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November 14, 2024

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SPP Board of Directors Briefs: Dec. 6, 2022

Staff Finalizing Mitigation Strategy for PRM-deficient LREs

SPP staff last week said they are finalizing a mitigation strategy for load-responsible entities unable to meet the grid operator’s new 15% planning reserve margin and developing several concepts that would make failure to meet the requirements “less costly or less punitive.”

Lanny Nickell (SPP) Content.jpgSPP COO Lanny Nickell | SPP

COO Lanny Nickell told the Board of Directors during its Dec. 6 meeting that the concepts include reducing the deficiency payment charge, extending the timeline to cure deficiencies and adding mechanisms to assure capacity.

Staff have been working on the mitigation strategy at the board’s direction since July. It became necessary when the board increased the planning reserve margin from 12% to 15%, effective next year, which left some members complaining they wouldn’t have enough time to meet the requirements. (See SPP Board, Regulators Side with Staff over Reserve Margin.)

“We’re not looking to add that to the tariff on a long-term and permanent basis, but it would give some instant and interim relief,” Nickell said.

He said reducing the deficiency payment would reflect excess capacity’s value when a payment is required after a sudden increase in the PRM requirement. Nickell said the mechanism would incent long-term capacity planning and assess deficiency payments based on multiples of the cost of new entry to LREs that have not met the PRM.

The concept doesn’t relieve LREs of their obligation to comply with their resource adequacy requirements. However, it is applicable to deficient LREs for two years after the PRM change.

SPP is also proposing giving LREs more time to assess and cure their resource adequacy positions and better facilitate submissions on a virtual bulletin board to buy or sell power.

A 12-member strike team of directors, regulators and stakeholders has been meeting weekly since October to vet staff’s work. “We appreciate the fact that they were willing to help and willing to advise staff as we developed our further efforts on a mitigation strategy,” Nickell said.

The 22-person Members Committee unanimously approved staff’s concepts, with one abstention, with its advisory vote.

Staff plan to seek approval this week from the Regional State Committee of the mitigation effort’s applicable concepts. The board in October gave the committee, which comprises state regulators, the OK to file a tariff change with FERC that details how LREs can qualify for and receive exemptions from deficiency payments. (See SPP Board Bypasses Stakeholders on PRM Obligation Exemptions.)

SPP plans to file the tariff revision on behalf of the RSC this week. At the same time, it will draft a revision request for the mitigation concepts and bring that to the board and RSC in January.

Myers, Lang to Lead MOPC

The directors spent the bulk of last week’s meeting reviewing stakeholder evaluations of the board and organizational effectiveness, a stakeholder satisfaction survey, and SPP’s key performance metrics.

They also approved the consent agenda, which included several Corporate Governance Committee recommendations for the Markets and Operations Policy Committee’s leadership and other organizational groups.

As is SPP’s practice, Vice Chair Alan Myers, of ITC Great Plains, assumed the chairmanship previously held by Evergy’s Denise Buffington. The CGC recommended Omaha Public Power District’s Joe Lang as the new vice chair; both will begin their two-year terms on Jan. 1.

Buffington will fill a transmission-owning member’s vacancy on the Strategic Planning Committee. The term expires Dec. 31, 2023.

The CGC also put forward several nominations to serve two-year terms as organizational group chairs:

  • John Turner, Western Farmers Electric Cooperative, Modeling Development Working Group.
  • Tess Venetz, Xcel Energy, Settlements User Forum.
  • Calvin Daniels, Western Farmers Electric Cooperative, Economic Studies Working Group.
  • Derek Stafford, Grand River Dam Authority, Operations Training User Forum.
  • Jodi Hall, Evergy, Change User Forum.
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California to Offer $100M in Clean Hydrogen Incentives

As the California Energy Commission prepares to offer $100 million in incentives for clean hydrogen projects in the state, officials are seeking public feedback on the details of the upcoming solicitations.

The Clean Hydrogen Program has three main components, CEC staff said during a workshop on Dec. 1.

In the first piece, the CEC plans to offer $40 million for large-scale, centralized clean hydrogen production. The funds will target projects using existing technologies to produce hydrogen on a large scale — 5 metric tons a day or more — in the near term. Awards will range from $10 million to $20 million.

Another $30 million in funding will be available to projects in which hydrogen is produced and stored at a point-of-use. The CEC is looking for 1 to 5 metric tons of daily hydrogen production. This funding is aimed at earlier stage technologies. The awards would range from $4 million to $7.5 million.

And in a third component, $20 million would be available to hydrogen projects in need of matching funds for federal money, such as from the Infrastructure Investment and Jobs Act. In addition, another $10 million is set aside for technical assistance and administrative support, bringing the program total to $100 million.

As now proposed, funding for large-scale projects would be limited to those producing hydrogen through electrolysis powered by renewable resources. In contrast, the CEC would allow more flexibility in production methods for onsite hydrogen projects.

The solicitations are expected to be released next year, starting with the federal matching funds component. The CEC is accepting comments on design of the solicitations through Dec. 16 at 5 p.m.

Electrolysis Requirement Debated

The electrolysis requirement for large-scale projects was a topic of debate during the workshop.

“[I] don’t understand why the focus was put on electrolysis. That’s not the cost-effective way to produce green hydrogen,” said workshop participant Chris Headrick, founder and executive chairman of Texas-based H2 Energy Group. The company’s technology produces hydrogen through pyrolysis of woody biomass.

The Clean Hydrogen Program was created by this year’s Assembly Bill 209, and CEC staff said program requirements are based on what’s in the bill.

The bill says that hydrogen projects eligible for the program’s incentives must involve hydrogen “derived from water using eligible renewable energy resources,” or be “produced from these eligible renewable energy resources.”

“I don’t see anything in AB 209 that justifies limiting the larger export projects to electrolytic hydrogen only,” said Julia Levin, executive director of the Bioenergy Association of California. “And I would say it’s actually far more urgent to deal with our organic waste to meet the state’s short-lived climate pollutant requirements, the wildfire reduction requirements, etcetera.”

CEC staff noted that the current program requirements are proposals at this point, and the agency will take stakeholder feedback into account before finalizing them.

Another program requirement that raised questions was a proposal to ban petroleum refining as an end use in either the large-scale or onsite projects.

“Why limit the end use of hydrogen?” a workshop participant said in a chat comment. “If it is green and can replace fossil derived hydrogen, it is a step in the right direction.”

Costs, Emissions Considered

The CEC plans to evaluate project proposals based on factors including technological readiness, water usage and reduction in emissions of greenhouse gases and other pollution.

The agency will be looking for cost improvements as compared to the cost of hydrogen from steam reforming of fossil gas. Job benefits and community impacts will also be considered.

CEC staff described the clean hydrogen program as complementary to the Alliance for Renewable Clean Hydrogen Energy Systems, or ARCHES.

ARCHES is California’s public-private consortium aimed at accelerating the development and deployment of green H2 projects and infrastructure. The partnership is seeking a piece of the $8 billion in hydrogen hub funding being offered by the Department of Energy.

ARCHES is seeking proposals for hydrogen projects in California, with a deadline of Dec. 23.

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Rhode Island Updates 2016 Greenhouse Gas Plan

A draft update of Rhode Island’s climate protection plan indicates the state is below the trajectory needed to meet its greenhouse gas reduction targets but lays out steps to achieve them.

The Executive Climate Change Coordinating Council (EC4) is under a Dec. 31 deadline to update the state’s 2016 Greenhouse Gas Emissions Reduction Plan.

The draft update released Monday contains changes based on developments since the original was penned, including last year’s Act on Climate, which converted the state’s emissions-reduction goals to enforceable mandates and set priorities for equity, justice and workforce development.

After delivering the final version of this update, the EC4 will begin to draw up the formal “2025 Climate Strategy,” due Dec. 31, 2025.

Rhode Island’s 2021 Act on Climate requires the state to reduce greenhouse gas emissions by 45% from 1990 levels by 2030 and 80% by 2040, then achieve net zero status by 2050. The state is also trying to reach 100% renewable energy by 2033.

Given changes in methodology, comparing 1990 and 2019 data is not an apples-to-apples exercise, the report states. But using that data, a simulator developed by RMI shows Rhode Island emissions fell 19.5% from 1990 to 2019 and projects emissions would be down only 40.8% in 2030, missing the 45% target by a significant margin.

“This is a very simple, preliminary model that verifies Rhode Island is moving in the right direction but is not quite at the point where we can be confident in our success,” the report states. “More refined modeling and development of specific strategies to increase that confidence will be the crux of the 2025 Strategic Plan.”

Developments in Rhode Island since the original Greenhouse Gas Plan was created in 2016 include:

Priorities going forward include:

  • conversion of the power grid to a two-way conduit between many renewable energy producers and customers, rather than a one-way flow from a few large generators to customers;
  • installation of advanced electric meters capable of by-the-minute measurements and real-time communication;
  • expansion of the number of EVs registered in the state from 6,275 (as of October 2022) to 86,000 by 2030;
  • growing public transit ridership from 53,000 to 87,000 trips per day by 2040;
  • conversion of 15% of all buildings from fossil fuel heat to efficient electric heat by 2030; the authors call this “an aggressive but attainable and necessary target;”
  • strengthening Rhode Island’s Building Energy Code;
  • adoption of a no-net-loss policy for forestland, which absorbs and stores carbon dioxide; the nation’s smallest state has about 361,000 acres now; and
  • the pursuit of districts for geothermal heating and cooling, which can be difficult for individual homeowners to install themselves.

The 2021 Act on Climate did not actually define “emissions” or the “net-zero” balance it seeks to achieve. The EC4 group proposes that emissions be defined as any of the greenhouse gases blamed for global warming now or in the future, and that net-zero be a balance between the amount emitted and the amount absorbed or broken down.

But the authors say that in the 2025 report they plan to continue to stress reduction of emissions over net zeroing. And without improvements in emissions-tracking capabilities, they plan to endorse annual measurements of emissions, rather than seasonal, monthly, daily or even hourly measurements.

Near-term prospects appear strong for federal funding to pay for these initiatives, the authors say, but it will not be enough. State taxpayers will have to foot some of the bill.

Rhode Island’s greenhouse gas emissions in 2019 — the last year available — were estimated to be 1.8% lower than in 2016.

Transportation and thermal uses accounted for the bulk of emissions at 39.7% and 38.8%, respectively, followed by electricity consumption at 18.9%. Agriculture and waste were the source of 2.6%.

Emissions from electrical power consumption and industrial uses decreased between 2016 and 2019, countered by increases in emissions from heating, transportation, agriculture and waste.

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ERCOT Technical Advisory Committee Briefs: Dec. 5, 2022

Real-time Co-optimization Could be Back in 2023

ERCOT plans to resuscitate the development of real-time co-optimization, staff told the Technical Advisory Committee Monday.

The market tool was paused last year because of staffing constraints following the February winter storm. (See “Passport Pushed Back 18 Months,” ERCOT Technical Advisory Committee Briefs: April 28, 2021.)

Dave Maggio, ERCOT director of market design and analytics, said plans to resume RTC’s development in mid-2023 are “on the radar.” Its delivery is dependent on staffing and other requirements that may come out of the market design, he said.

RTC was originally scheduled to go online in 2024. Maggio said assuming a mid-year kickoff next year, it will be delivered in 2026.

Staff has estimated it will cost as much as $55 million to implement the RTC tool, which procures both energy and ancillary services every five minutes. ERCOT’s Independent Market Monitor has called for the grid operator to add the tool for several years.

Maggio will return to TAC’s Jan. 24 meeting with additional details on scheduling and timing.

No Major Changes to AS Methodology

TAC endorsed staff’s annual recommendations for the proposed methodology for computing ancillary service quantities in 2023, which included making no changes to the methodologies used to compute regulation service and responsive reserve service (RRS) requirements for 2023.

Staff is proposing changes in the methodology used to compute minimum non-spinning reserve service requirements in 2023 by shifting from a 6- to 10-hour ahead net load forecast error. Upon its implementation, they are recommending computing ERCOT contingency reserve service requirements as the sum of capacity needed to recover frequency following a large unit trip and capacity needed to support sustained net load ramps.

Staff is also proposing to revise the minimum RRS-primary frequency response limit next year to 1,390 MW, aligning it with an increase to ERCOT’s interconnection frequency response obligation.

The recommendations were added to the TAC’s combination ballot.

Lange Welcomes Return as Chair

South Texas Electric Cooperative’s Clif Lange, who chairs TAC, told members he is open to returning to the leadership position next year, assuming he remains a committee member.

Lange, who was recently promoted as the cooperative’s general manager, said he had been approached by several other members about continuing as chair.

“I wasn’t sure that that was going to be possible,” Lange said, “but after having had some time to reflect and think about it, I’m certainly willing if TAC is willing to have me as chair for next year.”

The Board of Directors will confirm TAC’s representatives during its annual membership meeting Dec. 20.

TAC Endorses 10 Revision Requests

The committee endorsed a system change request (SCR821) that would address operational issues by allowing transmission and distribution service providers to set the voltage set point target information provided to distribution generation or energy storage resources.

The measure passed unopposed but with abstentions from CenterPoint Energy, Oncor Electric Delivery and Texas-New Mexico Power, members of the investor-owned utility segment.

The combination ballot passed with one abstention. It included five nodal protocol revision requests (NPRRs), two revisions to the Nodal Operating Guide (NOGRRs), and single changes to other binding documents (OBDRR) and the Resource Registration Glossary (RRGRR) that, if approved by the board, would:

    • NPRR1128: set an ancillary service offer floor $0.01/MW lower for fast frequency response (FFR) than for other RRS categories to allow FFR procurement up to the current limit, without proration with other RRS categories.
    • NPRR1132: specify that during local cold weather conditions, each qualified scheduling entity (QSE) must update its generation resources and energy storage resources current operating plan, real-time telemetry, and outage and derate reporting to reflect any limitations. It also requires each resource entity to provide resource-specific cold weather minimum temperature limits, hot weather maximum temperature limits, and alternate fuel capability information in its submitted resource registration data and update this information as necessary.
    • NPRR1138: require each resource entity to ensure the reactive capability curve for any intermittent renewable resource accurately reflects its reactive capability when it is not providing real power or is operating at lower levels of real power output.
    • NPRR1152: remove the protocol requirements to submit emergency operations plans (EOPs), weatherization plans, and declarations of summer/winter weather preparedness; revises procedures for submitting declarations of natural gas pipeline coordination with natural gas generation resources; revises the list of items considered protected information to remove references to weatherization plans and add protections for information relating to weatherization activities; and revises the list of ERCOT critical energy infrastructure information to clarify language concerning EOPs and add protections for information relating to weatherization activities.
    • NPRR1154: update language to allow for a qualified alternate resource to be considered in calculating the availability reduction factor for the firm fuel supply service (FFSS) resource and provides a new settlement billing determinant providing the FFSS award amount per QSE per FFSS resource by hour.
    • NOGRR226: add provisions for transmission operator “anti-stall” automatic firm load shedding at 59.5 Hz to mitigate the risk of a total system-wide blackout.
    • NOGRR243: modify the Nodal Operating Guide’s load-shed table to include separate load-shed obligations for the winter and summer seasons that align with Senate Bill 3 directives.
    • OBDRR043: align the operating reserve demand curve’s methodology with NPRR1148’s revisions, approved in August, in calculating the real-time reserve price adder.
    • RRGRR032: add data required to be shared with ERCOT as the reliability coordinator, balancing authority and transmission operator in considering cold weather limitations in its operational planning analysis, real-time monitoring, real-time assessments, and other analysis functions. The ISO also requires this information for hot weather limitations and making this a requirement for distributed generation resources and distributed energy storage resources.
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Ohio Senate Votes to Declare Natural Gas ‘Green’

The Republican-dominated Ohio Senate on Wednesday approved legislation that included a last-minute amendment declaring natural gas to be “green.”

The bill was approved by a vote of 22-7, with one Republican joining six Democrats in opposition. It now heads to the Ohio House of Representatives before the legislature concludes its lame duck session by year-end.

The green declaration was one of five amendments that had been added in the Senate Agriculture and Natural Resources Committee on Tuesday to Substitute H.B. 507, regulating the state’s poultry industry. The House had unanimously approved H.B. 507 in April.

There had been no discussion in the committee, other than questions and objections from the lone Democrat, before the vote to add the amendments.

Despite the designation of natural gas as green, the language of the amendment specifically blocks shale gas produced in Ohio from qualifying for renewable energy credits (RECs), as feared by renewable energy advocates when the amendments surfaced on Monday.

The Ohio legislature in recent years has made it more difficult for utility-scale solar and wind developers by approving legislation giving county commissioners authority to block the will of the state’s Power Siting Board.

The Senate’s move comes after six rural counties in the state approved resolutions declaring natural gas a source of green energy. That was the work of The Empowerment Alliance (TEA), an anonymously funded 501(c)(4) nonprofit founded in 2019 to promote natural gas and fight the “Green New Deal.” The alliance could not be immediately reached for comment.

Though not identified in committee or on the floor of the Senate, Ohio Sen. Mark Romanchuk (R) was the lawmaker who suggested the green declaration.

“I talked to them [TEA] about this, but I did not get any pressure about it. They were in favor of it,” he said. “It took me some time to get on board with it, but after reading about Europe” declaring natural gas green to help bankroll rapid development “and knowing just how important gas is to Ohio’s economy, I did some research and found that we reduced our emissions by 50% in 15 years,” referring to gas replacing coal for electricity generation.

“I thought about it long and hard for several months, did some research and reading. I decided to move forward and designate gas as a green energy,” he said.

Nolan Rutschilling, spokesman for the Ohio Environmental Council Action Fund, said declaring natural gas clean in the state’s revised code “gives credence to this myth that natural gas is clean when we know it is not.”

“We’ve seen the natural gas industry and the oil industry try to frame natural gas as clean and sustainable for years. We know it is a major contributor to climate change and that it’s a fossil fuel,” he said.

Another amendment added to the poultry bill included language requiring state agencies to negotiate with gas and oil producers seeking to drill laterally under public land, such as state parks. The drilling has been permitted for a decade, but state agencies have been waiting for the creation of a commission to complete the paperwork.

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WECC Heat Wave Analysis Evokes Calls for Caution, not Celebration

New analysis from WECC suggests that Westerners should take cold comfort from the fact that grid operators were able to avert blackouts during a September heat wave that toppled records for temperatures and electricity demand.

The analysis shows that, while the region’s grid operators have significantly improved their ability to respond to extreme weather events since an August 2020 heat wave prompted California’s first rolling blackouts in two decades, other factors outside the control of operators played a key role in avoiding a repeat of the 2020 outcome.

“Things were good, but they weren’t perfect,” Tim Reynolds, WECC manager of event analysis and situational analysis, said Wednesday in presenting the findings to the regional entity’s Board of Directors.

This year’s heat wave materialized as a heat dome on Aug. 31 and lasted until Sept. 10, bringing record highs to cities throughout Northern California, such as Sacramento (116 F), Santa Rosa (115 F) and Calistoga (118 F), while temperatures to the south exceeded norms.

Over the course of the nearly two-week event, CAISO experienced persistently high demand, hitting an all-time record peak load of 52,016 MW on Sept. 6, which nudged past the previous high and far surpassed the peak of about 46,000 MW that occurred during the August 2020 heat wave.

The ISO’s own analysis, released last month, indicated that electricity imports, conservation measures and improved coordination with utilities and government agencies helped prevent blackouts this summer despite the higher demand than two years earlier. CAISO also pointed to the benefits of increased coordination with neighboring balancing areas, including through expanded membership of the ISO-run Western Energy Imbalance Market, as well as the addition of 3,500 MW of battery storage resources within its territory. (See CAISO Reports on Summer Heat Wave Performance.)

Learning Process

WECC’s examination took a wider view of conditions across the Western Interconnection, which on Sept. 6 also posted a record peak of 167,530 MW, shattering the previous high of 162,017 MW set during the 2020 heat wave.

But as the CAISO peak load figure for Sept. 6 suggests, California appeared to account for all of that increase. And that points to a key difference between the two heat waves: This year, the most extreme heat was concentrated in California, while in 2020 wide swathes of the Northwest and inland Southwest were simultaneously subject to extremes.

“So this lets us know the demand wasn’t as much as it was back in 2020 in those [Northwest and Southwest] areas, and at the same time, there are more resources that could be available,” Reynolds said.

Another key difference, according to Reynolds: This year’s heat wave saw less transmission congestion than in 2020, when planned outages limited transfers between the Pacific Northwest and California.

“Energy transfers were able to happen a lot better than … back in 2020, so that was not an issue this go-round,” Reynolds said.

And while some wildfires were burning in the West during this year’s heat wave, none of them affected systemwide reliability. The biggest impact was seen at the start of the heat wave on Aug. 31, when fires forced outages for nine transmission lines and 1,103 MW of generation throughout the interconnection. Those resources were all restored within days, before the worst of the heat.

Reynolds said Level 3 energy emergency alerts (EEA 3) were issued seven times during the September heat wave, four of which were in the same — unnamed — balancing authority area. During an EEA 3, BAs “arm” themselves to begin shedding load. But no load was shed this time around, something Reynolds partly attributed to operational improvements that the BAs adopted based on best practices developed by WECC and the region’s reliability coordinators after the 2020 blackouts. He said WECC’s analysis of the 2020 heat wave found that BAs and RCs at the time lacked clarity on how to respond to emergencies.

“We actually sat down and had several meetings to go over what were some of the best [and] common practices,” Reynolds said. “It was great to see because some of the RCs had their trainers there, and they were kind of asking each other, ‘How do you train for an EEA?’ And they’re sharing ideas and everything else, so it was a great collaboration that was going on between WECC staff and the RCs, and we collated all that information to be able to make a best practice document.”

Reynolds said the process helped inform more BAs that, during an EEA 3, they can count armed load-shedding schemes as contingency reserves, freeing them to use spinning reserves to serve real-time load.

“What was nice was [in] this go-round … we saw more balancing authorities actually doing that, once they hit that EEA 3 level,” said.

Forecasting Flaws

WECC identified continued flaws in day-ahead load forecasting during the September heat wave, a carryover from 2020, with actual peaks outpacing forecasts during both events. On the day the interconnection registered its new record peak, the actual peak exceeded the day-ahead forecast by 4%, an even wider margin than the 2 to 3% errors seen in 2020.

“One thing we’re noticing a little bit of … with the EEAs is there’s not a lot of guidance or best practices out there for the forecasting, so there’s definitely potentially some areas for improvement and sharing those forecasting best practices for the day-ahead — but also for the annual forecasts,” Reynolds said.

Wind forecasts were similarly subject to errors during the heat wave, a phenomenon WECC also identified from its 2020 analysis.

“During the times of the peak and the most intense part of the heat waves, we noticed wind generation [would] go below forecast,” he said, adding that wind output didn’t necessarily come up short of forecast during the entire heat wave.

“We are definitely recommending more analysis to kind of look into this even more,” he said.

On a positive note, battery storage was a big contributor to the grid during the heat wave, in some intervals actually outproducing the 2,200-MW nameplate capacity of the Diablo Canyon nuclear plant. About 95% of that output was from battery resources located in California, WECC determined.

Nothing to Celebrate

WECC board members were impressed with the findings. They were less pleased by their implications.

“I hope people see this as, you know, we were pretty lucky. I mean, the weather could have changed significantly, and from my point of view, we could have been right back where you started from in 2020,” Director Gary Leidich said.

Leidich encouraged WECC to publish the findings in a report that is as “neutral as possible” but makes clear that “this is not an event which we should celebrate — nor is it one that’s a disaster.”

“We need to keep pushing on those improvements to be able to, frankly, fight to keep the lights on,” he said. “I just want to see there’s a balanced perspective here, because I sense of some of the media that I read along the way [said] that people were celebrating this as some sort of a success, and I don’t think we should view it necessarily as that.”

WECC CEO Melanie Frye called Leidich’s comments “spot on.” She pointed out that Reynolds’ presentation didn’t include the fact that California at one point avoided blackouts because Gov. Gavin Newsom issued a call for emergency demand response that quickly reduced load by nearly 2,400 MW.

“And that demand response is a great tool, but that’s not the way we want to deploy that as a resource,” Frye said. “So while I think there’s a lot to be learned, and there is some recognition of … all the work that’s been done to improve over 2020, we’re not done, and we can’t just sit back and say, ‘Oh, we got this figured out.’”

“We didn’t have any major lines down, and we didn’t have any major power plants down, yet we were dangerously close to the edge,” Director Jim Avery said. “I think that’s important to highlight.”

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PacifiCorp to Join EDAM, Final Plan Released

PacifiCorp on Thursday became the first Western utility to commit to joining CAISO’s proposed extended day-ahead market (EDAM) for its real-time Western Energy Imbalance Market, assuming the market design wins approval next year.  

“With this important and timely announcement, we are hopeful that many of our other valued partners across the West will join PacifiCorp in positioning the EDAM as the next major step in Western market integration,” CAISO CEO Elliot Mainzer said in a statement.

PacifiCorp helped design the WEIM and joined as its first member in 2014. The market now includes 19 participants and has generated more than $3 billion in economic benefits, including $500 million for PacifiCorp, which has also helped design the EDAM.  

“This next step to a day-ahead market is another game-changer to increase the triple benefit to our customers of cost reductions, increased reliability and reduced emissions,” Pacific Power CEO Stefan Bird said in a news release. Pacific Power is the PacifiCorp division that serves customers in Oregon, Washington and a small part of California.

The news of PacifiCorp’s commitment came a day after CAISO issued a final proposal for the EDAM that it plans to present to its Board of Governors and the WEIM Governing Body on Dec. 14. Both governing boards are scheduled to vote on the plan in February. FERC approval would be next.    

The final proposal makes changes to the draft final plan published Oct. 31. They include clarifications and enhancements that respond to stakeholder comments.

Transmission commitment has been a thorny topic in the EDAM planning effort, which CAISO fast-tracked starting late last year.  

“Availability of transmission to the market is critical for efficient transfers of supply across the EDAM footprint to serve load and maintain grid reliability,” the plan says.

Stakeholders have had questions and concerns about what, exactly, transmission availability and commitment mean in the EDAM design.

“The final proposal clarifies, in response to stakeholder comments, the transmission requirement for resource participation in the market,” it says. “In particular, the final proposal clarifies that a resource must be a designated network resource under the terms of the Open Access Transmission Tariff, have reserved firm point-to-point transmission (of any duration), or have a legacy transmission contract.

“If transmission has not been reserved, the resource would nevertheless be able to participate in the market and the EDAM entity transmission provider would assess a charge for using transmission based on the rate for the lowest duration of firm point to point transmission service established by the OATT.”

The final proposal also introduces two enhancements to proposed transmission availability rules.

It “enables eligibility for historical revenue recovery associated with historical sales of monthly firm and non-firm point, in addition to the already eligible weekly, daily and hourly transmission products.” And it clarifies the “treatment of, and the ability to exercise, transmission rights between an EDAM balancing area and a non-EDAM balancing area to support continued service to load and meeting obligations under existing or emerging programs around the West.”

The Western Power Pool is moving forward on its Western Resource Adequacy Program. Stakeholders have raised question about how that program’s requirements might clash with the EDAM’s rules. PacifiCorp and 10 other utilities said Thursday they intend to join the WRAP.

Resource Sufficiency Tweaked

Another sticking point has been the plan for a resource sufficiency evaluation (RSE) to keep participants from leaning on the EDAM to serve unmet internal load. How resources will be counted and penalties for failing the RSE have worried some stakeholders. (See CAISO Tackles EDAM Design in Stakeholder Meeting.)

The final proposal tries to ensure that demand response, as a resource, is “accurately captured and tracked.” It details how generation-only balancing areas will be treated in the RSE. And it retains the consequences for failing the RSE outlined in prior versions but clarifies the proposed surcharges for failing the test.  

The final plan further modifies the EDAM design by allowing participants to elect whether to allow convergence bidding within their balancing area after they join and removes a “mandatory transition to convergence bidding after one year of participation” contained in earlier drafts.

“The ISO will further evaluate and derive a more permanent EDAM convergence bidding policy leading up to the two-year anniversary of EDAM operation,” it says. “The stakeholder process will permit for consideration of EDAM operational experience and EDAM entity readiness in deriving the convergence bidding policy design.”

CAISO has promoted the EDAM this year as an effort to bring greater cooperation to the balkanized Western Interconnection, which has more than three dozen balancing authorities.

SPP has been trying to do the same with its planned Markets+ day-ahead offering, which would eventually subsume participants in its real-time Western Energy Imbalance Service. The WEIS has had limited success competing with CAISO.

SPP, however, also plans to launch a Western edition of its Eastern RTO, called RTO West. Utilities in Rocky Mountain states have indicated interest in joining SPP, which has a reputation for including voices from multiple and varied regions of the South, Midwest and Great Plains states.

Legislative efforts to expand CAISO’s governance to include members from other states have been unsuccessful in the past, but increased competition and studies that have shown up to $2 billion in annual benefits from a Western RTO might help sway lawmakers. A California Assembly resolution passed last year asks CAISO to prepare a report on recent market studies for the Legislature when it reconvenes in early 2023.

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Va. Air Panel Votes to Exit RGGI

Acting on a promise by Gov. Glenn Youngkin (R), the Virginia Air Pollution Control Board voted Wednesday to withdraw from the Regional Greenhouse Gas Initiative (RGGI), an action likely to result in legal challenges.

The board voted 4-1 to approve a proposed regulation allowing Virginia’s exit from the 11-state cap-and-trade program, which it joined after the General Assembly mandated participation in 2020 (SB 1027). After a review of the proposed regulation by the executive branch, it will be published in the Virginia Register of Regulations with a 60-day public comment period.

In January, Youngkin issued an executive order requiring the Department of Environmental Quality to proceed with the withdrawal. The DEQ is required to consider public comments before writing a final regulatory proposal.

“With the board’s decision to proceed to public comment, we are one step closer to exiting RGGI and bringing relief to ratepayers,” said acting Secretary of Natural and Historic Resources Travis Voyles, who presented the proposal.

Youngkin’s four appointees to the air board supported the repeal. Three members named by former Gov. Ralph Northam (D) balked, with one voting “no” and two abstaining, saying it would require legislative approval to withdraw.

In a report in March, the Youngkin administration called RGGI a “direct carbon tax” on residents and businesses,  saying that none of the $300 million the state has received to date is being used to provide rebates to customers. (See Youngkin Report: RGGI a ‘Direct Carbon Tax’ on Va. Ratepayers.)

The air board’s vote was denounced by environmental groups.

“Participation in RGGI is a commonsense policy that reduces air pollution, keeps us on track to meet our climate goals, and provides necessary funding to address the flooding we see today and that we know will get worse in the coming years,” said Victoria Higgins, Virginia director for Chesapeake Climate Action Network. “Because of RGGI’s overwhelming public support, Youngkin failed to repeal this popular policy through the legislature. It is appalling that the governor has now turned to using unelected members of a citizen board to enact his extremist agenda. This transparently undemocratic and illegitimate attempt at repeal reveals the lengths to which Youngkin will go to drag Virginia backwards on climate.”

Nate Benforado, a senior attorney in the Southern Environmental Law Center, also questioned the board’s authority.

“The administration continues to march down this repeal path despite the fact it has no such authority to repeal this regulation,” he said. “The law requires Virginia’s participation in RGGI, and the administration must abide by the General Assembly’s decision. But equally troubling is the fact that the administration appears uninterested in listening to its own residents. The public overwhelmingly opposed this action, but the administration is poised to plow through this irresponsible and unlawful repeal, no matter what people say and no matter the harm to Virginia.”

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GridCONNEXT Digs into Grid-Telecom Convergence

WASHINGTON — The convergence of the electric grid and telecommunications system is inevitable, critical and underway, according to Commonwealth Edison (NASDAQ:EXC) CEO Gil Quiniones.

“There are a lot more intelligent devices that are installed on the grid, aside from integrating renewables, wind [and] solar,” Quinones told an audience of grid professionals at the gridCONNEXT conference, sponsored by the GridWise Alliance. “There are a lot of smart switches, voltage-optimization devices and other systems that are on the grid. Plus, our customers are having more intelligent building electrical systems. So how do you orchestrate [that]? That can only happen when there’s convergence between telecom and the power grid.

“We really need a new operating system and a new set of application software,” Quiniones said. “That’s starting to happen now, but we need to enable the technology.”

Convergence was a key theme at the two-day conference, with panels on Monday digging into the current state of the interfacing of grid and telecom, and utility information technology and operational technology systems.

“A smart grid needs smart communications,” said Chris Guttman-McCabe, chief regulatory and communications officer at Anterix (NASDAQ:ATEX), a broadband company focused on the utility sector. “What we’re seeing is an absolute necessity for broadband by utilities” to respond to a range of new challenges, from cyber and physical security, to the aggressive decarbonization and environmental justice goals a growing number of electric utilities are adopting.

Like Quiniones, he sees a core “need to rethink everything within your purview, including your communications platform.”

Systems convergence is part of the digitization of the grid that has accompanied its transformation from a one-directional system — “generation, transmission, distribution to load,” as Quiniones said — to a bidirectional system, in which the customer meter is an increasingly permeable interface.

ComEd has been “layering fiber on top” of its power system, Quiniones said. “We’re going to be able to control the devices that we have in place, and we’re doubling down on that, in combination with a wireless network. It’s probably the right business model for us and utilities going forward.

“It is important because there has to be system awareness and visibility; situational awareness and visibility,” he said. “There needs to be very fast communication and switching. All those devices need to talk to each other in milliseconds.”

“It’s also a way for us to isolate faults. If there are outages, we can quickly isolate them and keep many of our customers up and running,” he said.

Anterix has developed an ecosystem of software and applications developers working to integrate and leverage communications systems on the grid. One of its partners, Schweitzer Engineering Laboratories, has developed a system that can “de-energize a broken line before it hits the ground,” Guttman-McCabe said. “That capability wasn’t usable until it was integrated with high-speed, low-latency, dedicated broadband.”

Communications systems have also been an essential part of ComEd’s Bronzeville microgrid project, a community-level microgrid that can island from ComEd’s distribution system in an emergency and trade or share power with another microgrid at the Illinois Institute of Technology.

Such projects “need very fast sampling and time-synchronized decision-making,” Quiniones said. “When we integrate more renewables, when we have more electric vehicle charging stations, when we have more heat pumps [and] hot water heaters that are all going to have devices embedded in them that can communicate with the grid, you need a very robust communications system.”

A Safe Place to Innovate

Similarly, Justin Driscoll, interim president and CEO of the New York Power Authority, sees IT/OT convergence as integral to hitting New York’s aggressive decarbonization goals, such as cutting the state’s greenhouse gas emissions 85% by 2050.

“The integration of information technology systems and big data analytics are systematically allowing the digital information world to see, understand and influence the physical, operational world,” Driscoll said in his opening remarks at Monday’s second convergence-themed panel. “When implemented properly, IT/OT convergence can merge business processes, insights and controls into a single, uniform environment by allowing different technologies to integrate and interoperate efficiently as a single, cohesive system. …

“NYPA will take full advantage of technology and advanced analytics from the generator to the end user,” he said. “And this journey enables NYPA and its customers to leverage the full potential of an advanced technology environment in every aspect of the utility industry value chain.”

One example is NYPA’s “enterprise-wide Cybersecurity Awareness Program that spans both IT and OT environments to ensure that cybersecurity is baked into the culture of everything we do,” Driscoll said.

Adrienne Lotto, senior vice president for grid security, technical and operations services at the American Public Power Association, said IT/OT convergence has been an “ongoing journey” for the past decade. Drivers include the changing generation portfolio, integration of distributed energy resources and the evolution of utility business models, she said.

“The business is changing, and as a result we need more and more data about our operating efficiency, creating the controls, understanding the data points and then responding in a coordinated response perspective,” Lotto said.

Looking at the challenges ahead, Lotto said, “All of these data points have data that is feeding into the utility, and how are we going to manage all of that? How are we going to standardize all of that? How do we run analytics to solve all that, and how do we understand all that while our [industry] is growing, changing and advancing?”

Coming from the IT side, Russell Boyer, energy field director for Dell Technologies, said the goal going forward is to create standard or common platforms “that can take that data and turn it into insights so that we can accelerate” progress toward industry targets.

The challenges he sees are the different skillsets of workers on both the IT and OT sides, who historically have not worked together on a regular basis and may be resistant to learning new skills and processes.

“You’ve got to figure out how to create a safe place to do innovation,” Boyer said. “So that everybody [is] on board, all the stakeholders get together and start doing some testing so that they can understand what this process is going to deliver so that they can get to the buy-in and get on board and ultimately be a part of that solution and the innovation that needs to occur.”

A Different Digital Divide

The digitization of the grid has also opened up a new digital divide, said GridWise CEO Wayland. “For me, it’s bigger than internet access,” she said. “It’s about access to the grid that allows the customer to interact with the grid and allows the customer to understand their energy use” and even use their own DERs to participate in wholesale markets under FERC Order 2222.

Bridging that divide was one reason GridWise pushed hard to have funding for broadband expansion included in the Infrastructure Investment and Jobs Act. “The idea that communications are central to the grid and should be part of that infrastructure was not well understood” in Congress, she said.

Of the $65 billion for broadband in the bill, $1 billion is dedicated to “middle-mile” infrastructure, which helps to connect small or remote communities to larger broadband networks. Utilities, and in particular electric cooperatives, are eligible to apply for the middle-mile funds.

In Illinois, the passage of the Climate and Equitable Jobs Act last year means ComEd is planning its system by “what’s best for disadvantaged and underserved communities,” Quiniones said.

The utility has been deploying its own fiber networks to help ensure service to remote and underserved communities, and leasing out excess capacity to internet service providers, which can then provide “last-mile” connectivity, he said.

“We’ve actually applied [for] IIJA funding to kind of accelerate our deployment,” Quiniones said. “It’s beyond broadband. We want to make sure that our customers have access to all the other clean energy technologies that are going to be deployed, whether they are DERs or electric vehicle charging stations or just resiliency and reliability.”

Anterix sees broadband as a versatile “Swiss Army knife” for the grid, Guttman-McCabe said. It is “an underpinning for everything that any utility is facing: the need to aggregate and act upon data, the need to be more equitable with [the] distribution of energy opportunities and offerings … the need to bake in cybersecurity instead of bolting it onto your existing, antiquated communications systems,” he said.

“As a utility begins to contemplate digitization of their grid and all the sensors that are there, all of a sudden you can start to recognize cloud-based computing, machine learning and artificial intelligence, virtual augmented reality,” Guttman-McCabe said. “And with that comes an incredible range of opportunities for the utility, for customers, for rapid evolution of distributed energy resources.”

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MISO Staff Preview New LRTP Projects with Board

ORLANDO, Fla. — MISO staff on Tuesday gave their board a first look at its concept map of proposed projects under the second phase of its long-range transmission plan (LRTP), saying the new portfolio could cost up to $30 billion.

Stakeholders reacted with disbelief over the portfolio’s possible magnitude when MISO transmission planners unveiled the map last week. (See ‘Conceptual’ Tx Planning Map Troubles MISO Members.)

Aubrey Johnson, vice president of system planning, said the grid operator isn’t “married to” the hypothetical network of 345-kV and 765 kV-lines and an HVDC line across Lake Michigan, but engineers “needed a place to begin work from.”

MTEP 22 report cover (MISO) Alt FI.jpgMISO’s MTEP 22 report cover | MISO

“This is an initial draft,” he said Tuesday during the board’s System Planning Committee meeting. “We view this as a directional starting point.”

Johnson reminded board members that in early 2021, staff warned them that it could require up to $100 billion in new transmission over the next few years for members to achieve their renewable generation additions and carbon-cutting goals. They said the first LRTP, based on the most conservative transmission planning future, could cost up to $30 billion. However, the resulting portfolio cost a little more than $10 billion. (See MISO Board Approves $10B in Long-range Tx Projects.)

“The billion-dollar question, I’m sure, is what it might take. This [portfolio] could be anywhere from $20 to $30 billion to achieve what we think is necessary” under MISO’s moderate second planning future, Johnson said.

Board members worried aloud that the RTO isn’t refreshing its future load assumptions as often as it does with generation predictions.  

Alliant Energy’s Mitch Myhre, representing transmission-dependent utilities, said his sector was alarmed by the second LRTP portfolio’s potential scope and cost. He said MISO should consider non-transmission alternatives, synchronous condensers, and other transmission-enhancing technologies under the second LRTP plan.

Southern Renewable Energy Association’s Andy Kowalczyk asked MISO leadership and board members to consider moving up LRTP planning for MISO South. The grid operator is looking at the Midwest region in the first two of four LRTP portfolios.

MISO’s 2022 interconnection queue cycle currently holds 956 generation project submissions totaling 171 GW. More than 96% of those projects are renewable or storage. (See MISO Insists it can Handle Record-setting Interconnection Queue.)

“What sets this year apart is just the record number of requests,” MISO’s Andy Witmeier said.

The project submittals are a 128% increase over 2021’s 77 GW of nameplate capacity submissions. Witmeier said that the Inflation Reduction Act’s approval and MISO’s first LRTP portfolio spurred the increase in generation plans.

MISO has released the first two requests for proposals associated with its first LRTP portfolio: a 345-kV line on the Indiana-Michigan state border and the Denny-to-Fairport 345-kV on the Iowa-Missouri border.

MTEP 22 Winds Down

Board members on Thursday unanimously cleared the way for work to begin on MISO’s $4.3 billion, 382-project 2022 Transmission Expansion Plan (MTEP 22). (See MISO’s $4B MTEP 22 Clears 1st Board Vote Despite Criticisms.)

No members took advantage of a public comment period before the vote on the annual plan.

Since MTEP 03, $32 billion in transmission investment has gone into service; another $23 billion remains under development, including the first LRTP.

With MTEP 22 in the rearview mirror, expedited project submittals under MTEP 23 are already accumulating.

Entergy submitted two expedited review projects for MTEP 23 before MTEP 22 was formally approved. MISO found no harm in Entergy Texas’s work on two 138-kV substations in East Texas to accommodate industrial load growth. The utility will commence with a customer’s new, $28 million substation and $10 million in upgrades to another substation, adding a 12 MW load capability and 25.1 MVAr capacitor bank.