Page 1096 – RTO Insider

October 11, 2020

MISO Market Subcommittee Briefs: Oct. 8, 2020

MISO has at once rebranded and postponed its attempt to develop more sophisticated modeling software that can accommodate different combinations of combined cycle units and their dependencies.

The delay marks the third time MISO has pushed back an effort at combined cycle generation modeling. It also renamed the more involved process “multiple configuration resource” modeling.

MISO Director of Business and Digital Transformation Dhiman Chatterjee announced the further delay during an Oct. 8 Market Subcommittee call. MISO projects it will be able to model combined cycle interdependencies sometime late in 2025 at the earliest.

MISO first planned to put improved combined cycle modeling in place by 2020, then delayed until 2022, and again into mid-2023. The RTO said its current market platform couldn’t technically handle the software. (See “At Least 1 Market Project Delay,” New MISO Platform Headed to the Cloud.)

MISO now says General Electric is delaying delivery of a new market clearing engine beyond original expectations, making combined cycle modeling an even more distant prospect.

Chatterjee also said MISO experts, already working on other priorities, will be further taxed by implementation of FERC Order 2222, which requires RTOs to enable aggregators of distributed resources the opportunity to compete in organized markets.

MISO has previously said it could save anywhere from $14 to $34 million annually if it implemented enhanced combined cycle modeling.

“This is beyond frustrating,” Xcel Energy’s Kari Hassler said. “I’m flabbergasted MISO continues to push this project out even though there are substantial savings to be had … This is a product that the entire footprint needs.”

Stakeholders asked if MISO could do something in the meantime to incrementally model combined cycle generators. Chatterjee said MISO is trying to be as transparent as possible about the challenges of implementing the modeling on its existing market platform.

“I just find it odd that [General Electric] said this is so complex of an ask when they’ve done something similar in SPP, and SPP has had it for about three years now. The complexity level is not extremely high,” Hassler said.

Chatterjee said SPP in fact encountered some technical difficulties when it introduced similar modeling. He also said SPP’s market clearing engine and interfaces are different from MISO’s.

“The tools are all customized, individualized for each RTO, and that’s why it’s so complex,” Chatterjee said.

“We’ll try to be ready, and if an opportunity presents itself, we’ll jump on that,” he added.

MISO Braces for 2nd Hurricane

At the time of the Oct. 8 meeting, Executive Director of Market Operations and Resource Adequacy Shawn McFarlane said MISO was preparing for the then-Category 3 Hurricane Delta, the 25th named storm of the 2020 Atlantic hurricane season.

“Unless you’ve been living under a rock, you know we have another hurricane forming in the Gulf and headed to Louisiana,” McFarlane said.

While Hurricane Delta’s projected landfall is only about 10 miles east of where Hurricane Laura made landfall, McFarlane said the relatively good news was that the new storm is weaker and faster-moving. He also said a weekend landfall means less load to be possibly interrupted.

“So on a relative basis, that is a better situation,” McFarlane said.

MISO decla r e d conservative operations and a transmission advisory for its South region beginning Friday.

McFarlane warned that Entergy’s Louisiana territory is still experiencing transmission line outages from the last storm. Hurricane Laura’s landfall on Aug. 27 brought MISO’s first load-shed orders and widespread transmission damage. (See MISO Keeps Advisories in Effect a Week After L a ura.)

“Certainly, we’re not as resilient as we could be because of Hurricane Laura,” he said.

IMM Reassures Stakeholders on Coal Self-commitments

MISO’s Independent Market Monitor reiterated that most coal self-commitment decisions in the footprint are made prudently.

Last month, Monitor David Patton provided the Board of Directors with analysis showing that most of the footprint’s coal self-commitments are profitable. (See MISO IMM Rebuts Uneconomic Coal Com m itment Studies.) This time, he brought the results to stakeholders.

“We don’t see the level of concern that prior studies have indicated,” Patton told stakeholders.

The Union of Concerned Scientists has released its own study concluding that Xcel Energy, DTE Energy, Cleco Power and Consumers Energy repeatedly make uneconomic coal generation commitments, costing ratepayers. (See UCS Analysis Knocks Coal Self-commitme n ts.)

Patton said self-committed coal dispatch returned fewer revenues in 2019 only because all energy prices were lower across MISO.

MISO Communication System Still a Source of Frustration

MISO has conceded again that its communication system for emergency resources needs to be more user-friendly.

The acknowledgment came during a review of load-modifying resource performance for an early 2019 generation emergency.

Market participants use the nonpublic MISO Communication System (MCS) to update availability of their load-modifying resources for use in emergency conditions.

“I know the MCS is not the most beloved system, but it does provide important information to MISO,” MISO Corporate Counsel Jacob Krouse told stakeholders during an Oct. 7 Resource Adequacy Subcommittee conference call. MISO stakeholders have long criticized MCS as being clunky and difficult to navigate. (See Stakeholders: M ISO System Fix Too Late for Summer.)

MISO issued a maximum generation event Jan. 30-31, 2019, in its North and Central regions during a record cold snap. While it called on more than 180 LMRs, only 21% met their expected load reduction. MISO levied almost $3 million in penalties to underperforming LMRs, and nine market participants sought alternative dispute resolution that lasted until early 2020.

Krouse said during the course of the dispute resolution, market participants indicated they were confused about what data they needed to input into the MCS. Some market participants weren’t following MISO’s requirement to furnish the MCS with their most up-to-date LMR availability data either, Krouse said.

He also noted that the MCS contained “default values inconsistent with LMR registration information,” which was fixed with monthly updates.

Krouse said there was confusion among MISO market participants on whether scheduling instructions would come from the MCS or another MISO mode of communication.

Krouse said MISO is working on MCS improvements following discussion from the Demand Response and MCS Alignment Task Team, formed last year. Further MCS improvements might be rolled out in mid-2021.

October 11, 2020

MISO Lays Out Seasonal Capacity Options

MISO resource adequacy staff are considering multiple options in the RTO’s effort to implement a sub-annual capacity mechanism and define new reliability criteria.

MISO has said it could define unique seasonal system reliability requirements as a bulwark against its increasing emergency events outside summer months. The RTO’s analyses indicate an emerging wintertime loss-of-load risk. MISO said it could be in the position of facing a winter peaking situation when electrification picks up in 2035 and beyond.

The shift could prompt MISO to issue a sub-annual reserves requirement based on a seasonal resource adequacy construct.

Stakeholders attending a virtual Resource Adequacy Subcommittee meeting Oct. 7 asked if MISO would run a Planning Resource Auction (PRA) four times per year.

MISO Director of Research and Development Jessica Harrison said several options are under consideration, including an annual construct that reflects sub-annual needs, one annual auction with seasonal or monthly segments, multiple seasonal auctions or monthly auctions across the planning year.

MISO is also exploring the use of additional risk assessments beyond loss of load, including the expected unserved energy calculation, where MISO calculates the expected amount of energy when load is set to exceed generation.

Senior Manager of Resource Adequacy Coordination Lynn Hecker said there could be additional “administrative burden” on MISO and its members if it develops separate planning reserve requirements and resource accreditations for each season.

“That’s really on the MISO to-do list, to get a better idea of what — if any — administrative burden … the proposed construct options might create,” she said.

If MISO moves to a sub-annual version of the capacity auction, Hecker said it would reduce its focus on summer peak modeling and forecasting in favor of pinpointing multiple loss of load risk hours throughout the year, called resource adequacy hours. RA hours would likely occur in summer and winter.

Harrison said MISO must decide if it should rely more on forward-looking projections or historical data to establish accreditation and reserve requirements using resource adequacy hours.

“In a time of slower-paced change, that’s reasonable; in a time of fast-paced change, that’s less reasonable,” she said of historical data being a predictor of system conditions.

Seasonal capacity auctions might give way to more seasonal economic outages, MISO and members said.

Harrison said MISO will be mindful of a seasonal auction’s possible effect of corralling too many generation outages into shoulder seasons. The RTO might consider must-offer obligations on capacity resources for each sub-annual period.

“The more granular we go, the more complex it will be to implement,” Hecker said.

The State Authority Quandary

The possibility of new reliability requirements has MISO and members probing the complicated relationship between MISO and state authority.

Some stakeholders have said that a move toward additional reliability criteria could infringe on state jurisdiction over resource adequacy and that MISO’s existing annual local clearing requirements and planning reserve margin are sufficient for reliability needs. (See MISO Closer to Se a sonal Capacity, Reliability Reqs.)

To date, no states have ever requested that MISO increase or decrease a planning reserve margin, said MISO Managing Assistant General Counsel Michael Kessler.

The MISO Tariff stipulates that states have the authority to superse d e the RTO and set their own planning reserve margins, but they cannot change MISO’s local reliability requirements or local clearing requirements. MISO would have to incorporate a state-set planning reserve margin into its planning resource margin requirements if it received a special state margin figure for a set of jurisdictional utilities. The Tariff also prohibits MISO from developing a resource adequacy requirement that conflicts with “state reliability or safety standards.”

Kessler said there’s “no other entity … than a state authority” that can alter MISO’s planning reserve margin requirement.

Some stakeholders questioned why states wouldn’t also have at least some authority over local reliability requirements or local clearing requirements if resource adequacy is ultimately the states’ prerogative.

Six of MISO’s ten local resource zones include territory from two or more states.

“Our interpretation of the Tariff — our literal reading of it — is that states do not have the authority to create a different local reliability requirement other than the one established by MISO,” Kessler said.

If a state chooses to set a lower planning reserve margin, the local clearing requirement of a local resource zone would still apply, Kessler said, with MISO still responsible for procuring capacity up to the requirement. Costs of the extra capacity procurement would be uplifted to the entire MISO footprint.

WEC Energy Group’s Chris Plante asked whether states could use a different loss of load risk than MISO’s one-day-in-10-years standard. A state’s decision to rely on a two-days-in-10-years risk would seem to affect zonal clearing and reliability requirements, he said.

“We haven’t had to work through a scenario where some of these mechanics would apply,” Kessler said, adding that MISO could pursue a deeper legal analysis of interaction between the Tariff and state law.

Plante has noted that states already largely rely on MISO’s recommended margins to set their resource adequacy plans.

“I think states increasingly look to MISO to establish their reserve margins,” he said during a special Aug. 21 MISO teleconference to discuss resource availability.

Zone 7 Reliability Requirements Questioned

Stakeholders are expressing consternation over draft 2021/22 PRA reserve requirements. This year, MISO began factoring unavailable generation due to planned outages into its loss of load expectation (LOLE) modeling, result i ng in higher local reliability requirements for almost all local resource zones.

MISO is estimating it needs a 9.4% unforced capacity (UCAP) planning reserve margin, up from last year’s 8.9% figure. Translated into an installed capacity basis, MISO needs an 18.3% reserve margin requirement in 2021, compared with 18% last year. (See MISO Planning Reserve Margin t o Climb in 2020.)

The need for more padding is the most dramatic in Lower Michigan’s Zone 7. Some stakeholders said it was unfair that a few individuals in MISO’s modeling group could have such an outsized impact on capacity requirements.

Customized Energy Solutions’ Ted Kuhn asked for “guardrails” in the LOLE modeling inputs process so members could expect more stability in the results.

MISO said its LOLE analysis showed that Lower Michigan runs the risk of more peak demand days in September than other local resource zones.

MISO plans to publish final LOLE results by Nov. 1.

MISO seasonal capacity — MISO’s UCAP planning reserve margin 2011-2021 | *MISO*

For the 2020/21 planning year, Zone 7 cleared at a cost of new entry price of $257.53/MW-day, due in part to a new MISO rule banning capacity resources from taking extended outages. (See MISO: New Outage Rules Boosted M i ch. Capacity Prices.)

MISO Independent Market Monitor David Patton sa i d two resources in Zone 7 raked in a combined $154 million in the 2020/21 Planning Resource Auction despite being on outages over the entire summer.

“Those resources are effectively unavailable even though we pay them the same,” Patton said during an Oct. 8 Market Subcommittee conference call.

Patton said he has long calculated leaner capacity margins than MISO projects because of the RTO’s failure to incorporate outages into its capacity picture.

Meanwhile, Planning Adviser Davey Lopez said MISO’s short-term resource availability and need fixes were successful in freeing up an additional 5-10 GW in capacity over the past year, as planned.

MISO launched new Tariff rules early last year to introduce demand response capability testing, seasonal documentation of the availability of load-modifying resources and a 120-day notice period for planned generation outages. (See “Near-term Filings,” MISO to Continue Resourc e Adequacy Talks in 2019.) The rules were meant as a stopgap measure to buy the RTO more time to flesh out bigger ideas.

“We are striving to come up with longer term solutions. The first phase was intended to buy time,” Lopez said, adding that MISO must continue working on the longer-term PRA changes. “Capacity margins continue to erode.”

October 11, 2020

NEPOOL Markets Committee Briefs: Oct. 6-8, 2020

The New England Power Pool Markets Committee last week rejected ISO-NE’s proposal for recalculating the dynamic delist bid threshold (DDBT) for Forward Capacity Auction 16, along with several proposed amendments to the RTO’s plan, none of which attracted the necessary 60% for endorsement.

The DDBT issue consumed half of the first day of the committee’s three-day meeting.

The DDBT for FCA 15 for 2024/25 is $4.30/kW-month. The Tariff requires the threshold, which was last updated in 2017/18, be recalculated for FCA 16 (2025/26).

The RTO proposed recalculating the DDBT annually using publicly available data, saying it would address transparency concerns and keep the threshold aligned with current and expected market conditions.

It would make the DDBT the average of the preceding FCA price and the price the capacity that cleared in the preceding FCA intersects with the estimated system-wide demand curve for the upcoming FCA. The threshold would not exceed the net cost of new entry (CONE) or fall below 75% of the preceding FCA price; the net CONE limit would apply if the two overlapped.

Jeffrey Bentz, director of analysis for the New England States Committee on Electricity (NESCOE), expressed concern in his presentati o n that setting the DDBT too high or at net CONE could improperly allow some bids to escape the scrutiny of a market power review. NESCOE proposed lowering the upper bound to 85% of net CONE or 125% of the prior auction clearing price, saying it would strike a better balance between the design objectives of providing adequate review to prevent market power and limiting unnecessary administrative interference.

NESCOE also proposed limiting the maximum rate of change in the DDBT from auction to auction to 30% of net CONE.

In a me m o to the committee, ISO-NE’s Matthew Brewster wrote that NESCOE’s proposals would “constrain the DDBT value relative to the [RTOs’] proposal under various conditions, which could undermine this key enhancement achieved with the new DDBT calculation method. … By preventing the DDBT from adjusting to reflect projected market conditions for the next FCA, the amendments would cause the DDBT to remain a lagging, or ‘stale’ estimate of the appropriate delist bid review threshold.”

The memo also said that “while NESCOE suggests a one-directional remedy within the DDBT for (potential) errors” in net CONE, it does “not appear to provide a reasoned basis for the numerical value of the proposed cap at 85% of net CONE.” Additionally, NESCOE’s other proposed DDBT cap of 125% of the last FCA clearing price “has only a superficial symmetry with the floor present in the ISO’s design.

“The underlying assumption of this 125% cap is that the supply curve becomes flat at prices 25% higher than the last FCA clearing price,” the memo continued. “However, that outcome is not supported by theory … nor is it plausible in practice. The supply curve generally is increasingly steep as quantity increases (up to the point where prices reach true net CONE).”

The NESCOE amendments failed with only 34% support.

The committee also rejected proposals by Calpine and Vistra Energy’s Dynegy unit to address what Bill Fowler, president of Sigma Consultants, said is the disadvantage faced by resource owners having to lock in static delist bids four months before the FCA.

At the September Markets Committee meeting, Fowler said the DDBT should be set at a “reasonable margin” — 50 cents to $1/kW-month — above the expected clearing price. (See “Change to Delist Bid Threshold,” ISO-NE Challenged on Wind, S olar, Storage Revenues.) Fowler revised the pro p osal last week, calling for “a small cushion” varying with the level of the expected clearing price, declining to zero if the expected clear is at net CONE. It won only 49% support.

Also rejected was a Calpine/Dynegy proposal to eliminate the obligation to commit to a bid price in October and make the October static delist finalization requirement a cap on auction prices.

ISO-NE’s proposed DDBT changes, the last vote, received only 44.5%. The RTO will file the proposal with FERC despite the lack of stakeholder endorsement.

Support for Forward Reserve Market Sunset

On a voice vote, the committee approved ISO-NE’s p r oposal to sunset the forward reserve market (FRM) to avoid conflicts with its proposed Energy Security Improvements (ESI) initiative, which is awaiting FERC action. (See ISO-NE S ending 2 Energy Security Plans to FERC.)

The FRM awards obligations for 10-minute non-spinning reserves and 30-minute operating reserves, but the RTO said it is becoming unnecessary because of ESI and transmission investments and market changes that address locational constraints and reward resource flexibility.

The RTO’s proposal included two alternatives. If FERC issues an order approving ESI as filed before Dec. 31, the RTO will file a “non-contingent” Tariff change by the end of 2020 to sunset the FRM on June 1, 2025, coinciding with the start of the 2025/26 capacity commitment period.

If FERC does not rule on ESI before the end of the year, the RTO would file a “contingent” FRM sunset that would take effect if FERC approves ESI as filed.

If FERC rejects ESI, the RTO will not file either Tariff change. The RTO said future discussions with stakeholders on reserves might be necessary if this is the eventual outcome.

The RTO plans a vote by the Participants Committee in November.

RTO Seeks Modifications for EERs, RAs

Ryan McCarthy of ISO-NE prese n ted proposed modifications to the qualification process for energy efficiency resources (EERs) to better account for expiring measures. The RTO also wants to change the monthly reconfiguration auction (RA) and bilateral qualification rules to better account for new financial assurance and performance accounting rules.

The proposal would set the seasonal qualified capacity to the lower of the amount of capacity that has cleared as “new” in prior FCAs or the amount of measures marked commercial plus FCA cleared non-commercial MWs on critical path schedule (CPS) monitoring. The proposed methodology would apply to both the FCA and all annual RA qualifications.

NEPOOL — The proposed methodology by ISO-NE is expected to increase energy efficiency qualification values. | *ISO-NE*

An EER will have two years from the start of the commitment period in which it first received a capacity supply obligation to install its measures. Previously cleared EERs will have until May 31, 2027, to install all measures.

As additional EE clears in the FCA, the capacity will be factored directly into the load reconstitution process. The RTO said the proposal will better align qualified capacity with its performance capabilities.

The RTO would assign monthly qualification to resources that become commercial during the capacity commitment period. The monthly qualification will track delayed commercial resources and allow non-commercial capacity to participate in monthly RAs and bilateral qualifications.

The Markets Committee will vote on the proposals next month. EER qualification changes would become effective in February 2021 for FCA 16. The monthly qualification changes would become effective in January 2022 and implemented for the March 2022 monthly reconfiguration auction and bilateral qualification period.

GIS Working Group to Consider Massachusetts ‘Clean Generation’ Changes

The MC agreed to direct the Generation Information System (GIS) Operating Rules Working Group to consider changes to the GIS and the GIS Operating Rules to reflect the addition of “Clean Existing Generation” (CES-E) to the Massachusett s Clean Energy Standard. The changes were requested by the Massachusetts Department of Environmental Protection.

NEPOOL counsel Paul Belval of Day Pitney said in a mem o that DEP revised its regulations to include a requirement that retail load-serving entities subject to the standard have a certain percentage of energy from “Clean Existing Generation Units.”

Clean existing generation units are nuclear or hydroelectric units with a nameplate capacity of at least 30 MW that began commercial operation before Jan. 1, 2011, and satisfy specific geographic requirements. In addition to adding a new category in the GIS, the DEP regulations pose two additional rule changes. Multiple co-located GIS generators could have their generation aggregated, and certain annual caps on qualifying output would have to be allocated among those GIS generators. Also, certain generators in Newfoundland and Labrador could be eligible. That would require a slight expansion of the area where qualified generators can receive unit-specific certificates in the GIS.

The committee is not being asked to vote on any changes to GIS rules, the memo said, but should refer issues to the working group to discuss and determine potential rule revisions.

Order 841 Compliance Update

Jennifer Wolfson of ISO-NE upd a ted the committee on the RTO’s plan for responding to an Aug. 4 FERC order on the RTO’s second Order 841 compliance filing. (See FERC OKs Most of ISO-NE 2nd S t orage Compliance.)

The RTO proposes Tariff changes to comply with two FERC directives. The first change would address FERC’s concern that the Tariff language preventing double payment for charging energy at the retail and wholesale levels would allow host utilities to decide whether an electric storage resource (ESR) may participate in its markets. It would be effective in the first quarter of 2021.

The second responds to FERC’s directive that the Tariff include the bidding parameters the RTO will use to account for the state of charge and duration characteristics in the day-ahead energy market. It would be effective Jan. 1, 2026.

The RTO will seek votes on the proposed revisions at the committee’s next gathering on Nov. 9-10 and at the Participants Committee’s Dec. 3 meeting.

October 11, 2020January 15, 2025

SPP Seams Steering Committee Briefs: Oct. 7, 2020

SPP staff last week said they considered several seams-related projects with MISO in their 2020 Integrated Transmission Planning (ITP) assessment but eventually declined to pursue them over differing methodologies in calculating benefits and costs.

“Rest assured we’re going to continue to look at these areas in the future,” Kirk Hall told the Seams Steering Committee during its Oct. 7 meeting, referring to three 345-kV projects along the Nebraska-Iowa border.

“MISO and SPP staff continue to work on understanding the cost differences,” Hall said. “Hopefully, we’ll come back with something that is agreeable to all parties.”

Hall shared a near-final version of the ITP assessment with the SSC. Staff identified 54 projects in the final portfolio, which includes 92 miles of 345-kV transmission lines and 141 miles of rebuilt high-voltage infrastructure. It estimated $532 million of engineering and construction costs but projected a 4.0-5.2-to-1 benefit-to-cost ratio.

The 2020 ITP takes a 10-year look at system reliability and economic needs. Staff spent more than two years evaluating more than 2,200 solutions, and said the projects will solve 163 system needs, help levelized market prices, improve congestion hedging and facilitate access to low-cost energy.

The ITP assessment will be taken to SPP stakeholders and the Board of Directors later this month for their approval.

Neil Robertson, SPP’s interregional relations senior engineer, said the grid operator remains “committed to coordinating” with MISO. The RTOs once again failed to agree on an interregional project during their fourth coordinated system plan (CSP) study but have since agreed to combine forces on a year-long transmission study to identify “comprehensive, cost-effective and efficient upgrades.” (See MISO, S PP to Conduct Targeted Transmission Study.)

“SPP will … work with MISO and determine how we would rectify costs differences if we decided to factor in whether a project can be recommended or not,” Robertson said.

He said SPP and MISO analyzed 10 needs in their CSP, but no solutions met “fundamental requirements.”

Robertson also discussed the final re p ort of SPP’s joint CSP with Associated Electric Cooperative Inc. The entities will combine forces on what would be the RTO’s first competitive project under FERC Order 1000. (See FERC A pproves SPP-AECI Competitive Project.)

M2M Settlements Again Favor SPP

Market-to-market (M2M) settlements once again flowed in SPP’s favor during August, staff told the committee, resulting in a $1.1 million accrual for the grid operator. Temporary and permanent flowgates were binding for 725 hours during the month.

SPP’s market-to-market settlements with MISO are approaching $95 million. | SPP

SPP has now accrued $93.82 million in M2M settlements since it began the process with MISO in March 2015.

August marked the 10th time in 11 months, and the 49th time in 66 months, that settlements have ended up in SPP’s favor.

October 9, 2020

NERC Opens Comments on SERC RSDP

NERC is seeking comments through 8 p.m. Nov. 20 on proposed changes to SERC Reliability Corporation’s Regional Reliability Standards Development Procedure (RSDP), stemming from recent changes to the regional entity’s executive structure.

Each RE files an RSDP with NERC to “define the steps in that region’s process for developing, reaffirming and withdrawing its regional reliability standards” and to ensure that regional standards align with continent-wide standards approved by FERC and its Canadian and Mexican counterparts. RSDPs must be reviewed and submitted to NERC every five years — or earlier if the RE’s board feels revisions might be needed.

SERC RSDP — SERC headquarters in Charlotte, N.C. | *SERC*

SERC’s current RSDP was approved by the RE’s Board of Directors in October 2017 during its five-year review and accepted by NERC the following year. This revision, which comes about two years before the regularly scheduled review, is a relatively minor update intended to bring the RSDP in line with SERC’s updated executive structure as described in the RE’s revised bylaws approved by FERC in July. (See FERC A p proves SERC’s Bylaw Changes.)

Changes to be implemented under the new bylaws include changing the Board Compliance Committee into a Board Risk Committee, transforming SERC’s Board of Directors into a hybrid board comprising both sector representatives and independent directors and eliminating the use of alternates and proxies for directors and independent directors. The updated RSDP reflects these changes by removing references to Board representatives and alternates and replacing references to the SERC Executive Committee with SERC Board of Directors.

In addition, the new document replaces references to the former executive committees of SERC’s technical committees to reflect their unification into a single Operations Planning and Security Executive Committee, and revises abbreviations throughout the RSDP to ensure internal consistency. The updates are planned to take effect Jan. 1, 2021, along with the new bylaws.

Openness, Balance Among Commenting Criteria

Industry stakeholders are being asked to comment on whether SERC’s updates meet NERC’s requirements for all regional RSDPs. Those requirements include the following:

Openness — The RSDP must allow any person or entity that is “directly and materially affected by the reliability of the bulk power system within the regional entity” to participate in the reliability standard approval process.
Inclusivity — Any person or entity with a direct and material interest must be permitted to express and justify an opinion, have that position considered and appeal through an established process in the case of an adverse decision.
Balance — Regional RSDPs must have a balance of interest and not be dominated by any two interest categories. No single interest category can be allowed to defeat a matter.
Due process — Standards development processes must provide reasonable notice and opportunity for public comment, including, at minimum, public notice of the intent to develop a standard, a comment period on the proposed standard, due consideration of comments and the opportunity for stakeholder ballots.
Transparency — All actions and materials relating to standards development must be transparent, and members of the public must be notified and allowed to attend all standards development meetings.

Following the comment period, SERC will submit the revised RSDP for approval by NERC’s Board of Trustees, most likely at its meeting in February 2021. Earlier this year, the Board accepted the Northeast Power Coordinating Council’s revisions to its own regional standard processes manual, aimed at clarifying outdated language and establishing closer alignment with NERC’s standard development process. (See “Budget, ROP, Standards Actions,” NERC Board of Trustees/MRC Briefs: Aug . 20, 2020.)

October 8, 2020

NY Solar Plus Storage to Grow ‘Dramatically’

The Alliance for Clean Energy New York (ACE NY) on Tuesday drew 162 people to a virtual meeting to hear solar developers, industry experts and a NYISO official discuss projects that pair solar energy with energy storage.

New York solar storage — Bill Acker, NY-BEST | *ACE NY*

Timing is crucial, and pairing energy storage with renewables allows the energy to move out of congested pockets, said Bill Acker, executive director of the New York Battery and Energy Storage Technology Consortium (NY-BEST).

“Instead of moving the energy at rush hour, you move the energy off of rush hour and you have what some people call virtual transmission,” Acker said. “Even beyond congestion, you have the situation when you get to very high renewables on the grid, where you literally have over-generation; even if you had the transmission, you wouldn’t be able to use the energy. Again, shifting the time allows you to use the energy.”

Because renewable energy projects paired with storage are proving popular with developers, NYISO in July decided to speed up its hybrid modeling capability, aiming to complete the enhancement in 2021. (See “Exciting Times,” Overheard at NY-BEST’s 10th Annual Meeting.)

Following is some of what we heard at the meeting.

Solar and Wind Benefit

“Storage is increasingly an area of focus for us; it is going to be paired with solar in all forms,” said David Gahl, senior director of state affairs in the Northeast for Solar Energy Industries Association.

In 2019, storage was paired with 5% of solar, “but we’re expecting that number to increase dramatically by 2025. In the distributed space, 25% of all behind-the-meter solar will be paired with storage,” Gahl said.

The growth is being driven in part by the eligibility of hybrids for the investment tax credit and by state goals, Gahl said. “In the utility-scale space … solar is increasingly paired with storage resources, with over 8 GW of commissioned projects that include storage right now. That represents nearly one in five of the contracted projects out there,” he said.

Clockwise from top left: Michael DeSocio, NYISO; Pete Fuller, Autumn Lane Energy Consulting; Anne Reynolds, ACE NY; Bill Acker, NY-BEST; and John Brodbeck, EDP Renewables. | *ACE NY*

New York’s solar-plus-storage market is being driven by the Climate Leadership and Community Protection Act, which set targets of getting 70% of the state’s electricity from renewables, and deploying 3 GW of energy storage and 6 GW of distributed solar, by 2030. The Public Service Commission laid out the state’s storage deployment policy in a December 2018 order, since updated (18-E-0130).

The New York State Energy Research and Development Authority is working to meet the goals via three pathways: state-subsidized incentives, contracts with the state’s investor-owned utilities and pairing a renewable energy certificate bid with storage, Gahl said. (See NY Utilities, Developers Tweak Storage Procurement Terms.)

In addition to providing the opportunity for more ancillary services, storage makes use of the spilled or “clipped” energy, adds duration and allows discharge at times better suited for the grid or the economics of the unit, said John Brodbeck, senior manager of transmission at EDP Renewables North America. With approximately 700 MW operating in New York, it is the largest owner of wind generation in the state.

“As a wind generator, we’ve been able to reg down for a while. To be able to reg up would be a good thing,” said Brodbeck, referring to ancillary services that help maintain the grid’s frequency. “There’s plenty of problems though … interconnection issues, modeling issues, how does it operate within the market and metering issues.”

NYISO was “pretty swift” to act on paired storage, and the stakeholder discussions quickly came to the concept of co-located storage resources (CSR), which is the simplest form of a hybrid unit: essentially two separate units at the same site, he said.

NYISO’s 2nd Storage Compliance Almost Hits Mark.)

“You can get some ancillary services from the storage side, and the intermittent [resource] can charge the storage resource, and those are good things,” Brodbeck said. “The whole AC-coupled, DC-coupled issue seems to have been resolved nicely in NYISO,” with the ISO allowing both AC and DC coupling configurations between intermittent and storage resources. “The current state of the rules for CSR is it does allow a single interconnection request, so we don’t need to have multiple interconnection requests in the queue or in the class year, and the injection can be sized to less than the total electrical capability of the unit, which allows some additional flexibility.” (See Hybrid Resource Developers Ask for Uniform Rules.)

“With 700 MW of wind, our plan is that at some point in the future, we’d be adding storage to most of those sites,” Brodbeck said. “Many renewable sites, especially solar sites, are going to be wanting storage either as part of the original design or added on later. … I think you’ll see storage being added to a large number of units. Our concerns are about having to go back and getting it resized for interconnection, making sure that interconnection plan can be done expeditiously to get online quickly.”

A More Complicated Grid

Pete Fuller, Autumn Lane Energy | *ACE NY*

The evolving grid is going to be much more complicated than the old one-way power flows of the past, said Pete Fuller, principal of Autumn Lane Energy Consulting.

“You’ve got rooftop solar, vehicle-to-grid applications, microgrids, solar, wind, storage, hybrids — you’ve got a lot more things going on out on the grid that are separate and distinct from those big central power plants,” Fuller said. “As I think about hybrids, the real goal here is to create something through co-located or otherwise aggregated resources that somehow is greater than the sum of the parts. It creates additional value, certainly for the developer owner, because that’s what generates the investment and the interest, but also creates additional value for the grid.”

Michael DeSocio, director of market design at NYISO, said that “the energy storage rules that went commercial at the end of August are technology-agnostic.”

The ISO’s new rules focused on storage technologies that are dispatchable, which varies depending on the capabilities of the technology. For example, “if compressed air can inject and withdraw without needing to change state — in other words go offline for a little bit to change the state of its compressors to do that — it could be an ESR [energy storage resource],” DeSocio said.

The model does not exist in the market today for compressed air that needs to go offline between injection and withdrawals, he said.

“It’s something that we’ve thought about building as part of the ESR model but ultimately put aside given that we don’t have any projects in the queue for any of those technologies,” DeSocio said. “We do have a model for limited energy storage resources that’s been around since 2009, which allows flywheels and smaller batteries to provide regulation service. … When we talk about hybrid resources and the co-located model, we’re focused on energy storage that is dispatchable and can provide energy as well as resources that are dispatchable.”

October 8, 2020

CAISO Says Constrained Tx Contributed to Blackouts

A report on the causes of California’s August blackouts details for the first time the role that convergence bidding played in masking tight supply and contends that constrained transmission prevented much needed imports from reaching the state.

The 107-page report to Gov. Gavin Newsom by CAISO, the California Public Utilities Commission and the state Energy Commission blames previously discussed causes, including extreme heat induced by climate change and inadequate resource planning. And it expands on the allegation, mentioned in passing at recent CAISO meetings, that load-serving entities failed to anticipate their needs when scheduling in the day-ahead market.

“We have identified several factors that, in combination, led to the need for the CAISO to direct utilities in the CAISO footprint to trigger rotating outages,” the organizations wrote. “There was no single root cause of the outages, but rather, a series of factors that all contributed to the emergency.”

The rolling blackouts were the first to sweep the state since the energy crisis of 2000-2001. Over two days, about 812,600 households — representing about 2.4 million people — lost power.

Outmoded RA Planning

In an expected finding, CAISO said the state was unprepared to meet the extreme Western heat wave of Aug. 14-19 and that resource planning now must assume there will be similar events caused by climate change.

During the mid-August “heat storm,” California experienced four out of the five hottest August days since the ISO and the CEC began tracking such data in 1985, the report said. The organizations use an average daily temperature composite to predict electricity consumption across the CAISO region.

“Current resource adequacy planning standards are based on a one-in-two peak weather demand plus a 15% [planning reserve margin] to account for changing conditions,” the report said.

CAISO blackouts — The 2020 heat storm was a one-in-35-year event, the California Energy Commission said. | *CEC*

But the August heat wave was a one-in-35-year event “not anticipated in the planning and resource procurement time frame, which is necessarily an iterative, multiyear process.” The state needs more supply resources, including battery storage for wind and solar, and must use new planning criteria for long-term projections, it said.

The rolling blackouts were made worse by transmission constraints and other causes, but “it is unlikely that current RA planning levels would have avoided rotating outages” under the same conditions, even without those contributing factors, it said.

Constrained Supply

Import bids in the day-ahead market were 40 to 50% (2,600 to 3,400 MW) higher during the August energy emergency than typical RA requirements from imports in August, but the output couldn’t get where it need to go, the organizations said.

“Despite this robust level of import bids, transmission constraints ultimately limited the amount of physical transfer capability into the CAISO footprint,” the report said.

A major transmission line in the Pacific Northwest upstream from CAISO was on forced outage because of weather conditions, and the California Oregon Intertie (COI) was derated, the report said.

“The derate reduced the CAISO’s transfer capability by approximately 650 MW and caused congestion on usual import transmission paths across both COI and Nevada-Oregon Border,” it said. “In other words, more imports were available than could be physically delivered, and the total import level was less than the amount the CAISO typically receives.”

Under-scheduling

CAISO said LSE scheduling coordinators “collectively under-scheduled their demand for energy by 3,386 MW and 3,434 MW below the actual peak demand for Aug. 14 and 15, respectively.”

During the net peak — the hours after solar goes offline but demand remains high on hot days — LSEs under-scheduled demand by 1,792 MW for Aug. 14 and 3,219 MW for Aug. 15, the ISO reported. The blackouts on those days occurred in the net-peak hours.

“The under-scheduling of load by scheduling coordinators had the detrimental effect of not setting up the energy market appropriately to reflect the actual need on the system and subsequently signaling that more exports were ultimately supportable from internal resources,” the report said.

CAISO said its own peak forecasts were 825 MW below actual demand for Aug. 14 and 559 MW above actual demand for Aug. 15. Its forecasts for the net demand peak times were 511 MW and 632 MW above actual demand.

But during the mid-August events, “it was difficult to pinpoint these contributing causes because processes that normally help set up the market masked the under-scheduling,” the report said.

One of the processes was convergence bidding, a financial hedge that some observers believed could have been used to game the market.

“As the name suggests, convergence bidding is intended to allow bidders to converge or moderate prices between the day-ahead and real-time markets,” the report said. “Under normal conditions, when there is sufficient supply, convergence bidding plays an important role in aligning loads and resources for the next day. However, during Aug. 14 and 15, under-scheduling of load and convergence bidding clearing net supply signaled that more exports were supportable.”

“Once this interplay was identified on Aug. 16 after observing the results for trade day Aug. 17, convergence bidding was temporarily suspended for Aug. 18 trade date through the Aug. 21 trade date,” it said.

During those days, when conditions remained much the same as Aug. 14-15, further blackouts were averted.

RUC Flaw

The report also delved into complications stemming from a flaw in CAISO’s residual unit commitment (RUC) process. The ISO runs the RUC after the day-ahead Integrated Forward Market (IFM) process to avoid real-time supply shortages in rare cases when LSEs under-schedule demand.

The report notes that inputs into the RUC process differ from the outputs of the IFM in three ways:

Load cleared in the IFM is replaced by CAISO’s own day-ahead forecast, which does not include exports.
Wind and solar schedules cleared in the IFM are replaced by CASO’s wind and solar forecasts.
Virtual supply and demand that cleared in the IFM’s convergence bidding market are removed.

The RUC itself consists of two passes: a scheduling run intended to address any unresolved market constraints based on “an intricate but prescribed set of relative priorities” for relaxing the constraint or curtailing schedules; and a pricing run to produce prices that align with both the $1,000/MWh bid cap and the scheduling run.

To ensure that schedules produced by the IFM are physically feasible, the RUC process enforces a power balance constraint to ensure that forecast load can be met in real time.

In 2014, CAISO implemented the Pricing Inconsistency Market Enhancement (PIME) to address inconsistencies between schedules and prices. PIME redirected both the IFM and the RUC to use pricing run results as the source of both prices and schedules.

“Through these RUC constraints, the CAISO determines what portion of the day-ahead schedules are physically feasible and which portion that market participants should tag when the E-Tag is submitted in the day-ahead,” the report said.

After the Aug. 14 and 15 blackout events, CAISO determined that rather than reducing the volume of infeasible exports scheduled in the IFM, the RUC pricing run instead relaxed the power balance constraint, compromising the ISO’s ability to meet actual load. But the ISO found that the RUC’s scheduling run (no longer used to set final schedules) would have relaxed the IFM’s scheduled exports before relaxing the power balance constraint.

As a result, CAISO said it stopped using the PIME functionality in its RUC process beginning Sept. 5, allowing it to use scheduling run results for RUC schedules rather than pricing run results.

October 8, 2020

FERC Approves SPP-AECI Competitive Project

FERC on Wednesday approved a cost-and-usage agreement between SPP and Associated Electric Cooperative Inc. (AECI) that could result in the RTO’s first competitive project under Order 1000 (ER20-2707, ER20-2708).

The letter order accepted the terms and conditions governing the construction, ownership, operation and cost for the installation of 345-kV terminal equipment at AECI’s existing Blackberry substation, the endpoint for SPP’s 109-mile, 345-kV Wolf Creek-Blackberry transmission project. It also accepts Tariff revisions to include the substation’s construction costs in each SPP transmission owner’s respective annual transmission revenue requirement.

“We were glad to see that outcome,” Neil Robertson, SPP’s interregional relations senior engineer, said in breaking the news Wednesday morning to the Seams Steering Committee.

The Wolf Creek-Blackberry project is expected to cost $152 million. SPP members will fund the line according to load-ratio share. The RTO’s Board of Directors last month lifted a suspension on the project and authorized the Oversight Committee to create an industry expert panel (IEP) to evaluate responses to a request for proposals, which staff have since issued. (See “Board Lifts Suspension on Competitive Upgrade,” SPP Board of Directors/MC Briefs: Sept. 22, 2020.)

SPP awarded its first competitive project in 2016 to Mid-Kansas Electric, but the project was later canceled because load projections dropped over time. (See SPP Cancels First Competitive Tx Project, Citing Falling Demand Projections.)

A third competitive project has already been evaluated by an IEP and will be brought before the board for its consideration in October.

October 8, 2020

FERC Report Outlines CIP Compliance Recommendations

In its latest round of Critical Infrastructure Protection (CIP) audits, FERC noted registered entities have made significant progress in meeting or exceeding the reliability standards’ mandatory requirements.

However, the commission still noted several “potential compliance infractions” and other areas for improvement.

FERC’s “Lessons Learned from Commission-Led CIP Reliability Audits” report is based on audits carried out during the federal government’s 2020 fiscal year, which began on Oct. 1, 2019, and ended Sept. 30. The number of audits performed, which also involved staff from regional entities and NERC, was not disclosed in the report; the audited entities’ identities were also kept confidential.

FERC has been conducting CIP audits since FY 2016. Audit fieldwork includes data requests, webinars and teleconferences, and site visits to registered entities’ facilities. During site visits, audit staff interview utilities’ subject matter experts, along with employees and managers responsible for performing tasks within the audit scope; observe operating practices in real time; and examine entities’ “regulatory and corporate compliance culture.”

Recommendations up from Previous Report

This year’s report produced 12 lessons learned, intended to “help responsible entities improve their compliance with the CIP reliability standards and their overall cybersecurity posture.” The commission’s first report covered FY16 and FY17, and included 21 recommendations; the number of lessons learned dropped to 10 in the FY18 report and seven last year. (See FERC: Room for Improvement on CIP Compliance.)

Despite the rise in recommendations, FERC’s report emphasized that “most of the … processes and procedures adopted by the registered entities met the mandatory requirements” of the CIP standards. As a result, the lessons learned reflect “practices that could improve security but are not required by the [standards],” in addition to mandatory fixes to bring entities back in line with requirements.

The suggested improvements covered the following standards:

CIP-002-5.1a — Bulk electric system cyber system categorization
CIP-004-6 — Personnel and training
CIP-006-6 — Physical security of BES cyber systems
CIP-007-6 — Systems security management
CIP-009-6 — Recovery plans for BES cyber systems
CIP-010-2 — Configuration change management and vulnerability assessments
CIP-011-2 — Information protection

For CIP-002-5.1a, staff observed that some entities did not properly identify BES cyber assets; for example, in some cases, cyber assets such as switches and protocol converters were recorded as communication equipment. This is incorrect, as such equipment “may pose an impact … within 15 minutes of their misuse.”

Auditors also found some instances in which substation BES cyber systems that should have been considered medium-impact were instead recorded by utilities as low-impact because staff “did not properly consider” the effect that all the relevant equipment might have when operated collectively.

CIP Compliance Recommendations — | *FERC*

Recommendations for CIP-004-6 include ensuring that electronic access to BES cyber system information is properly authorized and revoked, following auditors’ discoveries that several entities had not followed their procedures consistently. In some cases, access was granted verbally without filing the necessary documentation, while in others, the access of terminated employees was not deactivated by the end of the calendar day following their departure.

Improvements for physical security — covered by CIP-006-6 — include dedicated visitor logs at each physical access point, locking BES cyber systems’ server racks where possible and periodic inspections of physical security perimeters to ensure there are no unidentified physical access points. Consistent practices are also endorsed in the recommendations for CIP-007-6, which include periodic review of security patch management processes, as well as consolidating and centralizing password change procedures.

Under CIP-009-6, auditors noted that some entities “failed to update their backup and recover procedures in a timely manner,” for instance by failing to establish a new process following a critical event in violation of the standard’s requirement. Entities were also found to have neglected to “report any information to remediate and mitigate vulnerabilities identified in vulnerability assessments,” as mandated in CIP-010-2.

Finally, staff noted that several entities could not “demonstrate that they properly disposed of” substation devices removed from services as required by their asset reuse and disposal policies, and that others relied entirely on security controls provided by third-party vendors without verifying their sufficiency. Both issues could constitute a violation of information protection requirements in CIP-011-2.

In several places, staff also recommended that entities “consider the guidance” of the National Institute of Standards and Technology’s Security and Privacy Controls for Federal Information Systems and Organizations report. While implementing these recommendations would not contribute to compliance, they would enhance the culture of security among utility staff, they said.

October 8, 2020

Tri-State Increases Members’ Self-supply Options

Colorado cooperative Tri-State Generation and Transmission Association said Wednesday it will cut its rates by 8% by the end of 2023 and give members additional flexibility to provide their own power, addressing two of its members’ most frequent complaints.

CEO Duane Highley acknowledged during a press conference that members had asked for more leeway in self-supply options to increase their use of renewable energy, calling the actions a “green energy dividend.”

“It’s been lots of work, but the cooperatives have come together cooperatively to find ways to make this work for everyone,” Highley said, apparently unaware of his play on words. “We’ve all agreed this is a fair way to share costs.”

Highley was backed by two member representatives, Poudre Valley Rural Electric Association CEO Jeff Wadsworth and Southeast Colorado Power Association CEO Jack Johnston, and former Colorado Gov. Bill Ritter, director of the Center for the New Energy Economy.

Ritter lauded Tri-State for its Responsible Energy Plan, which the co-op unveiled in January with similar fanfare. The plan’s components include 50% renewable consumption by 2024, reduced emissions by closing coal plants in Colorado and New Mexico, and additional self-supply and local renewable energy flexibility for members. (See Tr i -State to Retire 2 Coal Plants, Mine.)

“This was not an easy result to get to. None of this is easy,” Ritter said. “They’re living up to the commitments they made in the Responsible Energy Plan. We’re going to make a commitment to lower rates for the next few years. That is something I think we should all applaud.”

The announcement followed a meeting at which Tri-State’s Board of Directors approved the rate cut and the Contract Committee’s process to implement partial requirements contracts with its utility members.

“You typically don’t hear about electric utilities lowering rates, so we’re grateful to Tri State and board for this big lift,” Wadsworth said.

Tri-State Generation and Transmission Association — Tri-State’s members cover much of the Rocky Mountains. | *Tri-State Generation and Transmission*

Beginning with an “open season” nominating period in early 2021, utility members can transition to the new contracts by expressing their interest in shares of the 300-MW of system-wide self-supply capacity allocation. The open season capacity accounts for 10% of Tri-State’s system peak demand.

Members can self-supply up to 50% of their load requirements, subject to availability in the open season. This expands on the current 5% self-supply provision and a new communi t y solar provision.

The 5% cap has frustrated Tri-State’s 42 utility members, some of whom are involved in regulatory litigation to leave the co-op. (See Tri-State, Delta Officially Part Wa y s.)

Tri-State has recently added three non-utility members, making it FE R C-jurisdictional. The commission in March found Tri-State to be under its jurisdiction, a ruling it affirmed in August. (See FERC Affirms its Jurisdictio n over Tri-State G&T.)

FERC Rejects Interconnection, GIA Procedures

As the press conference proceeded online, FERC issued an order rejecting Tri-State’s proposed Tariff revisions modifying its generator interconnection procedures and generator interconnection agreements (GIAs) without prejudice to a submitted revised proposal (E R 20-2593).

Tri-State said it intends to refile a revised proposal.

FERC in March accepted Tri-State’s Tariff revisions establishing the jurisdictional rates and terms and conditions for transmission service over its Western Interconnection facilities, but set the matter for hearing and settlement judge procedures to determine their justness and reasonableness. (See “Ruling Permits Tri-State to Become FERC Jurisdictional,” SPP FERC Briefs: Week of March 1 6, 2020.)

Tri-State proposed to reform its interconnection queue by transitioning from the pro forma sequential first-come, first-served study approach to a first-ready, first-served cluster study. The cooperative said the change was consistent with or superior to its pro forma large and small generator interconnection procedures (LGIP/SGIP) and the large and small GIAs.

The revisions would have established an informational interconnection study process — to assist customers make business decisions about their generation facilities before entering the queue — and a definitive interconnection study process. Tri-State said interconnection customers must demonstrate site control and meet increasingly stringent readiness milestones as they advance through the interconnection phases.

FERC found that Tri-State did not demonstrate several revisions to be consistent with or superior to the pro forma LGIP: 1) its proposal to allocate network upgrade costs based on a distribution factor analysis; 2) the requirement for interconnection customers to select energy or network resource interconnection service (ERIS/NRIS) before beginning one of the study process’ phases; and 3) the requirement for interconnection customers entering a transitional process to demonstrate readiness within 10 days of the revised LGIP’s effective date.