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November 5, 2024

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MISO Officials Explain 2022/23 Capacity Auction Mechanics

MISO officials this week answered questions about the more confusing aspects of the Midwestern shortfall and expensive prices in last week’s capacity auction while stakeholders asked for more supply data from before the auction.

The RTO’s 2022/23 Planning Resource Auction (PRA) resulted in the Midwestern zones, 1 to 7, being deficient by 1.2 GW of their collective planning reserve margin requirements and clearing at the $236.66/MW-day cost of new entry (CONE). (See MISO’s 2022/23 Capacity Auction Lays Bare Shortfalls in Midwest.) However, on the zonal level, only zones 4 to 7 — which include parts of Illinois, Lower Michigan, Indiana, Missouri and western Kentucky — couldn’t meet their local clearing requirements, and they couldn’t find extra supply from the other Midwestern zones.

MISO’s transfer limits between its subregions also kept the Midwest from accessing additional supply from the South that could have counteracted the regional capacity shortage.

Eric Thoms, MISO senior manager of resource adequacy operations, said the RTO’s auction clearing engine uses subregional resource zones and includes the marginal cost of a binding subregional flow limit in prices. In the case of this year’s auction, the South-to-North transmission limit bound. MISO used a 1,900-MW South-to-North limit and a 3,000-MW North-to-South transfer limit in the auction. The RTO begins with the usual 3,000-MW southbound and 2,500-MW northbound limits and subtracts firm service contracts to arrive at the transfer limits used in the auction.

MISO also used Zone 3’s $236.66/MW-day CONE to price the entire Midwest because it is the cheapest of the CONE prices, and the auction is designed to apply the lowest CONE when an entire region is short. The CONE values differ by zone because the cost of building new generation varies regionally.

“The objective of the multi-zone optimization methodology is to minimize the overall costs of capacity,” Thoms explained to stakeholders in a Resource Adequacy Subcommittee teleconference Wednesday.

Stakeholders asked MISO to telegraph a better feel of supply in the weeks and months leading into the auction. They said there was a large delta between confirmed unforced capacity and what was ultimately converted into zonal resource credits. Ahead of the 2022/23 planning year, MISO anticipated a 121-GW coincident systemwide peak, with 157 GW in total installed capacity and just short of 128 GW in total unforced capacity to cover it.

Stakeholders asked if MISO could have disclosed a level of accelerated suspended or retired megawatts ahead of the auction so market participants could have reacted and made more supply available.

Apex Clean Energy’s Richard Seide said the auction results were “astonishing.”

“I know things were getting tight, but if you read the data going into this year’s auction, you didn’t think it was going to go this way by a few hundred megawatts. You thought we were going to slide by again,” Constellation Energy’s John Orr said.

MISO Director of Resource Adequacy Coordination Zakaria Joundi said that while the RTO can’t reveal unit-specific data, it is reviewing the usefulness of the preliminary PRA data it posts.

“I think the process should be more transparent, so that choices to bring more capacity to the market can be viable,” Power System Engineering’s Tom Butz said.

Taylor Martin of the Independent Market Monitor, Potomac Economics, said the IMM tries ahead of time to project what will be unavailable but is bound by multiple confidentiality rules. But he said the Monitor found no evidence of economic or physical withholding.

Thoms also said no market participants this year elected to pay a capacity deficiency charge to MISO. According to MISO rules, load-serving entities can opt to pay out all or a portion of their planning reserve margin requirement.

The auction results are emblematic of the tricky situation MISO faces in navigating its members’ portfolio transition.

The 2022/23 capacity results brought longstanding criticisms of MISO bubbling back to the fore, including its lack of sturdier transmission connections between its South and Midwest regions, a bevy of thermal generation retirements and MISO’s use of a vertical demand curve over a sloped demand curve in the auction.

MISO said members in recent years have been replacing retiring thermal generation with even more megawatts from new intermittent resources.

The auction results come as Consumers Energy — Michigan’s largest electric utility — and stakeholders this week announced that they reached an agreement to close all coal plants by 2025, which could make it one of the first large utilities in the nation to eliminate coal use. The proposal still needs the blessing of the Michigan Public Service Commission. (See Consumers to End Coal by 2025 in IRP Deal with Mich. AG.)

Michelle Bloodworth, CEO of coal lobbying group America’s Power, said EPA’s recent crackdown on coal ash could also idle a little more than 2 GW of coal-fired generation in MISO Midwest as early as the fall. She said MISO should also factor that development into its supply picture.

Stakeholders said it seemed that a lot of the new capacity that MISO and the Organization of MISO States were expecting per their annual resource adequacy did not manifest. Some wondered if the RTO needs to recalibrate its expectations of generation that will complete the interconnection process.

Monitor: Sloped Demand Curve, Please

Monitor David Patton said the auction shortage reinforces the need for a sloped demand curve in the auction, a call he’s been making for 12 years now.

During the Market Subcommittee’s meeting Thursday, Patton said MISO undervalues capacity, sending “bad signals” to market participants. He said MISO’s long history of “near-zero” clearing prices spur too-early unit retirements.

Zonal clearing prices (MISO) Alt FI.jpgZonal clearing prices in the 2022/23 MISO capacity auction | MISO

 

“Since 2019, MISO lost almost 5 GW of capacity in the Midwest that would have been economic if the PRA had set efficient clearing prices,” he said. “Most of these retirements were by unregulated merchant suppliers that rely on the market signals to make investment and retirement decisions.”

2nd Regional Resource Assessment in the Works

MISO will pull together another long-term resource assessment by the end of this year, this time with assistance from its members.

Last year’s first regional resource assessment showed a need for members to add almost 140 GW of new capacity within the next 20 years. (See MISO Resource Assessment: 140 GW Needed Within 20 Years.)

Last year, MISO relied only on public data it independently searched. The regional resource assessment this year will include data sourced directly from members to get a better picture of protracted resource trends. The RTO said it has collected generation information from 75% of its load for the 2022 assessment.

MISO said preliminary results show a lower level of nuclear retirements 20 years out; net neutral natural gas retirements and additions over two decades; and the same 35 GW of coal plant retirements by 2040 that it originally expected last year. It also foresees a 65% reduction in emissions from 2022 levels by 2040.

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ISO-NE Defends Order 2222 Filing

ISO-NE defended its Order 2222 compliance filing on Wednesday, providing FERC its response to protests from environmental groups, renewable energy industry organizations and Massachusetts’ attorney general.

ISO-NE’s response to the federal order requiring RTOs to allow distributed energy resources to participate in wholesale markets has frustrated advocates, who say it fails to meet the goals laid out by FERC and would limit the availability of behind-the-meter resources to engage the market. (See ‘Beautiful Symphony’ or Bust on Order 2222, Advocates Say)

That frustration led to a number of protests arguing, among other things, that the order doesn’t allow sub-metering, gives utilities too much time to review aggregated DER proposals and that its seven participation models for DERs proposed by ISO-NE aren’t in compliance with Order 2222. Among those protests was a combined filing from environmental groups and another from several industry organizations.  

FERC’s rules technically don’t allow ISO-NE to file an answer to protests, but the grid operator is asking for an exception.

In its filing, ISO-NE argues that it has fully met the requirements of the FERC order.

Metering

Order 2222 gave RTOs flexibility in how they can establish market rules for metering DERs, ISO-NE said in its response.

And the alternatives that advocates proposed in their protests could lead to double counting of services, shift costs to customers without DERs and require new metering infrastructure, the RTO argues.

The filing also cites a previous FERC order in saying that metering at the retail delivery point (as proposed in the compliance filing) is appropriate for demand response resources, rather than the device-level sub-metering proposed in the protests.

And finally, it says FERC should reject the intervenors proposal to allow third-party metering because of double counting and data validation issues.

Utility Review

The protestors also challenged ISO-NE’s rule giving utilities 60 days to review DERs seeking to participate as part of an aggregation.

FERC’s order specifically allowed a 60-day review period, ISO-NE wrote, so the environmental groups’ request to shorten it should not be granted.

It gave a similar response to the industry groups’ proposal that the period for utilities to review the modification of DERAs be shortened.

Participation Models 

Perhaps most significantly, ISO-NE defended its seven participation models for DERAs wishing to take part in the models.

“The standards and requirements associated with each participation model in the Compliance Proposal are tailored to the products and services offered in the New England Markets,” ISO-NE argued, and they meet the requirements of Order 2222.

Specifically, the response provides defenses of ISO-NE’s continuous storage facility model, its settlement-only DERA model and changes to the existing Alternative Technology Regulation Resource.

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Rhode Island Advocates Hold out Hope for Stalled Clean Energy Policies

Members of the public asked Rhode Island’s climate leaders Tuesday to elevate the policies of three stalled energy-related bills as priority actions for reducing the state’s greenhouse gas emissions.

They said that the policies, which support energy storage and renewable energy deployment, should be a part of the state’s next plan for emission reductions in the electric sector.

Top among the policy priorities was a 100% renewable energy standard (RES) bill (H.7277) that was introduced in February and held for study in March by the House Environment and Natural Resources (ENR) Committee.

Passing a 100% RES by 2030 would be “really helpful,” Greg Gerritt, former executive director of the Environment Council of Rhode Island, said during the Executive Climate Change Coordinating Council (EC4) listening session. Amy Moses, general counsel for Utilidata, echoed Gerritt’s comment, saying that the standard is “critical” for the state.

EC4 hosted the electric sector-focused event as part of a series of listening sessions this year that will inform a legislatively mandated update to the state’s 2016 GHG Emissions Reduction Plan. A 2020 executive order from former Rhode Island Gov. Gina Raimondo put the state on a path to achieving 100% renewable energy, but it has yet to be codified.

Under the existing state RES, 19% of retail electricity supply must come from renewable sources this year, and the state had reached 12% of supply in 2020, according to U.S. Energy Information Administration data.

The Rhode Island Office of Energy Resources (OER) completed a 100% renewable energy study last year that recommended advancing an RES-like mechanism along with enabling actions, such as integrated grid planning, strategic energy storage deployment and regional collaboration on wholesale markets.

Gov. Dan McKee supported the RES bill in March 10 testimony for an ENR bill hearing, saying that the state needs a “largely carbon-free electric generation portfolio” to reach net-zero emissions by 2050. While the bill also received broad support from environmental groups and residents during the hearing, the Northern Rhode Island Chamber of Commerce urged the committee to gather insights from ISO-NE before adopting a mandate to accelerate renewables on the electric grid.

ENR still has the option of considering the RES bill again before the end of the session in June.

Rooftop Solar Cap

Eliminating current size requirements for solar rooftop systems should be an RES-enabling policy in the EC4’s emission-reduction plan update, according to Hank Webster, senior policy advocate and Rhode Island director at Acadia Center.

“We would like to see incentives for prioritizing rooftop solar throughout the state and removal of the cap on rooftop solar,” he said.

The House Corporations Committee took testimony March 1 on a bill (H.7333) that would remove size limitations on net-metered systems, but the committee voted to hold it for study.

In hearing testimony, the Division of Public Utilities and Carriers said the current limit ensures that a rooftop system meets on-site energy needs and protects ratepayers from the costs of “overly large systems.” National Grid also opposed the bill in its testimony, saying that net metering should not make rooftop solar a “revenue stream” for building owners.

Homeowners, however, should have the option to build larger systems that complement neighborhood-level demand or support peak grid demand, Webster said.

Energy Storage

An energy storage bill that the Corporations Committee held for study April 12 represents another priority policy that Webster says should be in the GHG plan update.

The bill (H.8026) would set an energy storage capacity goal for the state of 500 MW by 2032 and direct OER to develop programs and associated funding mechanisms to advance system deployments.

Sunrun supported the bill in hearing testimony, saying energy storage has a “critical role” to play in building a 100% zero-carbon electric grid in the state. The Public Utilities Commission, however, said a legislatively mandated storage compensation program, as proposed in the bill, could be more expensive than current market-based solutions and warrants further study.

Webster said that the 2022 GHG plan, which is due in December, should support a pathway to understanding where energy storage resources are needed across the region and where they can feed the distribution system.

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FERC Tells PacifiCorp to Refund Premiums

FERC told PacifiCorp this week that it must repay premiums it earned on wholesale electricity sales during the August 2020 Western heat wave that forced CAISO to order rolling blackouts and pushed prices sky-high in other parts of the West (ER21-60).

PacifiCorp received premiums on top of the spot market’s average index prices at Arizona’s Palo Verde trading hub on Aug. 18-19, 2020, when CAISO was struggling to prevent more blackouts like those it ordered Aug. 14-15, and the Western grid was strained by record triple-digit temperatures. (CAISO Blames Blackouts on Inadequate Resources, CPUC.)

Palo Verde wholesale prices on the Intercontinental Exchange (ICE) reached a record $1,515/MWh on Aug. 18 and $1,750 on Aug. 19, according to data posted by the U.S. Energy Information Administration. (The average price at Palo Verde from June to August 2020, excluding the high prices of Aug. 18-19, was $52/MWh, Southern California Edison and Pacific Gas & Electric said in FERC filings.)

Prices outside CAISO in the West fall under the Western Electricity Coordinating Council’s (WECC) soft price cap of $1,000/MWh, which requires sellers to justify prices above the cap to FERC or to issue refunds. The process, instituted in response to the California energy crisis of 2000-01, is meant to avoid the exercise of market power.

Prices above the cap can be justified based on three frameworks — a production cost-based framework, an opportunity cost-based framework or an index-based framework — FERC said in guidance it issued in June 2021. (See FERC Offers Guidance on Exceeding Western Price Caps.)

FERC found that PacifiCorp had justified its prices on Aug. 18-19 using the index-based framework, in which a seller cites an index at a specific trading hub to justify prices that exceed WECC’s soft cap. But FERC said the utility had failed to justify premiums it received above the index prices.

PacifiCorp defended the premiums by arguing it had seven bilateral spot market sales in August 2020 that exceeded the $1,000/MWh price cap. Four were brokered day-ahead transactions, with the price set by the buyer based on the Palo Verde day-ahead ICE index, and three were “direct transactions with counterparties that contacted PacifiCorp,” the commission said.

“PacifiCorp [contended] that, to the extent the prices reflect a premium over the prevailing index price, the premium was set by the customer, and PacifiCorp had no visibility into the prevailing index price for these transactions until after the ICE day-ahead market closed,” FERC wrote. “PacifiCorp notes that it served as a price-taker, which it argues the commission has recognized addresses any concern about the legitimacy of price formation.”

The premiums, which raise the cost of wholesale electricity marginally above the index price, usually are added by customers to “secure energy during times of scarcity,” the utility said.

FERC rejected the argument that the adders were justified.

“The Palo Verde price index already reflects scarcity conditions,” it said. “PacifiCorp’s attempt to justify prices above the soft cap by arguing it was a price-taker is insufficient.”

“In these circumstances, the index-based framework only justifies prices up to the index price and … any premiums above the index must be justified in other ways, which PacifiCorp failed to do,” FERC said. “Accordingly, we find that PacifiCorp has not provided adequate justification for the premiums above the index price.”

The commission directed the utility to refund the premiums to buyers within 30 days and report back to the commission in another 30 days. The decision did not cite specific amounts of the premiums or the total amount that could be at stake.

Four of the five FERC commissioners signed the order.

Commissioner James Danly issued a dissent in which he said FERC was meddling with contracts to sell electricity at market-based rates.

“I would … not require PacifiCorp to pay refunds for the ‘premium’ amount above the price index that PacifiCorp and the willing buyers freely negotiated because no showing has been made that the public interest is seriously harmed by the contract rate,” Danly wrote.

With its decision, FERC was putting sellers in an unworkable position, he said. The commission requires wholesalers to sell electricity, or it will investigate them for withholding and market manipulation, but then it negates market-based prices, he said.

“The de facto result is that we require PacifiCorp to sell, and then we require them to sell at our preferred price,” Danly said. “No wonder there seems to be no end in sight to the supply shortage in California and, increasingly, the Western United States.”

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CISA Issues Fresh Russia Cyber Warnings

The U.S. Department of Homeland Security’s Cybersecurity and Infrastructure Security Agency (CISA) joined the FBI and National Security Agency — along with security agencies in the U.K., Australia, New Zealand and Canada — on Wednesday to release a report detailing the cyber threats against critical infrastructure that have been detected in connection with Russia’s invasion of Ukraine.

The report, “Russian State-Sponsored and Criminal Cyber Threats to Critical Infrastructure,” presented hostile cyber activities by a host of Russian government agencies, including the Federal Security Service (FSB), Foreign Intelligence Service (SVR), Main Intelligence Directorate (GRU) and Central Scientific Research Institute of Chemistry and Mechanics (TsNIIKhM). Attacks could come “as a response to the unprecedented economic costs imposed on Russia, as well as materiel support provided [to Ukraine] by the United States and U.S. allies and partners,” the report said.

Veteran Cyber Units Hard at Work

Each Russian agency has been linked to previous cyber incidents: Just last month the Justice Department announced it had indicted agents of TsNIIKhM and the FSB for a series of cyberattacks against the global energy industry. (See DOJ Reveals Indictments Against Russian Energy Hackers.) GRU’s Unit 74455 — which analysts have variously dubbed Sandworm, Electrum and Voodoo Bear — is believed to have carried out attacks around the world, including against the Winter Olympics in 2018 and the Ukrainian power grid in 2015 and 2017. (See Six Russians Charged for Ukraine Cyberattacks.)

Industroyer, another breed of malware linked to Unit 74455 that knocked out 20% of Ukrainian capital Kyiv’s power grid in 2016, was back in the news recently after Ukraine’s Computer Emergency Response Team reported discovering a very similar attack underway last week. Like the earlier threat, the new “Industroyer2” hack appeared designed to attack the industrial control systems used by electric utilities; however, in this case the attack was stopped before any damage could be done. (See E-ISAC Warns of Escalating Russian Cyber Threats.)

Along with these officially government-linked groups, the report identified two malicious actors as “aligned” with Russia but not definitely known to be employed by its government. The first, dubbed Gamaredon or Primitive Bear, has “targeted Ukrainian organizations since at least 2013,” including multiple operations before Russia’s invasion. The other, known as Venomous Bear or Turla, “is known for its unique use of hijacked satellite internet connections” to attack NATO-aligned governments, defense contractors and “other organizations of intelligence value.”

Nominally independent cybercrime groups are another growing threat, the report said, with some gangs pledging support for Russia’s government and threatening to “retaliate against perceived attacks against Russia or materiel support for Ukraine.” Among the groups identified by code name is Wizard Spider, responsible for the Conti ransomware that has targeted more than 1,000 organizations worldwide. Other groups historically have focused more narrowly on the Ukrainian government.

Cybercrime gangs tend not to have the direct support of Russia’s government, even when based in the country; rather, law enforcement often turns a blind eye to their activities as long as they are directed against Russia’s perceived adversaries. The agencies noted that even for the groups that have promised to support Russia’s war in Ukraine, their primary motivation and mode of attack are likely to remain financial rather than participating in government hacking operations.

Warnings Becoming More Urgent

CISA has been in a “Shields Up” posture since Russia’s invasion began in February, calling for critical infrastructure operators to be vigilant for potential cyber interference. Though the agency initially said it had seen “no specific or credible cyber threats to the U.S. homeland,” it and other federal entities — including the White House — have issued more pointed warnings as the conflict wears on and Russia’s military seemed increasingly unlikely to score a clear victory on the battlefield, making a cyber escalation more probable.

“We know that malicious cyber activity is part of the Russian playbook. We also know that the Russian government is exploring options for potential cyberattacks,” CISA Director Jen Easterly said in a release. “We urge all organizations to review the guidance in this advisory as well as visit [CISA’s website] for continually updated information on how to protect yourself and your business.”

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FERC Opens Probes on Western Transmission Rate Protocols

FERC on Thursday ordered show cause proceedings on the transmission formula rate protocols of five Western utilities, saying they do not appear to provide customers and regulators the ability to challenge rates resulting from the formulas.

The commission opened proceedings under Section 206 of the Federal Power Act on the formula rate protocols of PacifiCorp (EL22-38), Idaho Power (EL22-37), Puget Sound Energy (EL22-41), Public Service Company of New Mexico (EL22-40) and Public Service Company of Colorado (EL22-39) (NASDAQ: XEL).

The commission said the companies’ rate protocols did not meet the standards it has required since a 2012 order regarding MISO’s transmission owners.

Under formula rates, the commission does not require transmission owners to make FPA Section 205 filings to update their annual transmission revenue requirements. Instead the utilities update the input data in the formulas.

“Safeguards need to be in place to ensure that the input data is correct, that calculations are performed consistent with the formula, that the costs to be recovered in the formula rate are reasonable and were prudently incurred, and that the resulting rates are just and reasonable,” FERC said.

“Formula rate protocols provide the parties paying for transmission service specific procedures for notice of, review of, and challenges to the rates that they will be charged. In order to fulfill this purpose, formula rate protocols must afford adequate transparency to affected customers, state regulators or other interested parties, as well as provide mechanisms for resolving potential disputes.”

The commission’s orders Thursday found that each of the five utilities’ protocols fell short on one or more of the following:  “(1) the scope of participation (i.e., who can participate in the information exchange); (2) the transparency of the information exchange (i.e., what information is exchanged); and (3) the ability of customers to challenge transmission owners’ implementation of the formula rate as a result of the information exchange (i.e., how the parties may resolve their potential disputes).”

In the 2012 MISO order, the commission ruled that the MISO’s protocols inappropriately limited who could participate in the review processes and directed MISO and the transmission owners to revise them to include all interested parties, including customers under the MISO tariff, state utility regulatory commissions, consumer advocacy agencies and state attorneys general (143 FERC ¶ 61,149).

Similarly, the commission said Thursday that PacifiCorp’s protocols do not define the term “interested party” to identify who is eligible to participate. “Without such a definition, PacifiCorp’s formula rate protocols may not provide sufficient clarity and may provide PacifiCorp with the discretion to determine who is an interested party, and therefore appear to be unjust and unreasonable,” the commission said.

In the Puget Sound order, the commission said the utility’s protocols regarding challenge procedures lacked “straightforward and defined procedures” or “the level of specificity required” in the MISO standard.

It ordered each of the utilities to respond within 60 days to either show cause as to why its protocols remain just and reasonable or explain what changes it will make to remedy the commission’s concerns.

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FERC Fines NY Hydro Operator $600K for Safety Violations

FERC on Thursday ordered the former operator of an upstate New York dam to pay $600,000 in civil penalties for failing to make needed repairs over six years and retain possession of all property needed to access the facility (P-9685-034).

Ampersand Cranberry Lake Hydro has 60 days to pay the fine for violating its hydroelectric license for the Cranberry Lake Project, located in St. Lawrence County, N.Y.

The project is owned by the Oswegatchie River-Cranberry Reservoir Regulating District Corp. (OR-CRRDC), a state municipal corporation. It includes a 57,400-acre-foot reservoir contained by dam that is 195 feet long and 19 feet high.

“The dam has a high hazard potential rating, which means that a failure of the project works would result in a probable loss of human life or economic or environmental losses,” FERC said.

Under FERC rules, hydro licensees are required to maintain property rights to their projects to provide access to the land associated with a dam in order to make repairs when necessary.

“In this particular case, Ampersand didn’t maintain those access rights. And thus, if something does go wrong or might go wrong, they don’t have the ability to access the site to make repairs that are necessary,” FERC Chairman Richard Glick said in a statement Thursday. “And this particular dam is classified as having a high hazard potential, so that’s something that we take very seriously.”

Thursday’s order follows an October 2021 commission issuance directing Ampersand Cranberry Lake to explain why it should not be assessed a civil penalty for violating its hydroelectric license and a November response by the company acknowledging that it failed to retain possession of all project property, in violation of its license. (See FERC Hits NY Hydro Plant for Delayed Repairs.)

FERC granted Ampersand Cranberry a license for the project in 2015 after the company promised to complete safety work related to the facility’s fuse plug spillway in the dam’s embankment and to raise the earthen embankment crest. The company notified the commission last July that it had agreed to terminate its lease and give up access rights to the project site to settle litigation with OR-CRRDC, which sued the company in 2019 over its failure to make rent payments.

FERC said the settlement came despite its repeated warnings that terminating the lease would violate the company’s license and would not relieve it of its responsibility to complete the outstanding work on the dam.

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MISO Stakeholders Insist on Consistency in Capacity Accreditations

Stakeholders told MISO Wednesday it should use a consistent capacity accreditation process for both its conventional and non-thermal generators.

The request comes as MISO is evaluating new accreditation options for non-thermal generation. The RTO filed with FERC late last year to change its accreditation for conventional resources to a seasonal value based on a unit’s past performance during tight conditions. The new accreditation is contained in a larger filing to create four seasonal capacity auctions (ER22-495). (See Deficiency Notices for MISO’s Seasonal Capacity Auctions Bid.)

At the time, MISO elected to wait to propose a new accreditation for its other, intermittent generating units.

Now, MISO is evaluating three accreditation options for non-thermal resources:

  • Expanding its effective load carrying capability (ELCC) calculation, currently in use for wind generation, to include solar generation and other intermittent resources;
  • Using an availability-based accreditation based on generator performance during “resource adequacy hours” — tight margin and emergency periods — over four historical planning years. That accreditation style is pending before FERC for MISO’s conventional resources; or
  • Employing a blend of ELCC and an availability-based accreditation.  

The blended approach would have MISO identifying seasonal risky hours in addition to running a loss of load expectation (LOLE) analysis to identify possible shortfall events. MISO said it will “develop windows of risk for each season by combining resource adequacy hours and LOLE events.” Capacity credits would be issued based on generator performance during the combined risk periods.

Stakeholders attending an April 20 Resource Adequacy Subcommittee (RASC) teleconference said they want comparability across accreditation of thermal and non-thermal resources. They said if thermal resources are going to be valued based on their historical contributions during times of system need, non-thermal resources need to be as well.

WEC Energy Group’s Chris Plante questioned why MISO considers ELCC “good enough” for intermittent resources but not for conventional resources.

“Why are we making a distinction between intermittent and conventional resources when, at the end of the day, we’re trying to determine the same thing?” he asked.

“We don’t need to have apples-to-apples, but we at least need a fruit salad. We can’t be throwing onions in,” Clean Grid Alliance’s Natalie McIntire said.

MISO staff said they’re still considering accreditation designs. The RTO plans to hold a special workshop sometime in June and set a direction on a new accreditation in July. It said it will work on a design with stakeholders through the end of the year.

During the March RASC, McIntire encouraged MISO to pursue an entire rethink of its resource adequacy construct instead of developing a new capacity accreditation for intermittent resources. Other stakeholders have also asked MISO to assess the entirety of its resource adequacy construct.

MISO’s Scott Wright told stakeholders the accreditation redesign for non-thermal resources is only a piece of the reforms MISO envisions needing as the resource mix transitions away from centralized, baseload generation.

“This is not the end or a destination,” Wright said.

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New York TOs Again Defend Local Tx Project Rights

New York transmission owners on Wednesday again rejected challenges to their new public policy category of local transmission development for purposes of cost sharing and recovery (Case No. 20-E-0197).

The NYTOs, including state investor-owned utilities, the New York Power Authority (NYPA) and the Long Island Power Authority, told state regulators that LS Power, the Alliance for Clean Energy (ACE-NY), and New York City were mistaken in their concern with the NYTOs’ proposed cost sharing and recovery agreement (CSRA) for so-called phase 2 projects.

Phase 1 projects are traditional utility investments that address system reliability or resilience issues, while phase 2 projects are investments made primarily to satisfy requirements of the Climate Leadership and Community Protection Act (CLCPA).

The NYTOs in January had urged the Public Service Commission to reject LS Power’s argument that costs of local transmission can only be allocated under the NYISO tariff’s Order No. 1000 processes and that any regional cost allocation is preempted by FERC’s exclusive jurisdiction over transmission. (See New York TOs Defend New Public Policy Tx Category.)

This month, the NYTOs rejected LS Power’s insistence that phase 2 projects must go through NYISO’s public policy transmission planning process: “Transmission projects identified through each NYTO’s local planning process have never been subject to the NYISO PPTPP or its competitive solicitation process and are properly within each NYTO’s planning authority.”

Forcing project development through the ISO would only serve to address bulk power transmission facility needs, not local system capacity shortfalls, the NYTOs said.

Under Order No. 1000, regional transmission facilities are those that must be regionally planned, competitively selected and eligible for regional cost allocation.

ACE-NY and the City

ACE-NY asked the PSC to establish a cost containment mechanism for phase 2 projects, a request the NYTOs said should be rejected as being outside the scope of the proceeding.

The NYTOs said they balanced competing interests in developing a voluntary CSRA under the basic premise that incurred costs of projects approved by the commission would be recoverable.

Regulators will use the cost recovery mechanism for only those projects approved as meeting the statutory objectives under the CLCPA, including a pre-determined rate of return and capital structure, the NYTOs said. The CSRA, they added, does not provide for pre-approval of all project costs. In addition, the PSC and all interested parties reserve the right to contest project costs incurred by the sponsoring NYTO, and therefore it would be inappropriate to impose generic involuntary cost caps.

New York said it is concerned about inconsistency between the CSRA and the rate schedule, according to the city’s Feb. 8 comments in the proceeding. Regarding cost recovery for NYPA customers, the NYTOs contend that under the CSRA, NYPA “will be allocated costs of approved transmission projects in the same manner as other [load serving entities] under rate schedule 18,” and that the rate schedule does not apply to NYPA, the city noted in its comments.

The CSRA and rate schedule, however, are correct, according to the NYTOs.

A provision of the CSRA relating to NYPA as a load-serving entity “recognizes NYPA’s customers will be responsible for CSRA-related costs to the same extent as other end-use customers in New York served by a load serving entity,” the NYTOs said.

NYPA said it will not use the CSRA or accompanying rate schedule to recover the costs of its transmission projects for the following reasons:

  • NYPA does not have a retail service area or local transmission and distribution system and therefore, under the Accelerated Renewables Act, will not be developing phase 2 projects for inclusion in the utilities’ capital plans, and
  • NYPA uses the NYPA transmission adjustment charge, which already allocates those costs state-wide, to recover its transmission embedded costs.
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Washington Looks to Boost Prospects for Winning Hydrogen Hub

Washington officials are seeking to bolster the state’s case to land one of the nation’s federally funded hydrogen hubs.

Gov. Jay Inslee and Lisa Brown, director of the Washington Department of Commerce, have been working in recent months to coordinate the state’s activities in seeking a piece of an $8 billion U.S. Department of Energy fund to create regional hydrogen hubs to produce and distribute the fuel for industrial and transportation applications.

“This is a ruthless competition nationwide. It’ll be political malpractice not to leave everything on the field,” state Sen. Reuven Carlyle (D) said at the Future of Carbon Policy Forum held at Seattle’s Space Needle last week.

Speaking at the forum, Rep. Kim Schrier (D-Wash.) said roughly 80 proposals will likely be whittled down to four to eight regional hubs, translating into $1 billion to $2 billion for each.

On Feb. 24, Inslee sent a letter to dozens of state agencies, utilities and private companies saying that Washington stands a good chance to host one of the hubs, citing the state’s extensive efforts in in combating greenhouse gas emissions.

“Washington has the lowest carbon intensive grid in the United States. The opportunity to develop truly green hydrogen and understand how it fits into a modern decarbonized economy is possible today in the state of Washington. No other region is as advanced in this area,” Inslee wrote.

He pointed to several utilities and private companies in Washington that are already delving into hydrogen production reduction or use. These include Microsoft, Amazon, PACCAR — which is building hydrogen-fueled semi-trucks — and the Port of Tacoma and Douglas County Public Utility District, which are exploring manufacturing hydrogen. Washington State University and the Pacific Northwest National Laboratory are also conducting hydrogen-related research.

The Douglas County PUD is the farthest along, building a $25 million hydrogen plant expected to go online in late 2022 or early 2023. (See Wash. PUD Breaks Ground on Hydrogen Plant.)

In an interview with NetZero Insider, the PUD’s General Manager Gary Ivory said that while no contracts have yet been signed for the output from the plant, potential customers have expressed interest in more hydrogen than the planned facility would be able to produce. Douglas County has more land set aside to expand the operation after construction of the original plant is complete.

In an April 4 letter to the same organizations addressed by Inslee’s letter, Brown wrote that the state, utilities and private companies recently created the Pacific Northwest Hydrogen Association, which is expected to coordinate hub-related efforts starting in May. In its 2022 session, the state legislature allocated $2 million to those efforts.

Lawmakers this year also passed a bill (SB 5910) establishing the Office of Renewable Fuels within the Commerce Department to support the development of renewable fuel and electrolytic hydrogen projects. (See Green Hydrogen Bill Passes Wash. Legislature.)

In her letter, Brown noted that the legislature also recently expanded the responsibilities of the state’s Energy Facilities Site Evaluation Council, giving the agency siting authority over renewable fuel projects. Lawmakers also created tax breaks for renewable energy projects if they met specific labor hiring standards, Brown wrote.