Page 1058 – RTO Insider

August 18, 2020

NEPOOL Markets Committee Briefs: Aug. 11-13, 2020

The New England Power Pool’s Markets Committee held a three-day meeting last week, with much of the time devoted to revising parameters and inputs for Forward Capacity Auction 16 (capacity commitment period 2025/26). Here are some of the highlights.

ISO-NE Seeks to Sunset Forward Reserve Market

ISO-NE is seeking to sunset the Forward Reserve Market (FRM) to avoid conflicts with its proposed Energy Security Improvements (ESI) initiative.

The FRM awards obligations for 10-minute non-spinning reserves and 30-minute operating reserves.

ISO-NE’s Jonathan Lowell told the committee that transmission investments and market changes, including the anticipated implementation of ESI, have or will relieve many locational constraints and reward resource flexibility. Because of those changes, and prior recommendations by the External Market Monitor, the RTO is proposing sunsetting the FRM on June 1, 2025, assuming FERC approves related ESI components.

Lowell said FRM and ESI cannot “peacefully coexist” because both procure 10- and 30-minute reserves and that FRM’s weaknesses cannot be corrected through incremental fixes. FRM does not use a two-settlement market design, relies on administratively calculated penalties and requires real-time energy offers above cost, resulting in an inefficient co-optimized real-time dispatch, the RTO says.

FRM was created as a supplemental payment to peakers. Although ESI has a different primary purpose — creating incentives to ensure energy security in real time — the two constructs would both award commitments prior to real time.

The RTO would align the FRM sunset with the net cost of new entry updates for FCA 16, contingent on FERC’s acceptance of 10- and 30-minute day-ahead reserves in either the RTO or NEPOOL version of the ESI proposal. (See ISO-NE Sending 2 Energy Security Plans to FERC.)

To receive a FERC order by March 1, 2021, ahead of the retirement bid delist window, the RTO plans to make the sunset filing contemporaneously with Forward Capacity Market parameters by the end of the year. CONE and other assumptions used in FCA 16 depend on estimates of ancillary revenues from sources such as FRM.

Lowell said the RTO is not concerned about removing incentives for new peakers to supplement increasing amounts of intermittent resources because the region has ample generation and fast-start capacity. Market changes over the last 10 years have added rewards for resource flexibility: fast-start pricing, energy market offer flexibility, Pay-for-Performance, sub-hourly settlements and the existing real-time replacement reserve, he said.

The RTO will present proposed Tariff changes to the committee Sept. 8-10, with an MC vote planned for October and a Participants Committee vote in November.

Wholesale Market Consequences of Gross Load Reconstitution Proposal

Bruce Anderson of the New England Power Generators Association (NEPGA) asked the RTO to make a market rule change to avoid suppressing capacity market prices as a result of its proposed gross load forecast reconstitution methodology.

The NEPOOL Reliability Committee on July 21 supported Tariff changes to reduce the quantity by which it reconstitutes the long-term peak load forecast. Instead of including all energy efficiency resource megawatts on the system, it would be limited to those that have cleared an FCA. The intent is to produce gross load forecasts that reflect the amount of EE that will clear in that FCA and avoid counting EE resources with capacity supply obligations (CSOs) as both supply and demand.

The change approved by the RC would set the quantity of load reconstitution based on a trend line reflecting historical measures of EE CSOs compared to the level of installed EE.

Anderson said limiting reconstitution to the trend line based on the forecast could result in EE megawatts clearing in the FCA exceeding the level of forecast EE megawatts reconstituted for that auction.

“If that were to occur, the FCA will understate demand and artificially suppress clearing prices,” NEPGA said in a presentation. “In addition, a lack of a companion market rule change will leave open the possibility of ‘double counting’ EE megawatts, i.e., to count those megawatts as both supply (though the acquisition of a CSO) and demand (by failing to reconstitute for that quantity).”

Anderson gave an example in which the trend line found 2,000 MW of EE will clear in the FCA, but the market clears 2,500 MW.

“The additional 500 MW of EE CSO cleared beyond the reconstitution would have the same effect as understating the capacity requirement by 500 MW and artificially suppress the FCA clearing price. The market would also double count the 500 MW,” he said.

Anderson suggested the region adopt one of two options:

Do not qualify EE as capacity supply above the level of EE reflected in the reconstituted peak load forecast; or
add a constraint in the FCA clearing process to prevent EE megawatts from clearing beyond the level of EE reflected in the peak load forecast.

NEPGA asked that the RTO agree to change Market Rule 1 before the September PC vote on the Tariff changes. It asked that the market rule changes be effective for the first implementation of the Tariff change in FCA 16.

Dynamic Delist Bid Threshold

ISO-NE’s Matt Brewster briefed stakeholders on a proposed revision to the methodology the RTO uses to recalculate the dynamic delist bid threshold (DDBT) for FCA 16. The threshold was last updated for FCA 13.

The DDBT sets the price range above which static delist bids are subject to pre-submittal and cost reviews.

Suppliers controlling enough capacity to benefit from market power whose bids exceed the threshold may have those bids reduced by the Internal Market Monitor.

Brewster said the RTO attempts to identify delist bids that may represent market power without unnecessarily interfering in competitive price formation.

ISO-NE’s proposed recalibration method would estimate the competitive clearing price for the next FCA using public data: the last FCA’s cleared supply and clearing price and forecasted demand changes (net installed capacity requirement (ICR), net CONE) for the next FCA.

Brewster said the recalibration estimate showed an average 25% error for FCA 9 through 15 compared with a 39% error with the current “manual” estimation.

He said the proposal’s use of current and forward-looking market information should improve accuracy and allow it to “catch up” with unforeseen market changes by the next period. It also will be aided by the recent transition to demand curves based on the marginal reliability impact (MRI) of capacity, he said.

The committee also heard from Vice President of Market Monitoring Jeff McDonald, who said he sees the function of the DDBT as avoiding mitigation for resources whose bids are too low to create market power concerns. “Constructing the DDBT to achieve this goal requires a method that can reasonably be expected to produce a threshold price that is below the auction clearing price,” he said in a memo to the committee.

McDonald said expanding the function of the DDBT to “support” prices or “complement” the Competitive Auctions with Sponsored Policy Resources (CASPR) could interfere with competitive price formation. “I am not in favor of expanding the function of the DDBT specifically to (i) serve a price support purpose or (ii) increase the amount of capacity that may opt into the Supplemental Auction. Artificial price supports (whether explicit or by way of allowing uncompetitive bidding) introduce inefficiencies, resulting in excess capacity and cost.”

Parameters for FCA 16

ISO-NE’s Deborah Cooke gave a presentation on the recalculation of gross CONE, net CONE and offer review trigger prices (ORTPs) for FCA 16 with a focus on the proposed “level of excess” adjustment for energy and ancillary service (E&AS) revenue calculations.

Cooke addressed a stakeholder suggestion that net CONE estimates should reflect the region’s current capacity surplus rather than using the assumption that the system is “at criterion” — with supply and demand perfectly balanced to achieve the region’s one-day-in-10-years loss-of-load expectation (LOLE).

ISO-NE estimates its excess capacity for FCA 16 is 791 MW, based on an expected net ICR of 33,165 MW and CSOs from FCA 14 of 33,956 MW. (See ISO-NE Capacity Prices Hit Record Low.)

Cooke said the RTO opposed an approach that used the same gross CONE value but calculated the E&AS offsets reflecting the system at surplus.

ISO-NE opposes the change because increased capacity tends to reduce expected E&AS revenues, which would increase the net CONE estimate above the RTO’s proposed value, Cooke said. She said this would induce new competitive entry, even when the system already has more capacity necessary to meet its LOLE standard.

Brett Kruse of Calpine questioned the RTO’s example, saying he was unaware of any generation developer that would rely solely on ISO-NE price estimates.

“I don’t think any developer of any stature would pretend that we’re at equilibrium as they’re figuring out whether their projects go forward,” he said. “I think the ISO’s price point is only one aspect of that, if that. That’s why I think the whole philosophy that you’re building the example on is inaccurate.”

[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved their remarks afterward to clarify their presentations.]

Robert Stoddard, who made the case for assuming a surplus on behalf of NEPGA at the MC’s July meeting, said Cooke’s conclusion depends on the slope of the E&AS price curve being steeper than the slope of the MRI.

“My guess is you could construct a different set of examples by using a steeper MRI value and find that this problem does not occur,” he said. He elaborated on his point in a presentation later in the meeting.

Kruse said after the meeting that generators are hurt by the RTO’s use of inconsistent planning parameters. “One of my concerns is not just the ‘at criterion’ argument here but the fact that they use different metrics; they factor in the oversupply as well as the upcoming state-mandated [resources] when setting the DDBT threshold. … We lose on both sides of the equation.”

Votes by the MC on the DDBT threshold and updated FCM parameters are expected in October with the PC voting in November.

August 18, 2020

MISO Pledges More Cost Allocation Work After Overhaul

MISO is not giving itself time to celebrate after FERC recently accepted its transmission cost allocation plan, promising more such work on long-term and interregional projects.

“We made it. We got across the finish line. After about three years of stakeholder discussion and a year and a half of FERC rejections, we did it,” MISO Senior Manager of System Planning Jarred Miland joked during the Regional Expansion Criteria and Benefits Working Group’s (RECBWG) teleconference Thursday.

MISO’s plan lowered the voltage threshold for market efficiency projects (MEPs) from 345 kV to 230 kV and eliminated the 20% postage-stamp allocation in favor of allocating full costs to benefiting transmission pricing zones. It also added two new benefit metrics based on whether a project can reduce dependency on the RTO’s transmission contract path with SPP or eliminate needs for other reliability projects. FERC approved the plan in late July. (See MISO Cost Allocation Plan Wins OK on 3rd Round.)

But the RECBWG’s work on transmission project cost allocation is far from over.

“I feel like it was time to take a nap, but then [Vice President of System Planning Jennifer Curran] kicked off expanded long-range transmission planning yesterday,” Miland said, referring to Curran’s announcement Wednesday to the Planning Advisory Committee that MISO will explore long-range transmission solutions — and may have some project recommendations as soon as next year.

The working group will likely forge new cost-allocation methodologies for any long-range transmission projects that may result. Several stakeholders asked when and how the group would approach the effort.

“We have to figure out what we’re talking about first,” Miland said in asking for patience. Long-range transmission discussions are continuing in MISO’s planning committees, and Miland said the RECBWG must wait to see what projects develop before it devises cost-sharing methods.

“It’s not baked yet; it’s not ready for primetime,” he said.

Miland also said the grid operator is now considering another filing to lower the voltage threshold on interregional MEPs with PJM from 345 kV to 230 kV.

That seemed to confuse stakeholders, who said the interregional project allocation voltage threshold was already lowered to 100 kV after a 2013 complaint at FERC by Northern Indiana Public Service Co. against the MISO-PJM interregional planning process.

Miland clarified that currently, the RTOs’ interregional economic projects between 100 and 345 kV are allocated to benefiting transmission zones based entirely on the original adjusted production cost metric. MISO is proposing to additionally use the two new benefits metrics to evaluate 230-kV+ MISO-PJM interregional projects.

“I think it would be a pretty simple filing to do,” Miland said. MISO’s rationale is that it would align both the RTO’s regional and interregional project evaluations, he said.

But Clean Grid Alliance’s Natalie McIntire argued that because FERC ordered a 100-kV threshold on MISO-PJM interregional projects, the RTO should also apply that to any benefit metrics.

Some stakeholders asked if MISO would also consider a filing applying the two new benefit metrics to economic projects with SPP.

“Frankly, we have not had any conversations around that,” Miland said.

August 18, 2020

GridLiance, Xcel Battle over Tx Qualifications

SPP may have been incorrectly charging transmission customers for their use of certain facilities, GridLiance High Plains says.

The independent transmission operator said a recent FERC ruling in a dispute between it and Xcel Energy Services “calls into question” how the Tariff’s Attachment AI has been applied.

Xcel has protested GridLiance’s inclusion of its Oklahoma Panhandle facilities in its annual transmission revenue requirement, saying they do not qualify for regional cost allocation under the Tariff and would result in a cost-shift to its Southwestern Public Service subsidiary, which shares the same transmission pricing zone.

Responding to a certified question from an administrative law judge presiding over settlement proceedings in the dispute, the commission ruled Aug. 7 that qualifying as a transmission facility under Attachment AI does not eliminate the need to pass the seven-factor test established by Order 888 (ER18-2358, ER19-1357).

GridLiance Xcel Transmission — GridLiance High Plains President Brett Hooton during an SPP transmission-planning meeting | © *RTO Insider*

FERC established the test in 1996 to identify which facilities would be under the commission’s jurisdiction and what facilities would remain under state jurisdiction in states using unbundled retail wheeling. The test says local distribution facilities are normally low voltage, in close proximity to retail customers and primarily radial. It also says that power flows into local distribution systems, rarely flowing out.

“We find that the seven-factor test may be applied either to classify or declassify any facility as a transmission facility under Attachment AI,” FERC said in its Aug. 7 ruling. “Parties are not precluded from seeking a determination from this commission or state commissions to classify or declassify any facility under the … seven-factor test.”

“Notably, this order impacts much more than just this case,” GridLiance High Plains President Brett Hooton said in a statement. He said the ruling raises questions about Attachment AI “and if transmission customers have been paying SPP rates for facilities that should have been directly assigned to a smaller set of customers.”

SPP spokesperson Meghan Sever disagreed, saying the grid operator’s interpretation of the order says it has “implemented Attachment AI correctly over the years.”

“If an entity wished to challenge the inclusion of facilities into a zonal rate, the challenger has that right before a state commission or FERC using the seven-factor test,” she said in an emailed statement.

‘Contentious Subject’

The ALJ said the seven-factor test has been a “contentious subject” of prehearing motions in Xcel’s challenge to GridLiance’s 2019 informational filing on its projected net revenue requirement. The commission ordered the dispute into settlement proceedings last October. (See FERC Sets GridLiance ATRR Dispute for Settlement.)

The judge said that GridLiance argues that, based on the commission’s clarification in the October 2019 order, the seven-factor test is a fallback used to classify transmission facilities when they fail to meet any of Attachment AI’s criteria. Xcel contends that the test’s outcome is the ultimate determinant of whether a facility qualifies as a transmission facility under Attachment AI.

The Tariff attachment defines transmission facilities as those that meet any one of six criteria:

All existing 60-kV or above non-radial power lines, substations and associated facilities and all 60-kV or above radial lines and associated facilities that serve two or more eligible customers not affiliates of each other.
Facilities used for interconnecting the transmission zones to each other or that interconnect the grid with other surrounding entities.
Equipment needed to control and protect a facility qualifying as a transmission facility.
Facilities on the high voltage side of a transformer for a substation transforming from a voltage higher than 60 kV to a voltage lower than 60 kV.
The portion of DC ties owned by an SPP transmission owner, including the portions operated below 60 kV.
Facilities operated below 60 kV that FERC has determined to be transmission pursuant to Order 888’s seven-factor test.

GridLiance asked that the commission clarify whether the Oklahoma assets qualify as transmission facilities under Attachment AI, and not whether they must also meet the commission’s seven-factor test.

Hooton said GridLiance requested the clarification “to simplify and shorten the hearing.”

“While we were disappointed in the decision, we remain confident in our case and continue to work to ensure Oklahoma Panhandle ratepayers receive comparable and fair cost allocation,” he said.

August 18, 2020

Industry Pushes Back on FERC Cyber Incentives

Stakeholder comments on FERC’s proposals for encouraging cybersecurity investments by utilities reveal widespread misgivings about the commission’s planned framework, even as most respondents acknowledged the need for action on protecting the grid from cyber threats (AD20-19).

FERC solicited comments in June on a white paper calling for an incentive framework that would complement the current Critical Infrastructure Protection standards, which the commission called an “effective technical baseline for cybersecurity practices.” The commission proposed two approaches for identifying cybersecurity investments that should be incentivized: one that would encourage entities to apply the current CIP standards voluntarily in areas where they are not currently required — specifically, to low-impact bulk electric system cyber systems — and a more open-ended alternative that would incentivize utilities to meet goals based on the National Institute of Standards and Technology’s (NIST) Cybersecurity Framework.

Commenters Lean Toward Combined Approach

The commission’s first question to stakeholders was which of the two frameworks — or whether a combination of both — should be adopted. A number of respondents endorsed the combined approach; International Transmission Co., for instance, asserted that the NIST framework and the CIP standards are “not mutually exclusive,” while Boston Consulting Group (BCG) favored including the Department of Energy’s Electricity Subsector Cybersecurity Capability Maturity Model as well in order to “provide a comprehensive view of cybersecurity … with the corresponding methodology for cybersecurity maturity assessment.”

The U.S. Bureau of Reclamation was an outlier, arguing for an incentive approach based solely on the NIST framework. Calling the CIP standards “compliance focused [and] overly prescriptive,” the bureau said a NIST-only approach would allow utilities greater flexibility and creativity to craft their own solutions.

FERC Accused of Overstepping Role

The commission also received some sharp dissents, with several commenters focusing on the potential impact to ratepayers. One such criticism came from Transmission Dependent Utility Systems, an ad hoc group of rural electric cooperatives, which said the commission’s incentive plan would essentially allow transmission owners to profit from essential cybersecurity investments rather than simply recouping the costs, potentially raising rates for end-use consumers.

“[Customer] interests are not even an afterthought; they do not draw a single mention, at a time when unemployment is at levels not seen for nearly a century and the media are filled with stories predicting a coming wave of housing and small-business evictions,” the group said. “For this reason alone, it would be appropriate for the commission to direct its staff to reconsider its proposal.”

FERC Cyber Incentives — | *Shutterstock*

It also accused the commission of assuming authority delegated by Congress to NERC, as the CIP-based framework would have the effect — if not necessarily the intent — of applying those standards to systems explicitly excluded by NERC. Supporting this view was the New Jersey Board of Public Utilities, which compared the proposed scheme to “the era of voluntary utility engagement” that was ended by the Energy Policy Act of 2005.

“Congress did not intend for FERC to create reliability standards itself. … It is for NERC, the ERO, not FERC, to utilize its technical expertise in deciding the adequate level of reliability and designing standards that ensure it,” the board said. “While the commission can request that NERC modify the CIP reliability standards, it cannot propose its own mechanisms to augment reliability on a voluntary basis.”

Even those that supported the incentive proposal in general tended to disagree with FERC on specific aspects of implementation. The commission’s question about adopting a sunset date for incentivized cybersecurity investments in order to encourage utilities to keep up to date with the changing security environment attracted dissent from trade group WIRES, which said that because every threat is different, there is no point in “drawing an arbitrary line in the sand” to declare a particular mitigation measure no longer useful.

BCG and the Indiana Utility Regulatory Commission were less categorical in their rejection of sunset dates, but both cautioned against setting them too broadly. The IURC recommended tying sunset periods to the useful life of the upgrade — for example, shorter periods for software that can be replaced relatively quickly, and longer for physical investments that will stay in place longer — while BCG urged the commission to adopt a “review cycle” to periodically reassess utilities’ cybersecurity investments.

Canadian Regulators Urge International Focus

The response from Canada’s Energy and Utility Regulators (CAMPUT) — the Canadian approximation of the National Association of Regulatory Utility Commissioners — sought to remind FERC of the high degree of interconnection between the U.S. and Canadian grids. While Canadian utilities are not under FERC’s jurisdiction, as a practical matter, Canadian provinces normally implement similar or identical reliability standards to those in force in the U.S., as “security is a matter of mutual interest.”

While CAMPUT noted that commenting on the proposed incentive framework would be outside of its prerogatives, the organization voiced concerns that any FERC incentive package could create a “disparity in North American CIP practices” if similar programs were not offered in the Canadian provinces. CAMPUT requested the commission consider a “North American cybersecurity dialogue” that would enable regulators to address this new threat collectively.

“Cybersecurity matters are very different than traditional reliability considerations such as vegetation management, and may require a new approach to address risk,” CAMPUT said. “By utilizing NERC to facilitate such a conversation amongst all stakeholders of the BES, there would be an opportunity to ensure that cybersecurity risks are optimally and collaboratively addressed throughout North America.”

August 18, 2020

FERC Rejects Exelon’s Mystic Complaints Against ISO-NE

FERC on Monday rejected Exelon’s complaint against ISO-NE alleging that the RTO’s request for proposals for competitive transmission projects addressing reliability needs in the Boston area violated its Tariff (EL20-52).

Exelon’s Constellation Mystic Power filed the complaint in June on behalf of its Mystic Generating Station, an eight-unit, 2-GW fossil power plant north of Boston. Constellation charged that ISO-NE was putting the region’s reliability at risk “by prematurely substituting the uncertain outcome” of its RFP “for the certainty provided by Mystic.” (See Exelon Challenges ISO-NE RFP in Bid to Extend Mystic.)

The complaint came two days after the grid operator’s announcement that it had awarded its first RFP under FERC Order 1000, a $49 million project, to incumbent utilities National Grid and Eversource Energy. (See ISO-NE Chooses Incumbent as Boston RFP Winner.)

The RFP was issued to address transmission violations expected with the closing of Mystic Units 8 and 9, whose retirement was extended to May 30, 2024, under a two-year, $400 million cost-of-service contract to preserve the region’s reliability. The National Grid-Eversource project has an in-service date of Oct. 1, 2023, eight months before the end of the contract.

Exelon has been trying to extend the plant’s cost-of-service contract for an additional year. It said ISO-NE violated its Tariff by shortcutting its transmission security review and prematurely culling bids (36 were submitted) received in response to the solicitation.

FERC found that the RFP results provided the grid operator with “sufficient information” to ensure it can address reliability criteria violations without the two retired units. It said ISO-NE conducted the Boston-area needs assessment “to assess transmission security needs resulting” from Mystic 8’s and 9’s retirements.

“Based on the [assessment’s] results … ISO-NE issued the corresponding Boston RFP, which was designed to address the transmission security needs caused by the retirement of Mystic 8 and 9 and involved modeling of whether each proposal addresses the identified reliability needs,” the commission wrote. “For those reasons, we find that ISO-NE was not required and, given the information it obtained from the Boston RFP results, had no need to use the network model in order to comply with [the] Tariff.”

FERC also disagreed with Constellation’s argument that the RTO had violated or circumvented the Tariff by depriving Mystic 8 and 9 of being able to receive compensation from the February 2021 forward capacity auction (FCA) for providing transmission security.

The commission also rejected Constellation’s contention that ISO-NE modified its planning procedures to qualify the National Grid-Eversource project in time for Forward Capacity Auction 15 in 2021, which will procure resources for capacity commitment period 2024/25. The New England Power Pool Participants Committee in June approved over Exelon’s opposition Planning Procedure 10 (PP10), revising the rules for determining whether planned transmission can be included in the network model for the studied capacity commitment period.

FERC said the revision is consistent with ISO-NE’s existing authority under its Tariff “to consider transmission enhancements that may address its reliability concerns.” It noted that the RTO said PP-10 is a business practice manual intended to “detail requirements and procedures … that are conducted pursuant to” the Tariff’s provisions.

The commission further noted that ISO-NE’s Tariff allows it to consider transmission projects as part of its transmission security review, giving the RTO “broad authority to address reliability concerns arising from the retirement of a resource ‘through other reasonable means (including transmission enhancements).’”

Exelon announced the retirement of Mystic 8 and 9 for economic reasons, citing the plant’s dependence on more expensive LNG than natural gas from pipelines.

August 18, 2020

MISO Board Primed for 1st Major Interregional Project

MISO’s Board of Directors is expected next month to approve MISO and PJM’s first major interregional transmission project, about a year after the RTOs first recommended it.

The nearly $25 million reconstruction of the 138-kV Michigan City-Trail Creek-Bosserman line in Indiana’s northwestern corner was identified last fall in the 2018/2019 MISO-PJM coordinated system plan. (See MISO, PJM Poised for 1st Major Interregional Project.)

Project costs will be split on a 90-10 basis, with PJM covering the larger share. The 11-mile rebuild is located in MISO’s Northern Indiana Public Service Co.’s (NIPSCO) transmission zone and is expected to be in service by January 2023.

MISO PJM Interregional Project — | *PJM*

PJM’s Board of Managers approved the project at its December 2019 meeting. MISO’s board has yet to meet for a vote.

MISO’s nine-month approval lag comes because it did not have a cost-sharing plan in place for its interregional market efficiency projects (MEPs). After twice rejecting the RTO’s cost-allocation plans, Another Rejection for MISO Cost Allocation Plan.)

“Now that we have cost allocation in place, MISO is going to present this project to our Board of Directors meeting in September to put the final touches on that project approval,” MISO Economic and Policy Planning Adviser Ben Stearney told stakeholders during a virtual MISO-PJM Joint and Common Markets meeting Tuesday.

MISO staff had proposed the project not be regionally allocated in the RTO, reasoning that its 138-kV rating disqualified it from allocation beyond the transmission pricing zone where MISO’s project share is located. The RTO’s two rejected cost-allocation filings reserved regional allocation for interregional MEPs 230 kV and above.

FERC in 2016 lowered MISO’s interregional economic project voltage threshold from 345 kV to 100 kV after a 2013 NIPSCO complaint over the MISO-PJM interregional planning process.

No 2020 Coordinated Plan

There are currently no additional interregional projects on the horizon for the RTOs, which have agreed not to start a two-year coordinated system plan study in 2020.

“We didn’t find any strong issues to support a study,” Stearney said, adding that the RTOs will continue to gather and analyze historical congestion data. He said they will meet in the fourth quarter to discuss potential economic needs and the possibility of a CSP that would begin next year.

August 18, 2020

Dominion Buys Rights to Va. Solar Farm

Dominion Energy is adding to its growing solar portfolio with the acquisition Monday of a generating facility scheduled to be built in Central Virginia.

The Richmond-based company announced it obtained the rights to the 62.5-MW Madison Solar generating facility in Orange County, Va. The facility, owned by California-based Cypress Creek Renewables, will be transferred to Dominion’s contracted assets arm.

Terms of the deal were not disclosed.

Dominion Energy solar farm in Virginia | *Dominion Energy*

Madison Solar has received all state and local permits and is expected to come online by the second quarter of 2022. About 660 acres of land along State Route 20 in Locust Grove are being purchased to house the solar project.

Northrop Grumman will purchase the project’s electricity as well as its renewable energy credits under long-term agreements, according to Dominion. Northrop officials said they anticipate the facility will provide enough renewable power to the grid to match 100% of the electricity used for its Virginia manufacturing and office operations.

Dominion is continuing its plans to add about 16 GW of solar generating capacity through company-owned projects and power purchase agreements it is signing with third-party developers in Virginia. Its proposed long-term integrated resou r ce plan for 2021-2045 would quadruple the amount of solar and wind generation in its previous 15-year plan a response to the Virginia Clean Economy Act (House Bill 1526 and Senate Bill 851). Signed by Gov. Ralph Northam in April, the law established that 16,100 MW of solar and onshore wind is “in the public interest.” (See Va. 1st Southern State with 100% Clean Energy Target.)

Virginia-based SolUnesco began securing the Madison Solar site in July 2016 before selling it to Sol Systems, a solar developer, and then transferring it to Cypress Creek Renewables in early 2019. The project will interconnect to a 115-kV line utilizing an easement for 0.1 miles from the parcel through an application filed with PJM in November 2017 (AC1-076).

“Our mission of powering a sustainable future one project at a time drives us to create valuable partnerships and projects,” said Cassidy DeLine, vice president of project finance for Cypress Creek Renewables. “Our collaboration with Dominion and Northrop Grumman on the Madison project reinforces our commitment to developing solar in the nation’s largest wholesale electricity market, PJM, and delivering long-term benefits for Orange County, Va.”

August 18, 2020

CAISO Blames Blackouts on Inadequate Resources, CPUC

CAISO on Monday blamed inadequate preparation by others for a supply shortfall that caused rolling blackouts over the weekend during the Western heat wave.

During an emergency meeting of the Board of Governors, CEO Steve Berberich immediately jumped to the defense of the ISO, which received the brunt of criticism for ordering statewide rolling blackouts Friday and Saturday.

The California Public Utilities Commission authorizes load-serving entities to procure energy, he said. CAISO has told the CPUC that an additional 4,700 MW would be needed to meet summer peaks during the state’s transition from fossil fuels to renewable energy. The CPUC directed LSEs to procure a total of 3,300 MW by next year, when the shortfall is expected to grow worse, he noted.

“The ISO does not direct procurement. We are the system operator,” Berberich said. “The situation we are in could have been avoided. For many years, we have pointed out to the procurement-authorizing authorities that there was inadequate power available during the [evening] net peak,” after solar has left the system but demand remains high.

The weekend outages occurred as solar power waned, he said. About 12,000 MW of battery storage are needed to store renewable energy, along with an “overbuild” of solar and wind generation to charge the batteries, he said. There’s currently only 200 MW of storage on CAISO’s grid.

Hotter summers caused by climate change also need to be taken into account, Berberich said.

“We have indicated in filing after filing after filing that the resource adequacy program was broken and needed to be fixed,” he said. “That program requires the load-serving entities to only procure to a 50/50 weather forecast. That is the worst weather you might have on average 50% of the time — not to an extreme heat storm like we have now.

“Resource adequacy must be reformed so that every hour of the year is properly resourced,” he said.

The CPUC rejected Berberich’s argument that it was mainly to blame.

“This is a shared responsibility, and we are working with our sister agencies to better understand why this occurred,” spokeswoman Terrie Prosper said in an email. “Our current focus is the public’s safety and to emphasize the importance of energy conservation to reduce the strain on electric supply.”

Demand during the heat wave was in line with predictions and should have been manageable, Prosper said.

“The electricity demand of the last few days is consistent with the level the agencies have for August, and the utilities and community choice aggregators procured the resources that were required to meet the forecasts,” she said. “The question we’re tackling is why certain resources were not available.”

Millions Could be Without Power

CAISO predicted even worse outages Monday and Tuesday than those that roiled the state last week. (See CAISO Warns Blackouts Could Continue, Calls Emergency Meetings.)

It had predicted up to a 4,400-MW shortfall Monday, with rolling blackouts in the afternoon, increasing after sunset. About 3 million customers could lose power, Berberich acknowledged in a call with reporters.

“We have a perfect storm going on here,” Berberich said. “The entire region … is extremely hot. We can’t get the energy we’d normally get from out of state because it’s being used to serve load natively.”

On Monday night, however, CAISO lifted a Stage 2 emergency declaration, saying “no rotating power outages are anticipated, thanks to reduced demand due to consumer conservation and cooler-than-expected weather.” The ISO had not updated its predictions for Tuesday as of press time.

CAISO blackouts — CAISO predicts resource deficiencies of up to 4,400 MW this week. | *CAISO*

The ISO can’t dip deeper into its contingency reserve, which can total thousands of megawatts, because the reserve is necessary to protect the Western grid from failure, CAISO officials said.

John Phipps, director of real-time operations, said CAISO must follow NERC and WECC standards that protect the Western Interconnection from failure should a large generator drop offline or another serious problem occur.

CAISO contains 35% of the load in the interconnection, which stretches from the Rocky Mountains to the Pacific Ocean and into Canada and part of Mexico. A serious disruption in the ISO could prove disastrous to the entire region, Phipps said.

Governor Weighs in

During a televised address Monday, Gov. Gavin Newsom said record-setting heat had set the stage for the blackouts but acknowledged the state was culpable for the crisis.

“We failed to predict and plan for these shortages, and that’s simply unacceptable,” Newsom said. “I am the governor. I am ultimately accountable and will ultimately take responsibility to immediately address this issue and move forward to make sure this simply never happens again here in the state of California.”

Newsom said his office had launched an investigation into the interrelationship among CAISO, the CPUC and the California Energy Commission, which he said have a shared responsibility to maintain reliable electricity delivery.

“We’ll get to the bottom of it, and that’s why that investigation into what happened and its implications for the future will be done swiftly and immediately,” he said.

In the meantime, the state is “working with partners across the spectrum” to alleviate the immediate energy shortages, including reducing consumption at the state’s ports, allowing utilities to tap resources reserved for public safety power shutoffs from wildfires, and procuring more power from the Los Angeles Department of Water and Power (LADWP) and the State Water Resources Control Board, the governor said.

Newsom also called for a broader examination of how California will continue to reliably serve electricity customers while pursuing its ambitious renewable energy and decarbonization targets. State law requires all LSEs to supply 100% carbon-free energy to retail customers by 2045.

“We now have to sober up to the reality that in this transition, we’re going to have to do more and be much more mindful in terms of our capacity to provide backup [energy] and insurance,” he said.

Convergence Bidding

In a move signaling that its own market mechanisms might be contributing to its real-time shortfalls, CAISO on Sunday notified market participants that it would suspend convergence bidding throughout its footprint beginning Monday for the Aug. 18 trading date.

“As a result of the record-breaking heat wave that has led to load curtailments, the California ISO has determined that convergence bidding is detrimentally affecting the ISO’s ability to maintain reliable grid operations,” the ISO said in a market notice.

Convergence — or virtual — bidding allows market participants to hedge their physical positions and limit exposure to day-ahead and real-time price differentials. The bid is a purely financial one, implying no obligation to take or deliver electricity. Instead, a market participant buys or sells “virtual” energy in the day-ahead market, a position required to be automatically liquidated in the opposite direction in real time.

CAISO said Monday that it had eliminated convergence bidding to give it a clearer picture of day-ahead market conditions, but the practice has a checkered history in California.

A week after implementing convergence bidding at interties into California in February 2011, the ISO suspended bids at nodes on nine interties linked to the Mountain West because of a software glitch that risked overscheduling those points in the physical day-ahead market.

That incident was followed months later by the more serious discovery that some CAISO market participants were using virtual supply bids on the interties to offset virtual demand bids at nodes located just inside the state, a gaming strategy that produced no benefit for the physical market and cost the ISO more than $50 million.

The scheme prompted CAISO to suspend intertie convergence bidding altogether, and it completely eliminated the bidding at interties in March 2016. (See FERC Eliminates Intertie Convergence Bidding in CAISO.)

Robert McCullough, an energy economist who was among the first to spot the market manipulation behind the Western energy crisis of 2000/01, pointed to why the convergence bidding market that still exists inside the CAISO remains “worrisome.”

“By allowing node-level bids and not requiring physical assets, this allows any single party the ability to dominate transactions at a specific location. Enron called such exploits ‘load shift,’” McCullough told RTO Insider. “However, that exploit required lying to the ISO about the ‘virtual’ supplies.

“The convergence market doesn’t even require a lie — just a willingness to gamble on the ISO’s computer systems,” he said. “Past experience has tended to make this less of a gamble than you might think since critical information is often learned by specific market participants and then used to advantage.”

McCullough, long an outspoken critic of organized electricity markets, questioned how Friday’s unforeseen demand could have sent CAISO into a Stage 3 emergency.

“Their 15% reserve margin should have handled this easily,” he said. “The congestion data indicates that this is a Southern California issue, although, mysteriously, LADWP was not affected.”

CAISO’s demand peaked at 46,777 MW on Friday, above the 1-in-2 peak forecast of 45,907 MW in the ISO’s 2020 Summer Loads and Resources Assessment, but below the 1-in-5 (47,755 MW) and 1-in-10 (48,457 MW) forecasts. That assessment also estimated a 3.7% probability the ISO would enter Stage 2 operations this summer and a 1.1% probability for Stage 3.

CAISO on Sunday also declared a capacity procurement mechanism (CPM) significant event to solicit any available resources not already offered into the CPM’s competitive solicitation for August.

Resource owners were urged to contact the ISO if they were willing to accept its soft offer cap of $6.31/kW-month. CAISO will give preference to resources able to deliver energy from 2 p.m. to 10 p.m.

August 16, 2020April 30, 2025

CAISO: Blackouts May Continue, Calls Emergency Meetings

CAISO warned residents Sunday that rolling blackouts could continue for days and called emergency meetings of its Board of Governors to address the system deficiencies.

“A persistent, record-breaking heat wave in California and the Western states is causing a strain on supplies, and consumers should be prepared for likely rolling outages during the late afternoons and early evenings through Wednesday,” the ISO said in a news release. “There is not a sufficient amount of energy to meet the high amounts of demand during the heat wave.”

CAISO declared a Stage 3 emergency for two hours Friday night, ordering rolling blackouts across the service territories of the state’s three big investor-owned utilities. Hundreds of thousands of customers in Northern and Southern California were without power for an hour or more.

The ISO triggered a Stage 3 emergency again Saturday night for 20 minutes when, it said, 1,000 MW of wind power and a 470-MW power plant dropped offline.

“The load was ordered back online 20 minutes later at 6:48 p.m., as wind resources increased,” CAISO said.

Pacific Gas and Electric said it began restoring power to 220,000 residents on California’s coast and in the Central Valley after the brief outage but warned that restoration could take additional time.

Earlier in the day, CAISO had assured residents on Twitter that the “ISO is expected to cover electrical demand with no stage emergencies planned at this time.”

The CAISO board met Sunday in closed executive session and scheduled a public teleconference for Monday at 11 a.m.

Friday was the first time the ISO, which encompasses 35% of electrical load in the Western Interconnection and covers 80% of California, went to its highest emergency level since market manipulation schemes and rolling blackouts plagued the state during the Western energy crisis of 2001. A similar heat wave in 2006 strained the system but did not cause blackouts.

“The ISO requires load curtailments [and] use of interruptible load, and requests out-of-market and emergency energy from available sources,” CAISO said in an alert. “Maximum conservation efforts are requested.”

A Stage 3 alert means the “ISO is unable to meet minimum contingency reserve requirements, and load interruption is imminent or in progress.” Notices are issued to utilities of potential interruptions, CAISO says on its website.

CAISO spokeswoman Anne Gonzalez said the ISO had ordered 1,000 MW of load shed.

PG&E said it had been directed by CAISO to “turn off power to approximately 200,000 to 250,000 customers at a time in rotating power outages given the strain on the power grid during the statewide heat wave. Other power utilities in the state are being directed to take similar actions.”

Southern California Edison and San Diego Gas & Electric also shut off power to tens of thousands of customers. Roughly 750,000 account customers — and at least 2 million residents, based on average household size — lost power between 6:36 p.m., when the emergency was declared, and 8:54 p.m., when CAISO lifted its declaration.

Customers of public utilities including the Los Angeles Department of Water and Power and the Sacramento Municipal Utility District were not affected by the blackouts. The utilities operate their own power lines and generation resources.

The transmission grids of the three large IOUs are operated by CAISO.

Lead-up to Blackouts

On Friday afternoon, CAISO issued a Stage 2 alert after capacity dipped below its 15% reserve margin. It said it had taken all possible mitigation measures and was still unable to meet its energy requirements.

The heat wave drove temperatures into the triple digits in Sacramento, Phoenix, Las Vegas and other areas of the inland West on Friday and is predicted to last into next week. Temperatures in Los Angeles and typically cooler cities such as Portland, Ore., rose well beyond summer norms.

ERCOT, which instituted rolling blackouts during an extreme cold snap in February 2011, weathered the heatwave amid record-setting demand in Texas over the weekend. Dallas, Austin and other cities topped 100 degrees Fahrenheit.

The temperature reached 120 degrees in Death Valley Friday. | National Park Service

Throughout the West, families working and learning from home during the coronavirus pandemic cranked up their air conditioners, straining the system.

CAISO’s day-ahead forecast predicted a peak of 46,258 MW on Friday, but the ISO raised it to 46,824 MW in the afternoon. Available supply, at its peak, was about 53,000 MW but declined to 48,378 MW as solar power dropped offline when the sun set.

The ISO said it was “declaring a Stage 3 electrical emergency due to high heat and increased electricity demand. The emergency initiates rotating outages throughout the state. A Stage 3 Emergency is declared when demand outpaces available supply. Rotating power interruptions have been initiated to maintain stability of the electric grid.”

“The Stage 3 emergency declaration was called after extreme heat drove up electricity demand across California, causing the ISO to dip into its operating reserves for supply to cover demand,” it said. “The California ISO is working closely with California utilities and neighboring power systems to manage strain on the grid and to restore the power grid to full capacity. As portions of the grid are restored, local utilities will restore power in a coordinated fashion.”

“Although a Stage [3] emergency is a significant inconvenience to those affected by rotating power interruptions, it is preferable to manage an emergency with controlled measures rather than let it cause widespread and more prolonged disruption,” CAISO said.

National Weather Service map | National Weather Service

On Thursday and again on Friday morning, CAISO issued a “flex alert” urging customers to voluntarily conserve power, including by setting thermostats at 78 F. It restricted utility maintenance operations and then issued a warning midday Friday followed by the first emergency alert at 3:25 p.m.

The Stage 2 emergency, announced Friday afternoon, was the ISO’s first in 15 years.

Unexpected Early Test

The shortfall tested the state’s transition from fossil fuels and nuclear power to renewable resources. The percentage of renewables serving load fell from about 30% midday to single-digits after sunset as natural gas plants ramped up to meet demand.

Natural gas generation ramped up steeply Friday. | CAISO

Gas generation began the day providing roughly 11,500 MW to the CAISO grid but was pumping out nearly 26,000 MW after an exceptionally long, steep ramp from 10 a.m. to 7 p.m.

Renewables in CAISO’s system, mainly solar power, peaked at more than 13,000 MW at 2 p.m. but began to fall off just as demand increased late in the afternoon.

Imports from other Western states gradually decreased throughout the day to about 3,500 MW at 4 p.m. as the heat wave drove demand in neighboring Nevada, Arizona and other states. Imports recovered in the evening, helping to alleviate the shortfall.

CAISO and the California Public Utilities Commission have repeatedly warned that the combination of retiring natural gas plants and constrained imports could result in capacity shortfalls starting as soon as this summer and grow significantly worse in the next three years. (See CAISO, CPUC Warn of ‘Reliability Emergency’.)

However, the ISO reported in May that it expected to be able to get through this summer without a shortfall such as Friday’s. (See CAISO Predicts Adequate Summer Capacity.)

Resource adequacy in the West has become a major topic for organizations such as WECC and the Northwest Power Pool. The added problems of catastrophic wildfires and the COVID-19 pandemic have exacerbated those concerns. (See WECC Tackles Wildfires as Reliability Threat.)

Robert Mullin and Rich Heidorn Jr. contributed to this report.

August 16, 2020

NY PSC Gets Update on Tx Planning, Investment Efforts

The New York Public Service Commission heard a progress report Thursday on a grid study underway to identify distribution upgrades, local transmission upgrades and bulk transmission investments needed to meet the state’s clean energy goals, as well as brief outlines of three separate petitions on large-scale public policy transmission needs (Case No. 20-E-0197).

“We need more; we need smarter; we need faster transmission,” PSC Chair John B. Rhodes said. “Recognizing this, there is necessarily a lot going on.”

Tammy Mitchell, chief of bulk electric systems for the state’s Department of Public Service (DPS), said the study results — due Nov. 1 — will inform two separate investment plans to be established by the PSC, one related to distribution and local transmission investments or upgrades, and another plan for bulk system transmission investments.

The commission in May authorized the study as directed the previous month by the Accelerated Renewable Energy Growth and Community Benefit Act (A09508), which set up the Office of Renewable Energy Siting and required investment plans to meet the renewable energy targets of last year’s Climate Leadership and Community Protection Act (CLCPA). (See NYPSC Launches Grid Study, Extends Solar Funding.)

The CLCPA mandates that 70% of the state’s electricity come from renewable resources by 2030 and that electricity generation be 100% carbon-free by 2040. Its clean energy targets include doubling distributed solar generation to 6 GW by 2025, deploying 3 GW of energy storage by 2030 and raising energy efficiency savings to 185 trillion BTU by 2025.

The PSC in May also directed utilities to file proposals to incorporate the statutorily mandated environmental benefits in utility planning and investment criteria, and proposals to prioritize such projects in their capital spending and apply benefit/cost analysis for potential investments. It also directed them to file cost-containment, cost-recovery and cost-allocation methods. All proposals are due no later than Oct. 5.

The commission will seek public comments on the grid study results and utility proposals and expects to be able to move ahead with distribution and local transmission upgrades early in 2021, Mitchell said.

Three Projects Now Being Sited

New York currently has three 345-kV transmission projects underway that were selected through the NYISO Public Policy Transmission Planning process and are in the Article VII — or full review — siting process, Mitchell said.

NYISO selected NextEra Energy’s Empire State Line proposal in October 2017 to obtain full output of the New York Power Authority’s (NYPA) Niagara hydro facility, maximize Ontario inflows and maximize exports of renewable resources out of western New York to the rest of the state. The line is expected to be in service in the first half of 2022.

NY PSC transmission — NYISO’s 2019 CARIS Report shows renewable generation pockets in western New York. | *NYISO*

The other two projects underway were selected by NYISO last year as part of the broader AC Public Policy Transmission Project. One being built by LS Power and NYPA will increase transmission capacity by approximately 800 MW at the Central East (Segment A) electrical interface, well above the commission’s minimum of 350 MW, she said. (See NYISO Board Selects 2 AC Public Policy Tx Projects.)

Another by New York Transco for the Upstate New York/Southeast New York (Segment B) interface will run from the Albany region to the Hudson Valley region, increasing transfer capability by about 2,000 MW, well above the commission’s minimum of 900 MW.

Both of the latter projects are expected to be in service by December 2023, Mitchell said.

Fast-track Proposals from NYPA, DPS, LIPA

On July 2, NYPA and the DPS submitted a two-part petition to the PSC that included DPS staff’s proposed criteria for determining priority projects and a NYPA proposal that the commission designate its “Northern NY Project” as a priority project to be developed under the new siting law.

The DPS criteria included an investment’s potential for unbottling existing renewable generation, avoiding future congestion and increasing the deliverability of existing and anticipated baseload renewable or low-carbon generation. It also factored in whether an early in-service date would increase the likelihood of meeting CLCPA targets and considered the transmission investment’s eligibility for expedited review under Article VII and its implementing regulations.

The redacted public version of the petition does not include cost estimates, but in it, NYPA estimates the project will result in approximately 7.5 TWh of avoided renewable curtailments annually, starting in 2025, and result in production cost savings of approximately $99 million per year, for a net present value of approximately $1 billion over a 20-year period.

The Northern NY Project “will establish a continuous 345-kV path that greatly expands the deliverability of renewable generation from northern and western New York to load centers,” while compounding the benefits from the Segments A and B projects already underway, NYPA said.

On July 13, NYPA filed another petition asking the PSC to designate its Western New York Energy Link Project (WNYEL) to also be a priority for the state.

NYPA said the project will upgrade assets owned by National Grid, New York State Electric and Gas and NYPA to reduce or eliminate existing curtailment of renewable and carbon emission-free generation, facilitate the siting of new renewable generation in the area and increase transfer capability from the region to load centers by approximately 600 MW.

The WNYEL project includes reconductoring two 42-mile Packard-Huntley-Gardenville 230 kV circuits; a tower separating 230 kV lines; converting the existing double-circuit common tower structures to single-circuit single tower structures; and installing a new phase angle regulator at the South Ripley substation to control the flow from PJM to the New York Control Area.

NYPA said NYISO’s 2019 Congestion Assessment Resource Integration Study, issued in June 2020, supports the need for additional transfer capability near the Niagara Power Project, citing the study’s identified renewable generation pockets. (See Bulk Tx, 115-kV Upgrades Needed for NY 70×30 Goal.)

NYPA asked that if the PSC does not designate WNYEL as a priority project, the commission instead direct National Grid and NYSEG to undertake the necessary improvements to develop the project in coordination with NYPA.

Collectively, NYISO projected that Zone A will be the site of more wind and solar generation than any other zone except for Zone J (New York City), and found three potential areas of transmission bottlenecks, identified as pockets W1, W2 and W3. NYISO projected curtailments of 20 to 30% for solar generation between and 5 to 8% for land-based wind resources.

The Long Island Power Authority (LIPA) on July 30 submitted to the PSC a FERC Order 1000 referral, as allowed under the NYISO Tariff, seeking the commission’s determination that the 2018 Offshore Wind Standard is a public policy driving the need for transmission. LIPA also asked the PSC to find a need for additional export capability on the Consolidated Edison interface, as well as for upgrades to the local transmission system on Long Island to support the 2018 OSW procurement target of 2,400 MW (18-E-0623).

Two years ago, NYISO solicited proposals for transmission needs driven by public policy requirements and, in October 2018, submitted to LIPA seven of the 15 proposed needs it received from stakeholders, including one from PSEG Long Island that summarized the OSW procurements as giving “rise to the need to optimize transmission development and to create a ‘transmission backbone’ structure in order to meet the state’s ambitious goal of 2,400 MW of resources by 2030.”

“The transmission system was originally built to serve native load of monopoly utilities, and ratemaking at both the state and federal level was based on that,” Commissioner John B. Howard said. “This new paradigm is as dramatically different from that as can be imagined, since the primary focus of our bulk transmission system will now be to enhance and provide environmental benefits through zero-emissions generation across the state.”