The committee agreed to revisit the subject at its meeting Jan. 7. Staff hope to have a recommendation to bring before MOPC later in January.

SPP Faced with 3 Planning Studies

Any work on coordinated system studies with MISO and AECI will have to wait, staff told the SSC on Wednesday, as SPP is working on three different transmission planning assessments.

SPP’s planning staff is busy with three different transmission studies. | SPP

“Obviously, there’s a very full workload amongst all of the planning staff. It’s going to be crucial we don’t duplicate work,” SPP’s Neil Robertson said.

Staff are well into work on the 2021 and 2022 studies and the 20-year assessment. The long-term assessment is scheduled to be completed in 2022.

December 22, 2020

CAISO Board Fields RA Measures, Big and Small

CAISO’s Board of Governors voted Thursday to keep a small, older natural gas plant operating to maintain reliability and received a briefing on initiatives to revamp the ISO’s resource adequacy construct.

Both were part of CAISO’s push to prevent energy emergencies next summer like those that struck the state in August and September.

In an unusual request, management asked the board to approve a reliability-must-run (RMR) designation for two units at the Midway Sunset Cogeneration facility, a 250-MW plant built in the late 1980s in a Kern County oilfield.

The units were scheduled to retire at the end of this year. A third unit was already mothballed, but CAISO said the two remaining units may be necessary to help keep the lights on in the world’s fifth largest economy.

The plant can contribute to meeting demand in summer heat waves in the net-peak hours, when California’s solar resources ramp down but demand remains high in the evening. Rolling blackouts in mid-August and close calls over Labor Day weekend occurred during net-peak times. (See CAISO CEO Defends Blackouts Response.)

CAISO Resource Adequacy — The Midway Sunset Cogeneration plant sits in a Kern County oilfield.

“The Midway Sunset Cogen is required for the ISO to meet the 2021 systemwide reliability needs due to capacity insufficiency at the net-peak hour during the months July-September 2021,” Neil Millar, vice president of infrastructure and operations planning, wrote in a memo to the board. “Accordingly, the ISO cannot allow the resource to retire or mothball because, absent these units, it faces an inability to meet reliability criteria during these months.”

Stakeholders, including Pacific Gas and Electric, protested the lack of process in the decision and the rush to designate the plant as an RMR resource. Board Chair Angelina Galiteva acknowledged their concerns but said “reliability trumps” all other considerations with just days before the plant’s scheduled shutdown.

Stakeholder Initiatives

On a larger scale, CAISO is prioritizing stakeholder initiatives to promote resource adequacy in 2021 and 2022.

“This is important to ensure we are ready for next summer’s heat events,” Anna McKenna, interim head of market policy and performance, told the board.

Changes in the annual update to the ISO’s three-year policy initiatives roadmap focus on the urgent need to “comprehensively reform resource adequacy requirements” in connection with the shift from fossil fuels to renewables and tightening supply across the West.

They include a redesign of the ISO’s resource adequacy construct, Greg Cook, executive director of market and infrastructure policy, said in his presentation.

The efforts will try to ensure there is sufficient supply to serve net-peak load in heat waves and provide an adequate planning reserve margin, which CAISO wants the California Public Utilities Commission to increase from 15% to 20%.

A new workshop will try to make sure exports do not occur during times of tight supply, as occurred during the August blackouts. And the ISO is seeking to bring new storage resources online by the summer and ensure that imports are backed by specific out-of-state resources.

Many of the issues addressed in CAISO’s slate of initiatives were identified in a preliminary root-cause analysis of the summer blackouts sent to Gov. Gavin Newsom in October. (See CAISO Says Constrained Tx Contributed to Blackouts.)

December 22, 2020January 15, 2025

Study Proposes New Capacity Treatment for Oregon

Oregon should recognize the capacity contributions of all resources including variable renewables, according to a new report commissioned by the state Public Utilities Commission.

The report from consulting firm Energy and Environmental Economics (E3) counsels the PUC to adopt a plan based on methods already familiar to market participants in Eastern RTOs. These include use of demand curves to adjust capacity prices and measuring the marginal capacity contributions from renewable resources based on effective load-carrying capability (ELCC).

The E3 report seeks to answer a key question the PUC posed in April 2019 when it initiated an investigation (UM 2011) into a “comprehensive approach” to recognizing the capacity contributions of the various resources in utility integrated resource plans (IRPs): How should capacity be valued?

“The capacity provided by a resource to the electric system plays a central role in determining that resource’s overall value and therefore informs fair compensation to that resource,” the PUC wrote then. The growing penetration of variable energy resources “requires an examination at how capacity from various resources should be valued.”

The PUC said its existing programs have dealt with capacity valuation on a “piecemeal” basis, using different methodologies to account for capacity from utility-scale generation, distributed resources, energy efficiency, storage and demand response. At the same time, variable resources were short-changed by receiving “little to no credit” for their contributions to peak needs.

“A holistic investigation into these issues related to capacity could lead to a harmonization of some of these disparate approaches,” the PUC said.

The regulator pointed out that capacity valuation can play a role in the implementation of time-of-use rates or in evaluating programs such as demand response that can avoid or postpone investments in new resources.

“Other program benefit evaluations where capacity value needs to be considered include transportation, electrification and energy storage,” the PUC said.

Marching Down the Decarbonization Curve

“I think we’ve all seen across the West what can happen when capacity planning doesn’t quite go to plan,” E3 Director Zachary Ming said during a PUC-hosted video call Thursday to explain the capacity valuation report. “I’m really happy to be part of this proceeding that’s happening in Oregon to try to make sure the state gets ahead — and stays ahead — of the curve on this capacity issue that’s becoming more and more important with every year as we march down the decarbonization curve.”

Ming offered a primer on concepts that might be unfamiliar to Westerners not steeped in the organized capacity markets prevailing in the East.

The study’s authors asked two questions in their effort to identify a capacity compensation scheme: How much capacity in megawatts can any one resource provide? And for any megawatt of capacity, what is the value of that capacity to the system?

“Once you answer those questions, then you can set a dollar value,” Ming said. Any compensation framework should “appropriately measure” the quantity and value of the capacity a resource is providing, he said.

Ming said ELCC is the “gold standard” for measuring a resource’s contribution to maintaining the one-day-in-10-years loss of load probability (LOLP) principle typically recognized as the basis for gauging system reliability. ELCC allows for a comparison between different types of resources and measures the “perfect capacity” from each that would provide equivalent system reliability. For example, based on operating characteristics, a 100 MW solar plant and 50 MW gas-fired plant would each be capable of providing 50 MW of capacity.

Measuring the ELCC of a resource such as solar can become particularly tricky, Ming said. Under the concept of “antagonistic pairings,” resources with similar limitations reduce each other’s ability to provide capacity, something that occurs when more solar plants are added to an already solar-heavy system. In contrast, the “synergistic” pairing of resources with different characteristics, such as solar and storage, improve each other’s ability to provide capacity.

Regulators might have reasons for applying ELCC in different ways, Ming said. To assess overall system reliability, a “portfolio ELCC” approach can be used to capture the combined capabilities of all resources on the system. A “last-in ELCC” approach can capture the marginal ELCC of the next unit of a variable or energy-limited resource, an important tool when trying to understand how a newly procured resource will contribute to system capacity needs.

The industry widely uses simplified “approximation metrics” to reduce the complexity of estimating ELCC, Ming said. Among the most common is use of hourly LOLP to gauge ELCC. Historically, LOLP hours have been almost “exactly correlated” with peak load hours, he said.

“Resource availability wasn’t really an issue [in the past]. All resources — you could turn them on and off; you could run them for as long as you wanted. The only issue of not being able to meet load is if load got too high, which happened in peak hours or during extreme weather years,” Ming said.

Increased adoption of renewables, especially solar, means that LOLP has shifted into the evening hours when load is actually falling but the volume of energy produced is also declining with the setting sun.

“In today’s system, you see this most notably in California, although Oregon is headed in this direction, the loss of load probability hours have shifted [to] both later in the day and later in the summer,” Ming said.

He said the monetary value of capacity should be rooted in the principle of avoided cost. “A resource should be provided no more compensation than the least-cost resource that can be procured by the utility that provides equivalent reliability.”

To keep costs in check, the report proposes that Oregon policymakers adjust capacity prices based on a sloped demand curve “similar” to those used in organized capacity markets. That would enable the regulator to increase the value of capacity as the system moves from periods of resource sufficiency to deficiency. During times of sufficiency, the capacity value might reflect only operations and maintenance costs. In periods of deficiency, the value might rise to the net resource cost (similar to net cost of new entry), which reflects the total cost of building, integrating and operating a resource minus the revenue it earns from energy and ancillary services.

Different Strokes

Acknowledging the difficulty of creating a single capacity compensation framework for all resource types, E3 instead recommended two broad approaches.

Dispatchable resources such as gas-fired plants would earn payments based on a fixed annual value determined by its MW capacity credit multiplied by the $/MW-year value of the capacity. Resources paid under this “fixed payment” scheme would be subject to penalties for lack of performance during critical periods.

A “pay-as-you-go” scheme would compensate variable renewables based on performance during peak demand or capacity scarcity hours. The plan could be structured to either pay resources dynamically during only periods of system stress, or it could “send a consistent pre-determined price signal for all hours that have a higher” LOLP, E3 said. The plan would avoid subjecting variable resources to an “undue performance requirement,” Ming noted.

Because of their dispatchability, storage resources would fall under the fixed payment scheme, with compensation based on the product of the “last-in” ELCC and the monetary value of capacity.

“Performance would be measured by having the utility send a signal to the storage resource based on its capabilities. If it responds, it won’t be assessed penalties,” Ming said. Using pay-as-you-go to compensate storage could be “potentially discriminatory” because it could require the resource to cycle every day to receive payment. It also avoids compensating a storage resource when it’s not actually needed for capacity.

Like storage, demand response resources would receive fixed annual payments. Because DR has more limitations than storage, performance requirements would be based on a resource’s “inherent capabilities, identical to what is used in its ELCC calculation.”

For hybrid resources, E3 proposed a “bifurcated” scheme in which the renewable portion of the resource would be compensated under pay-as-you-go while the storage portion receives a fixed payment. “We do not think that a fixed payment only is appropriate for hybrids for the same reason it’s not for renewables,” Ming said.

‘Deliberately Provocative’

Fred Heutte, senior policy associate with the Northwest Energy Coalition, asked what E3 meant by “dispatchable” resources. Heutte noted that E3 had performed a study for Tampa Electric showing that solar can be dispatchable in providing incremental and decremental energy, providing load-following capability.

“It’s not something commonly done right now, but it’s certainly possible. Is that what you mean by dispatchable or is there something else?” Heutte asked.

“I think for the purposes of providing non-capacity services to the system, dispatching solar can be useful, like providing ancillary services,” Ming responded. “From a capacity perspective, I don’t know that I’d consider solar dispatchable, but it’s a term of art; there’s a gray line, of course.”

Dispatchability is really a function of how a capacity resource responds within its compensation framework, Ming continued. Solar will provide as much energy as it can when it’s producing to meet capacity needs.

“Storage is going to provide energy when [the grid operator] sends a signal to dispatch, and to that extent the compensation framework impacts how storage is dispatched. The compensation framework does not impact how solar is dispatched,” Ming said.

Representing the Oregon Solar Energy Industries Association, Patrick McGuire asked how E3 saw the “last-in” ELCC being updated over time. “If it’s put into a contract, does it have to be leveled?”

“We would expect both the last-in ELCC and the table of loss of load probability hours is going to be different in each future year, and they’re going to be changing as the resource mix and the loads on the system change,” Ming said. “In particular, we would expect the last-in ELCC of solar to decline over time.”

Commissioner Letha Tawney asked whether the PUC should be concerned about whether LOLP data is sufficiently accounting for climate change.

“The West-wide heat storm this August was relatively unusual in the historical data, but over the multi-decadal timeframe of these contracts, [it] may not be such an outlier,” Tawney said.

“The answer to that question is quite simply an emphatic ‘yes,’” Ming said. “You do need to account for a changing climate. That is easier said than done. There are firms and researchers that are looking at how to do that. I would say the standard practice in the industry probably doesn’t do as good of a job accounting for climate as it should.”

Heutte posed a “deliberately provocative” question about the risks of introducing concepts from organized markets into Oregon’s IRP process, such as net cost of new entry (CONE) and sloped demand curves. He said for the past two decades he’s read prominent economists who claim capacity markets are the way forward for the electricity sector, but that recent talk from states such as Illinois, Maryland and New Jersey about pulling out of PJM’s capacity construct calls into question the concepts underpinning those markets.

“I’m wondering what can we learn from that. … How can we be assured going forward that those kinds of design elements will actually produce the kind of results we’re looking for?

Ming said E3 explicitly avoided using the term net CONE and instead used net resource cost, which is fundamental to ratemaking.

“Trying to isolate the portion of the resource that’s attributable to capacity and attributable to energy is something that’s done in ratemaking in every regulated jurisdiction across the country,” Ming said.

He said the reason states are looking to pull out of PJM is unrelated to the way the market sets net CONE or the demand curve.

“It’s related to the inability of renewables to bid into the capacity market. They’re forced to bid in prices that are higher than the clearing price and, ultimately, they don’t clear the market and they don’t get paid anything for capacity. So that minimum offer price rule implemented by FERC this year, that is what is driving the states to exit the capacity market,” he said.