The California Public Utilities Commission unexpectedly postponed its planned vote Thursday on Pacific Gas and Electric’s bankruptcy reorganization plan because a party to the proceedings improperly sent out a mass email earlier in the week.
“This proposed decision is being held because a party sent an ex parte communication by email on Tuesday,” President Marybel Batjer said. “This was a prohibited ex parte communication under state law and the CPUC rules of procedure.”
The CPUC was planning to vote on an administrative law judge’s decision to approve PG&E’s Chapter 11 plan with some modifications, including enhanced oversight by the commission.
CPUC President Marybel Batjer
Batjer angrily denounced the party’s action and warned of possible consequences for issuing a communication during a required quiet period from May 15 until the Thursday vote.
“For my part, I am not pleased that an error in understanding our rules or a disregard for them will delay the vote on a proposed decision,” Batjer said. “We will implement this delay to ensure that we have very clearly taken the procedural steps we need to take to ensure we issue a legally sound decision.”
The email was sent by William Abrams, a wildfire victim and party to the CPUC proceedings, who sent an email with attached documents to hundreds of individuals on the CPUC’s service list.
“This is to notice the Commission and parties of this proceeding regarding my objections and those of the [Tort Claimants Committee] filed in the U.S. Bankruptcy Court (Case #19-30088-DM),” it said in part.
Abrams has represented himself in the bankruptcy court proceedings and has urged delay to more closely examine PG&E’s reorganization plan. He apologized in a notice to the CPUC Wednesday.
“My understanding was that posting publicly available documents to the docket for this proceeding was not a violation of the quiet period,” Abrams said. “However, I apologize if this was not in keeping with policies and procedures of this proceeding and of the commission.”
Batjer gave parties, including PG&E, a chance to respond to the email until midnight Thursday and insisted that the commission’s rules against ex parte communications during the “quiet time” before a vote be strictly obeyed.
“We will not tolerate any further delay to this proceeding,” Batjer said.
The CPUC could pursue “remedial action” if it finds a party intentionally delayed the vote, she said.
The vote will now be held on May 28, one day after a hearing is scheduled to start in the U.S. Bankruptcy Court in San Francisco on PG&E’s Chapter 11 plan. The quiet time for the next hearing will last from May 22 until the conclusion of the hearing, she said.
PG&E needs the bankruptcy court and CPUC to approve its reorganization plan by June 30 in order to participate in a state insurance fund for future wildfires. Massive fires sparked by its equipment caused PG&E to seek bankruptcy protection in January 2019.
A new study finds that analyses by PJM’s Independent Market Monitor predicting increased costs for regions that exit PJM’s capacity market are skewed by their assumptions and should be redone to presume exiting states will maximize imports to counter local market power.
“The reports’ cost estimates risk confusing or even misleading states to the extent they suggest confidence that FRR [fixed resource requirement capacity procurements] will yield higher prices than continued reliance on PJM’s RPM [Reliability Pricing Model],” said the report by Rob Gramlich, president of Grid Strategies, and consultant Miles Farmer, a former attorney for the Natural Resources Defense Council.
“At this stage, given uncertain market dynamics and questions surrounding how states and utilities may implement FRR, it is difficult for anyone to render a confident and accurate prediction of FRR prices. While Monitoring Analytics provides useful data and a structure to evaluate FRR costs, we recommend that it provide a more complete picture of the potential costs of FRR by conducting additional scenarios applying the reasonable assumption that FRR entities would competitively procure externally-located capacity.”
The Monitor said its analyses in Illinois, Maryland and New Jersey indicate ratepayers are likely to see costs increase if their jurisdictions leave the PJM capacity market for an FRR. The reports also concluded that the expanded minimum offer price rule (MOPR) is unlikely to increase capacity costs, at least for the first couple of auctions. (See PJM Monitor Finds Capacity Exit Costly for NJ.)
State officials in Illinois, Maryland and New Jersey are considering alternatives to the PJM capacity market. | Monitoring Analytics
The Gramlich-Farmer report did not attempt to quantify the impact of an FRR, but it said “a reasonable set of assumptions yields lower price estimates for FRR than for continued reliance on RPM.”
The authors said any analysis should assume that an FRR service area located partially or fully within a constrained locational deliverability area (LDA) would seek to purchase as much capacity as possible at lower prices outside the LDA before “meeting the rest of internal load with internal generation.”
They said states should request that the Monitor provide them data on the maximum import capability into constrained zones, which will determine the minimum internal resource requirements.
“Monitoring Analytics reports all suffer from a central flaw: they assume that FRR entities would purchase as much capacity as possible from internal resources, importing capacity only to the extent ‘needed to cover any shortfall in meeting the FRR obligation,’ even where the FRR entity is located within a transmission-constrained area where local capacity prices are higher than those of the importing region(s),” the report said. “Monitoring Analytics never justifies this assumption, which leads to higher prices across all scenarios that modeled an FRR entity located entirely or partially within a transmission-constrained LDA.
“While this framing suggests an apples-to-apples cost comparison, in fact it yields skewed results that in effect presume an irrational capacity purchasing strategy by the FRR entity.”
Bowring continued to stand behind his analyses Thursday, saying, “It is extremely unlikely that the FRR approach will result in prices equal to or lower than market prices.”
He criticized the Gramlich-Farmer report’s references to the resource adequacy policies of MISO and CAISO, saying neither are markets. “MISO relies on cost-of-service regulation with its attendant high costs and lack of competition, and CAISO relies on an inefficient process of bilateral contracting for capacity.”
The report noted that the Monitor found a 5.4% reduction for an FRR in Maryland’s PEPCO LDA — which is not constrained by a binding transmission import limit — under a scenario in which capacity prices would be equal to the most recent Base Residual Auction.
Gramlich and Farmer also questioned why half of the Monitor’s scenarios assumes all suppliers — not just pivotal suppliers that possess market power — will be paid prices at the seller offer cap.
“Market power is a significant challenge that states, PJM and FERC should carefully address in designing and implementing FRR. But it is important to recognize that FRR does not ‘create’ market power, which flows from the underlying dynamics of market suppliers’ generation ownership and relevant transmission system constraints,” they said.
They also disagreed with the Monitor’s conclusion that the expanded MOPR will not increase costs in upcoming BRAs. Gramlich this week released a study projecting that the expanded MOPR will cost ratepayers $9.7 billion or more over the next nine years. (See New MOPR Analysis Sees Cost at $1B/Year.)
“MOPR will raise RPM costs to the extent it raises market clearing prices by causing higher priced supply offers and to the extent it forces customers to support the construction or retention of redundant capacity. MOPR also could increase the cost of state programs because state-supported resources that do not clear the capacity market may require more revenue from renewable energy credits (RECs) and other payments in order to cover their costs and be developed as the states desire.”
In contrast, Gramlich and Farmer said, FRR programs could procure capacity from state-supported resources at prices that reflect state subsidies. “The costs of state clean energy policies would also be reduced as compared to BRA with MOPR because state-supported resources could more confidently rely on capacity revenues.”
The authors said lower costs are likely under FRR because it would require only a 15% reserve margin — using a vertical demand curve and fixed MW requirement — rather than the 22% margin in recent RPM auctions, which uses a sloped demand curve. They cited an estimate from ICF that the lower reserve margin under FRR could reduce prices by $15 to $25/MW-day in the near term and $30 to $50/MW-day in the long term.
The study also said FRR would give utilities and states more flexibility because non-performance penalties could be assessed on a physical and portfolio-wide basis rather than as an economic penalty applied to individual units under RPM. They said unit-specific financial penalties have been a disincentive to renewables’ participation in the capacity market.
Bowring questioned why Gramlich and Farmer assert “that the weaker performance incentives in an FRR would be a good thing. “An essential point of the Capacity Performance design was to strengthen performance incentives. One of the strengths of well-designed markets is that investors bear the risks associated with the performance of their assets,” he said.
FRRs could make better use of seasonal resources than RPM, they said, citing a Brattle Group report that concluded separating summer and winter capacity markets in PJM would save consumers $100 million to $600 million annually.
FRRs also could obtain lower prices by giving sellers multi-year price locks. “Price formulas could partially or fully index to RPM. And the purchase could also be combined with energy, ancillary services or environmental attributes providing the purchaser and seller more certainty as to their total costs and revenues.”
The authors acknowledged that PJM rules bar utilities from returning to the capacity auction for at least five years after departing (though PJM allows an exception if state regulatory changes materially affect consumers’ retail choice options).
They also noted concerns that state regulators would have to prevent distribution companies from acting on incentives to favor their own generation under an FRR.
Under PJM rules, the entity responsible for obtaining capacity could be a utility, distribution company or state agency. Legislation pending in Illinois would give such responsibility to the Illinois Power Agency. (See Clock Ticking on Exelon Illinois Nukes Under MOPR.)
FERC on Thursday approved PJM’s proposed energy price formation revisions, agreeing with the RTO that its reserve market was not functioning as intended (EL19-58, ER19-1468).
“PJM made a persuasive case that its current reserve market design must be overhauled,” Chairman Neil Chatterjee said during the commission’s monthly open meeting, held by teleconference because of the COVID-19 pandemic. “PJM showed that the current market mechanism systematically fails to enable PJM to acquire within the market the reserves it needs to operate its system reliably and [that] it fails to send appropriate price signals for efficient resource investment.
“The fact that PJM operators regularly must procure thousands of megawatts of reserves outside of the market construct is evidence of a market design that is unjust and unreasonable.”
PJM filed its proposal unilaterally in March 2019 under Section 206 of the Federal Power Act because stakeholders could not come to a consensus on one plan. It was the culmination of a year’s worth of debate and discussion among stakeholders, RTO staff and members of the Board of Managers. (See PJM Files Energy Price Formation Plan.)
The changes consolidate the tier 1 and tier 2 reserve products, align the products that PJM procures in the day-ahead and real-time markets and revise the height and shape of the operating reserve demand curve. “Together, these reforms will ensure that market forces, rather than out-of-market decisions, drive the procurement of reserves in PJM,” Chatterjee said.
PJM’s new operating reserve demand curve (blue) as approved by FERC, compared to a previously proposed version (green) and old version (red dotted line) | PJM
Commissioner Richard Glick issued a strong dissent, saying that “while I’m concerned that the commission made an unsupported finding that PJM’s existing rate is unjust and unreasonable, I’m even more concerned and particularly troubled that the commission accepted PJM’s proposal to revise the operating reserve demand curve. The commission is replacing marginal-cost pricing with an administrative adder that is going to force consumers to pay scarcity pricing all the time, regardless of whether there was actual scarcity or not. …
“How is it ‘market forces’ when we’re administratively drawing up a curve that makes no sense and the market wouldn’t support? We’re doing it, obviously, to raise prices,” he said. “PJM and others continue to treat low prices — due in large part to a significant amount of excess generating capacity — as a matter that requires market tweaks designed to raise prices. Instead of addressing the true cause of the problem, which is excess capacity, this commission continues to approve proposals that raise prices. And what does that raise in prices do? It further exacerbates the problem.”
The RTO had estimated in a December 2018 white paper that the changes would result in increased costs to load of about $700 million annually, but Glick said the costs could reach up to $2 billion.
Chatterjee acknowledged that “these reforms will affect the amount of reserves procured and the energy and ancillary services revenues resources receive.” To counterbalance the costs to consumers, the commission directed PJM to recognize the new changes in its capacity market’s energy and ancillary services offset, a key variable in calculating the net cost of new entry (CONE) for resources in the RTO’s capacity auctions.
The offset is calculated using energy market results from the three calendar years prior to the Base Residual Auction. Therefore, “an historic energy and ancillary services offset would likely underestimate future energy and reserve market revenues, considering that PJM’s proposal will likely result in increases in the energy and reserve prices compared to the historic values,” the RTO said in the white paper.
Staff had proposed a mechanism that would have estimated the offset had the new rules been in place the previous three years, but the PJM board ultimately declined to include it in the filing. (See PJM Advances Own Energy Price Formation Plan.)
FERC ordered PJM to submit a compliance filing in 45 days to implement the mechanism.
“Recognizing the interplay between these reforms and the pending capacity market reforms,” Chatterjee said, referring to the RTO’s pending compliance filing implementing an extended minimum offer price rule, “we’ve asked PJM to propose an implementation schedule that harmonizes the reforms while minimizing auction delays.”
FERC had not posted the order to its website as of press time.
FERC Chairman Neil Chatterjee pledged Thursday to serve his full term, saying his Facebook post suggesting he was considering a run for governor of Virginia was intended as a joke.
Chatterjee, a former aide to Senate Majority Leader Mitch McConnell (R-Ky.), who has long been rumored to have political ambitions, created a Facebook group titled “Hypothetical: Draft Neil Chatterjee for Virginia Governor 2021” on May 16. (See Chatterjee Exploring Va. Gubernatorial Race.)
“Let me just be totally, totally clear on this, and I can’t stress this enough. What I did was write a light-hearted post to social media. It was clearly a joke and not serious,” he said in response to a question at his press conference after FERC’s monthly open meeting. “I cannot stress enough [that] my focus is on the work of the commission. I’m not focused on anything about my future until after the completion of my term at the commission, June 30, 2021. Period. Point blank.”
The filing deadline for the Virginia primary is April 25, 2021, more than two months before Chatterjee’s term expires. Under the Hatch Act, Chatterjee would be required to relinquish his FERC position before seeking office in a partisan election or soliciting political contributions. Gubernatorial candidates must obtain 10,000 signatures to get on the ballot in Virginia.
Chatterjee said it was clear fellow commissioner Richard Glick wasn’t taking his potential candidacy seriously. After making opening remarks at Thursday’s meeting, Chatterjee invited comments from Glick, who said jokingly, “Thank you governor. I mean Mr. Chairman.”
Nevertheless, Chatterjee’s Facebook group had attracted more than 300 members as of Thursday, and none of those who pledged their support and campaign contributions seemed to be aware it was meant as a lark.
“I was joking around with my friends on my personal social media to try to get a reaction from my [them],” Chatterjee said when asked whether he was concerned that his posting could cause confusion. “It was not something that was in any way meant for the broader public. Maybe I should have spent more time building pillow forts. There [are] only so many pillow forts you can build. I was goofing around.”
Under questioning, the chairman declined to say unequivocally that he would not be running for governor next year, repeating, “I will serve my term until June 30, 2021.”
FERC on Tuesday partly rejected CAISO Tariff revisions seeking deliverability enhancements for interconnection customers, saying a proposal to limit self-scheduling by some generators wasn’t reasonable. (ER20-732.)
The revisions sought by CAISO in a January filing were a response to the increasing impact of net peak demand shifting to later in the day, after solar goes offline, and a desire to avoid curtailing wind and solar resources due to transmission congestion during off-peak hours.
In particular, the ISO wanted off-peak generators to qualify for the same kinds of system enhancements traditionally given to on-peak generators to ensure resource adequacy under the RA program administered by the California Public Utilities Commission (CPUC).
As FERC noted, the CPUC’s program “determines how much resource adequacy capacity a given generator can reliably provide and assigns each generator technology a monthly ‘qualifying capacity’ based on the generation technology and expected load conditions, but without considering potential transmission constraints.” That means a conventional generator would have a qualifying capacity equal to its total capacity for all months of the year, but a solar resource’s qualifying capacity would depend on the time of year.
To account for system constraints, CAISO calculates each generator’s “net” qualifying capacity, which adjusts the CPUC’s qualifying capacity to account for the expected load and energy flows on the transmission lines a generator uses to deliver its output to consumers.
The CPUC revised its method for calculating qualifying capacity in 2018, significantly reducing the RA values for solar resources. The change also complicated the CAISO’s ability to finance the costs of transmission upgrades needed to maintain system deliverability during peak conditions at a time when solar represents about 60% of the ISO interconnection queue.
The ISO requires generators submitting interconnection requests to elect one of three statuses to indicate what portion of a resource’s output is deliverable under peak system conditions: full capacity, partial capacity or energy only. Energy-only resources are only deliverable subject to grid conditions and are not eligible to be counted as RA capacity.
Currently, CAISO conducts on-peak and off-peak deliverability assessments for generators seeking to connect to the ISO’s system, FERC explained. The on-peak assessment determines what network upgrades are needed to deliver the resource’s full output.
“However, the off-peak assessment is currently for informational purposes only because, according to CAISO, deliverability concerns principally relate to resource adequacy, and therefore peak demand,” FERC said. “Generators’ ability to deliver energy off-peak has not historically been a concern warranting developers’ financing network upgrades to relieve constraints.”
But that’s changing in CAISO as solar delivers increasing amounts of energy during off-peak hours midday. The ISO asked to create an off-peak deliverability status to identify and finance needed network upgrades and to grandfather in all generators that sought off-peak status. Those that didn’t seek that status would not be allowed to self-schedule in CAISO.
FERC accepted the ISO’s off-peak upgrades proposal.
“We find that CAISO’s proposal to identify off-peak network upgrades in the interconnection process to relieve local transmission constraints and allow generators to finance them, rather than potentially waiting years for solutions to develop in the transmission planning process, is reasonable,” FERC said. “We note that on-peak delivery network upgrades where generators choose to finance such upgrades to obtain deliverability status to provide resource adequacy are also undertaken through the interconnection process, not the transmission planning process.
“Thus, we find that it is just and reasonable to include in transmission rates the costs of off-peak upgrades to address local constraints, consistent with the inclusion of costs for on-peak upgrades that address local constraints.”
But FERC rejected the limitations on self-scheduling for generators that don’t opt in to seeking off-peak deliverability status.
“We find that CAISO has not adequately supported its proposal to give a self-scheduling benefit to interconnection customers with off-peak deliverability status, while restricting self-scheduling for other resources solely for the sake of preventing free-ridership,” FERC said. “CAISO has not justified why some interconnection customers should receive the proposed self-scheduling benefit in the energy market for upfront funding of transmission upgrades whose costs are eventually rolled into transmission rates and borne by all transmission customers, while other interconnection customers do not.”
NYISO is seeing “historically low” load and prices, Senior Vice President of Market Structures Rana Mukerji told the Business Issues Committee on Wednesday.
Day-ahead and real-time load-weighted locational-based marginal prices were $15.77/MWh in April, a drop from $17.11/MWh in March and $28.01/MWh a year earlier.
Year-to-date costs through April were $22.38/MWh, a 44% decrease from the same period in 2019.
Average daily sendout was 344 GWh/day in April, a drop from 375 GWh/day in March and 371 GWh/day in April 2019, Mukerji said.
The BIC voted to recommend that the Management Committee approve changes to section 4.4.3.1.1 of the Services Tariff to only award energy storage resources (ESRs) energy schedules that are sustainable for at least 60 minutes during a reserve pick-up (RPU) event.
The change was prompted by concern that during an RPU, real-time dispatch may award a larger energy schedule than an ESR can sustain for 60 minutes, as required by the Northeast Power Coordinating Council.
This can occur because the real-time dispatch/corrective action mode used to perform an RPU must issue updated schedules very quickly and thus only looks out 10 minutes.
“This … could result in an ESR running out of energy and not being able to continue following basepoints during the critical 60-minute recovery period after loss of a resource or transmission element,” said Aaron Markham, director of grid operations.
The ISO is proposing additional Tariff authority and updated RPU software to limit awards that are sustainable for 60 minutes (or more).
Peak Load Forecasts and Minimum Unforced Capacity Requirements for LSEs
The BIC voted to recommend that the Management Committee approve revisions to the NYISO Market Administration and Control Area Services Tariff sections 2, 5.10 and 5.11 to address a concern regarding the peak load forecast and minimum unforced capacity requirements for load-serving entities.
The forecast is determined using the prior calendar year’s highest hourly actual load in the New York Control Area (NYCA), adjusted to “design conditions,” which are expected to occur on a non-holiday weekday in July and August. About 80% of the highest coincident NYCA peak load hours have occurred in July and August.
The minimum capacity requirement is allocated among individual LSEs, determined by their consumption during the highest hourly actual load in the NYCA, regardless of whether that is consistent with consumption at “design conditions.”
The ISO said it was concerned about situations in which the highest hourly actual load occurs outside the “design conditions” as in 2019, when the highest actual load occurred on a Saturday in July.
The proposed Tariff revision would require the use of the highest NYCA load hour occurring on a non-holiday weekday during July and August when calculating the NYCA peak load forecast. The change will ensure that each LSE’s share of the minimum capacity requirement is consistent with the “design conditions” used to calculate the minimum capacity requirement.
If the highest load hour occurs on a weekend or holiday, load would be adjusted to account for expected additional load that would have occurred if the highest load hour had been a non-holiday weekday. Similarly, load also would be adjusted when the highest load hour occurs outside July and August.
If the temperature is higher than the design temperature, load will be removed to reflect the expected lower load that would have occurred if the highest load hour had taken place at the “design” temperature. The ISO said the change should ensure the incentive to reduce peak demand aligns with when the peak demand is expected to occur.
The changes will be presented to the Management Committee for approval on June 16, with board approval and a FERC filing expected in July. If it wins FERC approval, the changes would be effective for 2021/22 capability year.
Manual, Bylaw Changes
Members also approved changes to the following:
Accounting & Billing Manual — Changes apply to ESRs, including provisions on settlements, day-ahead bid production cost guarantee and margin assurance payments. The changes will be effective at the same time as related ESR Tariff revisions.
Revenue Metering Requirements Manual (RM2) — Changes apply to responsibility for meter inventory-related information; creation of metering configuration sub-sections for behind-the-meter net generation resources and ESRs; and allowable duration for the use of telemetry meter data as a back-up source for revenue meter data.
Public Policy Transmission Planning Process Manual — Updated to reflect Tariff revisions to clarify, streamline and improve the Public Policy Process approved in 2019 (ER19-528). (See NYISO Public Policy Tx Revisions Approved.) Other revisions address cost-containment provisions approved in February 2020 for competitive transmission projects (ER20-617).
BIC Bylaws — Changes to attendance rules, including a revision to allow nonmembers to attend by teleconference.
Installed Capacity Manual — Changes to reflect FERC order Dec. 20, 2019, accepting most of the ISO’s proposed Tariff revisions for compliance with Order 841 to accommodate and establish rules for participation of ESRs in ISO markets (ER19-467). (See FERC Partially Accepts NYISO Storage Compliance.)
Black reviewed changes to the gross load forecast reconstitution methodology, which is used to prevent the double-counting of PDRs in the RTO’s Forward Capacity Auction.
PDRs receive compensation as a supply-side resource and reduce demand, thus their demand-reducing impact becomes embedded in historical load data. To ensure that PDRs are not double-counted, the RTO must add — or reconstitute — PDR demand reductions into historical loads used in the development of a forecast of future loads.
Composition of new passive demand resources | ISO-NE
EE measures comprise the majority of PDR energy, Black said. However, some EE measures expire, which also requires reconstitution of the load forecast data.
“When we say expiring measures, we’re referring to EE measures that have reached the end of their useful measured life and can no longer participate in FCM as supply,” Black said. “Some of the lingo in the industry is that there will be no backsliding.”
[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved their remarks afterward to clarify their presentations.]
ISO-NE will present the load forecasting methodology changes to the RC for an advisory vote in June. Upon approval by NEPOOL’s Participants Committee, the RTO will file the Tariff changes with FERC with a requested effective date of Aug. 30.
The change in load forecasting methodology is the first of three related initiatives the RTO introduced to relevant NEPOOL technical committees so far this year. The second initiative considers the impact of behind-the-meter solar PV on future planning assessments. The third is intended to better integrate the FERC Order 1000 solicitation process into the reliability delist bid review, starting with FCA 15.
Changes to PP10 for Tx Solution
The RC approved changes to Planning Procedure 10 (PP10) to provide implementation details for the alignment of reliability reviews of delist bids with the competitive transmission solution process. It recommended that the PC support the revisions at its next meeting June 4.
ISO-NE Director of Transmission Services and Resource Qualification Al McBride presented the proposed changes to “better describe how responses in the competitive solicitation process that meet certain conditions may be accounted for in the review of rejected delist bids under Section 7.5 of PP10.”
The RTO presented and discussed the proposal at the April 22 RC meeting.
If approved, the changes would not affect the outcomes of the selection processes stemming from Order 1000, nor would they have any effect on how new resources participate in the FCM, McBride said. They are intended to prevent unnecessarily retaining a resource for reliability if transmission responses in the competitive solicitation process address the reliability need.
Metering for DC-coupled Assets
ISO-NE Manager of Demand Resource Administration Doug Smith presented changes to Operating Procedure 18 (OP-18) that would enable DC-coupled facilities to participate in the markets as separate assets. The proposed redline changes attempt to leverage existing processes while ensuring that metering and telemetry for DC-coupled facilities meet the same standards that apply to other generating facilities.
DC-coupled facility registered as two assets | ISO-NE
The RTO proposes the changes become effective in the third quarter because some DC-coupled facilities are likely to be commercial by then. Several market participants are installing electric storage and intermittent generation behind the same point of interconnection. Some of those “co-located” facilities are DC coupled, meaning that both the storage and intermittent components share one or more inverters, thus the need to address the metering of such assets.
ISO-NE will bring the matter back for an advisory vote in June.
Committee Actions
The RC’s notice of actions included approval of several motions, noting that all sectors had a quorum.
The committee approved a cluster of projects in Western Massachusetts for National Grid (NEP-20-G03), including 96 state-jurisdictional projects and 19 associated transmission power purchase agreements.
High-definition cameras on drones allow Eversource Energy line inspectors to see possible damage from all angles and take better photos. | Eversource
National Grid also won approval for a cluster study in Rhode Island (NEP-20-G04), composed of 39 state-jurisdictional projects and two associated transmission PPAs.
The RC approved a pool transmission facility (PTF) cost allocation of $375 million to Eversource Energy for transmission upgrade costs on 27 separate projects in Connecticut, Massachusetts and New Hampshire.
Eversource also had $7.5 million in PTF cost allocations approved for work associated with the replacement of 25 wooden structures on the 345-kV 371 line and $11.8 million in PTF cost allocation approved for work associated with the replacement of 55 wooden structures on the 345-kV 321 line.
The RC also approved a revision to Operating Procedure 12 (OP-12) related to voltage and reactive control, recommending that the PC support the revisions at its June 4 meeting.
ERCOT’s new long-term load forecast for COVID-19 scenarios based on data provided by Moody’s Analytics indicates the Texas grid operator will continue to see a loss of demand into 2024.
Requested by stakeholders, the forecast relies on demand and energy data from adjusted peak load forecasts — based on historical weather years — that correlates with Moody’s economic forecast. Stakeholders can use the information to perform their own analyses, the grid operator said.
ERCOT’s long-term forecast (blue and orange lines) compared to those based on Moody’s COVID-19 economic projections (yellow and gray lines) | ERCOT
The scenarios used the updated Moody’s base COVID-19 scenario (P90 forecast), which projects a 2024 peak demand of 84.3 GW. ERCOT’s 2020 long-term forecast foresees an 87.1-GW peak demand.
The scenarios include:
a 90th percentile summer noncoincident peak by weather zone;
ERCOT’s various peak demand scenarios;
noncoincident peak forecast by weather zone;
ERCOT monthly peak demand and energy forecasts; and
coincident peak forecast by weather zone.
ERCOT is still publishing its weekly analysis of COVID-19’s effect on load. Its latest report indicates the grid operator was still seeing a 3-4% load reduction through May 10.
Plants Enter, Exit Mothballs
ERCOT will be losing 105 MW of year-round capacity after this summer, but it could also be adding 420 MW of capacity in 2021.
Austin Energy on Tuesday told ERCOT it plans to mothball its 105-MW, wood-fired Nacogdoches Power facility in East Texas, returning it for seasonal operations from May 15 to Oct. 15. The facility is the largest biomass plant in the U.S.
However, the grid operator has included the 420-MW coal-fired Gibbons Creek Generating Station, which was shut down last June, in its long-term assessment for 2021. The plant is expected to resume operations before next summer. (See Texas PUC Responds to Shrinking Reserve Margin.)
TMPA’s Gibbons Creek coal plant could soon be roaring back to life. | Texas Municipal Power Agency
ERCOT said Gibbons Creek has met all criteria for inclusion in its capacity, demand and reserves (CDR) report, including an interconnection agreement signed by its current owner, Texas Municipal Power Authority. The agency operates the plant on behalf of the cities of Bryan, Denton, Garland and Greenville.
TMPA is in negotiations to sell the plant. In its report, ERCOT lists the “interconnecting entity” as TEERP Power Station.
Austin Energy acquired Nacogdoches Power from Southern Power last year. It has a 20-year power purchase agreement for the plant’s energy that expires in 2032.
About 10,000 central Michigan residents have been forced to evacuate their homes after a small hydroelectric dam beset by safety violations failed under heavy rainfall this week.
An earthen embankment at the 4.8-MW Edenville Dam in Midland County collapsed Tuesday, followed hours later by an overrun of the nearby Sanford Dam, flooding the surrounding area in up to 9 feet of water and prompting an emergency declaration by Gov. Gretchen Whitmer.
“If you have not evacuated the area, do so now and get somewhere safe,” Whitmer said Tuesday. “This is unlike anything we’ve seen in Midland County.”
Michigan had previously rated Edenville in unsatisfactory condition, while Sandford received a fair rating. Both dams are about 95 years old and in the process of being sold.
FERC in 2018 revoked owner Boyce Hydro’s hydropower license to operate Edenville, located between Wixom Lake and the Tittabawassee River, citing concerns about the dam not being able to handle floods.
Edenville Dam
Violations included failing to increase spillway capacity to address the increased likelihood of more frequent flooding; performing unauthorized dam repairs and excavation; neglecting to file a public safety plan or follow its own water monitoring plan; failing to acquire all property rights; and failing to construct required recreation facilities near the dam. The commission has spent about 15 years trying to get Boyce, which has owned the dam since 2004, to increase spillway capacity, the most serious of the safety violations.
The Office of Energy Projects’ Division of Dam Safety and Inspections “has determined that the failure of the project dam could result in the loss of human life and the destruction of property and infrastructure,” FERC warned in 2018.
FERC also said Boyce’s unexecuted plan to repair the spillways and use the temporary installation of a cofferdam for four to six months would “reduce the spillway capacity by approximately 50%, increasing the potential for overtopping of the dam.”
MISO will not open its doors to stakeholders or other visitors for at least the rest of the year as the coronavirus pandemic runs its course, the RTO said Tuesday.
All remaining stakeholder meetings in 2020 will be held via teleconference, MISO Vice President of Strategy and Business Development Wayne Schug said during an Informational Forum.
The decision represents yet another — and more drastic — extension of MISO’s COVID-19 response measures of holding virtual stakeholder meetings and restricting access to control rooms, policies the RTO last month had extended to June 1. (See MISO Extends COVID-19 Measures.)
MISO is also contemplating what timeline and safety precautions to follow before allowing select employees to physically return to its three office locations.
“We’re developing contingency plans,” CEO John Bear said, adding that MISO is seeking stakeholder input on a staged reopening in 2021.
“We’re looking to allow more staff to return to the office at least on a periodic basis. We’re trying to balance work from home with our business interests and with our staff’s personal needs,” Schug said, noting that MISO expects some employees will have difficulty lining up childcare or have family members that are more susceptible to the disease.
Schug said MISO continues to work with epidemiologists to bring some employees back in a “safe and predictable manner.” He also said it may consider holding some off-site in-person meetings later this year.
“Having said that, we understand the pandemic is a very dynamic situation,” Shug said, adding that MISO would adjust dates and virtual meeting setups as necessary.
Schug said MISO will ask stakeholders during a June 17 Advisory Committee meeting for advice based on how their companies are navigating staged reopenings and deciding when to welcome visitors back into their offices. The AC meeting is part of the Board Week that was originally slated to take place June 16-18 in Milwaukee. Those meetings will now be spread out in virtual format over June 10-18 to keep the meeting schedule more manageable.
“Based on what we’re hearing from you — and the world around us — our September meeting will likely be virtual, with a hope we can meet up in Orlando in December,” Bear said.
MISO’s quarterly Board Week in September was scheduled to be held in St. Paul, Minn.
MISO Executive Director Real-Time Operations Rob Benbow said no essential MISO control room personnel have tested positive for the virus to date.
“The control room staff have been doing a good job of isolating themselves … and maintaining that physical distance at work and at home,” Benbow said.
Kevin Murray of the Coalition of MISO Transmission Customers asked how often the RTO orders virus testing and whether it has had difficulties securing tests for its employees.
Benbow said essential employees so far are only tested off-site if they experience symptoms. Operators are responsible for reporting any symptoms and isolating at home until they’ve been tested.
“We require them to have two negative tests before they return to work, so we’ve had about four to five operators go through this process,” Benbow said.
In the meantime, Bear said MISO’s virtual stakeholder meetings have been going smoothly.
“I think we’re going to have some wonderful productivity and efficiencies out of this that can help reduce our costs,” Bear said.
Schug said energy and demand in the footprint is currently trending down about 11% compared to usual spring consumption.
“We anticipate that as stay-at-home orders are lifted and things return to more normal patterns, those numbers will trend back up, but it’s too hard to tell because those orders have just started to be lifted,” Schug said.
MISO has reported that load has been about 10% below average because of the pandemic for about a month. Executives said that as some business reopen, they expect surges in load.
By April 6, 11 of the 15 MISO states were under a stay-at-home order. By the end of the month, three states ended their orders, with the remaining set to expire before the end of this month.
Benbow said MISO has been calculating what load would look like without the pandemic’s effects to prepare itself for a return to more normal load.
However, April’s below-normal temperatures and shelter-in-place directives cut peak load by 10 GW — to 73 GW —compared with the same period last year.
Real-time prices fell more sharply, with LMPs averaging $18/MWh compared with $26/MWh last April.
Benbow said natural gas prices in particular have been battered by the pandemic, with Chicago Citygate trading at an average $1.68/MMBtu, down from $2.46/MMBtu a year ago, and Henry Hub at $1.69/MMBtu, down from $2.59/MMBtu.
In the midst of the widespread quarantine measures, MISO set a new all-time wind generation peak of 18 GW on April 9.
Queue Waiver Request Before FERC
MISO has also requested a 60-day extension of its June 25 deadline for developers to demonstrate exclusive land use for projects entering MISO South’s 2020 interconnection cycle. (See MISO to File 1st COVID-19 Queue Waiver Request.) The RTO asked for FERC to issue an order on the waiver by Friday (ER20-1794).
Chris Supino, with MISO’s legal department, said the waiver request doesn’t foreclose individual waivers for interconnection customers.
“Obviously a customer is free to go to FERC and request any waiver they want,” Supino said during a May 12 conference of the Interconnection Process Working Group. He urged customers to notify MISO of their situations to allow it to file supporting comments with FERC, should it deem a waiver necessary.
Supino said MISO will re-evaluate the need for further queue waivers if COVID-19 restrictions pick back up or continue for another month.
“It’s easy to go overboard at first, and we’re trying to take an incremental approach,” Supino said.
