Page 1098 – RTO Insider

May 22, 2020

FERC Partly Rejects CAISO Deliverability Enhancements

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.

CAISO Deliverability Enhancements — Longhorn cattle graze below transmission lines in Northern California. | © *RTO Insider*

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.”

May 21, 2020

NYISO Business Issues Committee Briefs: May 20, 2020

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.

Daily NYISO average cost/MWh (energy & ancillary services, excluding ICAP payments) | *NYISO*

60-minute Rule

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.)

May 21, 2020

NEPOOL Reliability Committee Briefs: May 19, 2020

NEPOOL Reliability Committee Briefs: April 22, 2020.)

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.

NEPOOL — 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.

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-1 2) related to voltage and reactive control, recommending that the PC support the revisions at its June 4 meeting.

May 21, 2020

ERCOT Briefs: Week of May 18, 2020

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.

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.)

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.

May 21, 2020

Michigan Dam with Prolonged Safety Issues Fails

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.

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.

Boyce has twice sought rehearing on FERC’s decision to no avail. (See Closed Michigan Dam Loses Rehearing Bid.)

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.”

May 21, 2020

Wary of Contagion, MISO Bars Visitors for 2020

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.

May 21, 2020March 11, 2025

Emergency Measures Possible for ERCOT, FERC Warns

ERCOT may need to use Energy Emergency Alerts (EEAs) to provide “operational flexibility” and ensure it has sufficient resources to mitigate capacity shortages this summer, according to FERC’s 2020 Summer Energy Market and Reliability Assessment.

The report released Thursday found that aside from ERCOT, all NERC planning regions should have adequate generation available to exceed their reserve margins during June, July and August. FERC staff noted, however, that the projections were prepared before the COVID-19 outbreak began to impact the bulk power system and warned that system operators should prepare for deviations as the situation evolves.

ERCOT is predicting a reference reserve margin of 12.6% for the summer, according to its Summer 2020 Final Seasonal Assessment of Resource Adequacy, released May 13. (See ERCOT’s Su m mer Reserve Margin up to 12.6%.) This is higher than the initial projection of 10.7% used in NERC’s report, but still below NERC’s reference margin level of 13.75%. ERCOT said the elevated reserve margin in its latest assessment is due to a downward adjustment in peak load forecast to account for economic impacts from COVID-19.

In a pod c ast accompanying the summer assessment, members of FERC’s Office of Energy Policy and Innovation (OEPI) and Office of Electric Reliability (OER), which drafted the report, said the outlook for this summer is comparable to last year, when ERCOT reported a considerably lower reserve margin of 8.5%. (See Abundance of Summer Capacity — E xcept in Texas.) This led to what the grid operator characterized as a “difficult August,” though it was able to operate reliably throughout the summer months. (See ERCOT, SPP, CAISO Recount Summer Chal l enges.)

NERC 2020 anticipated reserve margins | NERC

“While ERCOT faced some challenges last year, it maintained system reliability with no load curtailments even as it set several new peak loads, including its current standing all-time peak load of 74,820 MW on August 12, 2019,” said Louise Nutter, with OER.

But despite the lack of load curtailments, ERCOT was forced to declare an EEA several times last summer to activate emergency procedures such as demand response measures and increased generation imports from neighboring regions. Even with these measures in place, the operator still found itself short on reserves at times, experiencing real-time locational marginal prices of up to $9,000/MWh. Based on the experience of last year, ERCOT identified a “potential increased need to call an EEA” under some scenarios this summer.

Net Growth in Generation Capacity

One area where ERCOT leads other regions is in the growth of its generation capacity. The grid operator intends to add more than 3 GW of generation this summer, almost entirely comprised of wind and solar facilities.

Industry-wide, about 5.6 GW of capacity is scheduled to come online this summer. MISO has the largest expansion planned after ERCOT, with 1.21 GW of primarily natural gas-fired generators. Next is CAISO, with 680 MW of wind and solar. ISO-NE, NYISO and SPP plan to add 60 MW, 80 MW and 10 MW, respectively.

Planned retirements total 1.3 GW, mostly by PJM, which will shut down 900 MW of coal-fired plants and approximately 200 MW of natural gas facilities while adding around 300 MW of solar capacity. The report noted that these projections could change due to the COVID-19 pandemic, with the economic slowdown affecting construction on new units as load and price reductions accelerate planned retirements across the industry.

While renewables make up most of the projected growth, natural gas will “continue to play a pivotal role” in the generation mix this summer, thanks to both the installation of new gas generators and the retirement of facilities using other fuels. The share of gas generation is highest in NYISO, where it represents 55% of total net summer capacity, but it remains the largest single source of generating capacity in every organized wholesale market.

Report Details

FERC cited data from the National Oceanic and Atmospheric Administration that “assesses a greater than 50% probability” of above-average temperatures throughout the Western U.S. and parts of the Southern and Eastern U.S. this summer, while average temperatures are predicted for the upper Midwest. NOAA also predicts that the 2020 Atlantic hurricane season will be more active than usual, with up to 16 named storms, eight hurricanes and four major storms between June 1 and Nov. 30.

Other findings from the report include the following:

Natural gas production is expected to average around 88 Bcf/d, a 3.7% decline from last summer. This will be accompanied by a 3% decrease in demand to about 78 Bcf/d. A major driver for this drop is falling consumption for electric generation, the largest sector of gas demand, which is expected to fall 1.6% this year.
U.S. natural gas exports are expected to “reach new highs” this summer, thanks in part to 5.3 Bcf/d of capacity additions at four LNG liquefaction terminals. Pipeline exports to Mexico are also expected to grow as new pipeline connections are added. LNG exports, combined with pipeline exports, are expected to average 14 Bcf/d in the summer months, up from 10.9 Bcf/d last year.
Natural gas storage levels are expected to end the injection season at 3.84 Tcf, around the five-year average. Staffers said the injection season began relatively high due to a mild winter, which helped to build back inventories from a large deficit in 2019.
Hydropower generation in California is expected to be lower than last year due to a below-average snowpack, which could lead to increased use of gas-fired plants and imports of power. Utilities in the state may also have to selectively de-energize transmission and distribution lines due to continued risk of wildfires. (See CAISO Predic t s Adequate Summer Capacity.)

NERC Summer Assessment Previewed

In a preview of NERC’s 2020 Summer Reliability Assessment, planned for release June 1, FERC revealed the organization is forecasting net demand of approximately 750 GW, about 0.9% higher than summer 2019. Growth in demand is concentrated in ERCOT and WECC, with reductions predicted for PJM and MISO. Total generating capacity is expected to grow by about 0.2% over last year.

ERCOT’s control room | ERCOT

The team preparing NERC’s report told the Reliability Assessment Subcommittee in April that it has been a challenge to address the ongoing impact of the coronavirus outbreak while still providing a balanced look at other reliability issues. (See RAS Balancing COVID-19 Impacts in Reliability R e port.) Nearly all of the report’s key findings have been affected by the pandemic in some way.

NERC released a separate r e port earlier this year to help with the issue. The Pandemic Preparedness and Operational Assessment — Spring 2020 is described as a “bridge” to the summer reliability assessment that can examine the effects of COVID-19 and provide guidance so that the main report is not overwhelmed with a single issue. (See PPE, Test i ng Top Coronavirus Concerns for NERC.)

May 20, 2020

Strah Named New President of FirstEnergy

FirstEnergy promoted its chief financial officer on Tuesday to take over as president beginning next week.

Strah FirstEnergy — Steven Strah | *FirstEnergy*

Steven E. Strah, who was named CFO and senior vice president in 2018, was elected by the FirstEnergy board of directors to serve as president effective Sunday. Strah is taking over the role as president from Charles E. Jones, who has been FirstEnergy’s president, chief executive officer and member of the board since 2015. Jones will continue to serve as CEO and a member of the board.

Strah will oversee FirstEnergy Utilities; corporate services and information technology; finance; product development, marketing and branding; external affairs; rates and regulatory affairs; and strategy. Strah, who began his career with The Illuminating Company in 1984, previously served as regional president and vice president of distribution support of Ohio Edison, and senior vice president at FirstEnergy Utilities.

“Steve is a strategic and driven leader with a deep understanding of FirstEnergy’s business and the needs of our customers, employees and investors,” Jones said in a press release. “He is committed to driving our long-term, customer-focused growth plans, as well as our mission to be a forward-thinking electric utility.”

FirstEnergy also made several other senior leadership moves on Tuesday:

K. Jon Taylor was elected senior vice president and CFO and will report to Strah, overseeing accounting, treasury and investor relations.
Robert P. Reffner was elected senior vice president and chief legal officer, reporting to Jones. He will add risk management and internal auditing to his current duties overseeing the corporate, legal, information and compliance and real estate departments.
Ebony L. Yeboah-Amankwah was elected vice president, general counsel and chief ethics officer, reporting to Reffner.
Mary M. Swann was elected corporate secretary, reporting to Yeboah-Amankwah.
John Skory was named vice president of FirstEnergy’s utility operations.
Gary W. Grant Jr. becomes president of Ohio operations, reporting to Skory.
Michelle R. Henry, director of FERC and state regulatory compliance since 2018, was named vice president of customer service.
James H. Myers III was named president of West Virginia operations. Myers is taking over for Holly C. Kauffman, who is retiring after 36 years with the company.

May 20, 2020

Chatterjee Exploring Va. Gubernatorial Race

FERC Chairman Neil Chatterjee, who has long been rumored to have political ambitions, floated a trial balloon last week on a potential run in the 2021 Virginia gubernatorial race.

Chatterjee created a Facebook group titled, “Hypothetical: Draft Neil Chatterjee for Virginia Governor 2021” on May 16. The page — which features a photo of Chatterjee in the commission meeting room, wielding a gavel and wearing a Washington Nationals baseball cap — had attracted almost 300 members as of Tuesday.

Chatterjee, a Kentucky native, joined the commission in August 2017 after serving as Senate Majority Leader Mitch McConnell’s (R-Ky.) energy adviser.

Chatterjee Virginia Gubernatorial — FERC Chair Neil Chatterjee with his former boss, Senate Majority Leader Mitch McConnell (R-Ky.) and New England Patriots coach Bill Belichick | *Neil Chatterjee*

“Does this mean you won’t be a lieutenant [governor] candidate for Kentucky in 2023?” asked one member on the Facebook page.

“Love, love, love Kentucky,” Chatterjee responded. “But [I] have been living in Virginia for almost 20 years.”

“I will not make any decisions about my future until after the completion of my term at the commission,” Chatterjee said through a FERC spokesperson in response to questions from RTO Insider. “While I appreciate the kind and encouraging responses, this was a lighthearted post to social media. All kidding aside, I take my role as chairman of the commission very seriously. I have been and will continue to be accountable to the staff, to my colleagues, to the courts and to the free press.”

The filing deadline for the primary is April 25, 2021, more than two months before Chatterjee’s FERC term expires on June 30.

But Chatterjee would need to make a decision well before April. According to the Virginia Department of Elections, gubernatorial candidates must obtain 10,000 signatures (at least 400 from each congressional district) to get on the ballot. (The filing deadline for independent candidates is June 8, 2021.)

Hatch Act

If Chatterjee decides to move forward with a campaign, he will be governed by the Hatch Act, which prohibits federal employees from seeking public office in a partisan election or soliciting or accepting political contributions.

The law is intended “to ensure that federal programs are administered in a nonpartisan fashion, to protect federal employees from political coercion in the workplace, and to ensure that federal employees are advanced based on merit and not based on political affiliation,” according to U.S. Office of Special Counsel.

The Field

Chatterjee could face a crowded field if he decides to run to replace Gov. Ralph Northam (D), who is prohibited by the state constitution from seeking re-election.

State Sen. Amanda Chase has announced her candidacy for the Republican nomination, and several other present and former elected officials, including former U.S. Rep. Barbara Comstock, have been named as potential candidates.

Former Gov. Terry McAuliffe, Attorney General Mark R. Herring and Lt. Gov. Justin Fairfax have expressed interest in seeking the Democratic nomination.

“Lighthearted” or not, Chatterjee’s flirtation means his future actions as chairman will be viewed by at least some through a partisan lens.

Some renewable energy supporters have cited Chatterjee’s support of an expanded minimum offer price rule in PJM as evidence that he is supporting President Trump’s pro-coal agenda. Chatterjee has denied the charge, saying he is merely ensuring a “level playing field” for fossil fuel resources in response to state renewable energy subsidies.

Chatterjee and fellow Republican Commissioner Bernard McNamee have regularly clashed with Democratic Commissioner Richard Glick over their refusal to consider greenhouse gas emissions in rulings on natural gas pipelines and LNG export facilities.

On May 12, Chatterjee sent a letter rejecting Herring’s call for a moratorium on new gas pipeline approvals in Virginia during the coronavirus pandemic. “The public’s need for strong energy infrastructure is not lessened by this pandemic,” Chatterjee said in the letter, which he tweeted about. “It is imperative that the commission continue to operate as close to normal as possible, so that the energy sector is well-positioned to contribute not only to Virginia’s economy but also to the nation’s economy as a whole.”

Climate activist Drew Hudson, of Friends of the Earth, tweeted that if Chatterjee runs “he’ll be a joke — but it will not be funny.” Hudson said the chairman “personally ordered pipelines to take land from Virginia landowners, denied [their] appeals for rehearing, and threatened their homes and lives in the process.”

Before his time on McConnell’s staff, Chatterjee worked in government relations for the National Rural Electric Cooperative Association, as an aide to House Republican Conference Chairwoman Deborah Pryce (Ohio) and as a staff member on the House Committee on Ways and Means.

Chatterjee served as FERC chairman from August to December 2017 when he was replaced by Kevin McIntyre. He returned to the chairmanship in October 2018 when McIntyre, fighting cancer, relinquished the post.

In October 2017, Chatterjee praised then-Energy Secretary Rick Perry’s “bold leadership” in calling for price supports for coal and nuclear plants. Chatterjee joined in a unanimous vote rejecting Perry’s Notice of Proposed Rulemaking in January 2018.

In returning to the chairmanship, Chatterjee credited McIntyre for helping him grow “from [a] formerly partisan legislative aide to independent regulator.” (See Returning Chair Pledges to Protect FERC’s Independence.) McIntyre died in January 2019.

May 20, 2020

New MOPR Analysis Sees Cost at $1B/Year

The expanded minimum offer price rule (MOPR) will cost PJM ratepayers almost $9.7 billion over the next nine years if FERC adopts revised floor prices allowing most nuclear plants to clear, according to a new analysis by critics of the commission’s directive.

Michael Goggin and Rob Gramlich of Grid Strategies generated headlines last August with a report that predicted an expanded MOPR could add $5.7 billion annually to PJM’s capacity costs. (See MOPR Impact Study Ruffles Feathers Ahead of FERC Ruling.) The estimate was cited by those calling for pulling the Commonwealth Edison zone in Northern Illinois out of the capacity market — and criticized by others, including Independent Market Monitor Joe Bowring, as wildly inflated.

Gramlich said the new analysis was prompted by FERC’s December order, which exempted more existing renewable energy than prior proposals, and PJM’s March 2020 compliance filing, which reduced MOPR floor prices for nuclear plants and renewables. (See PJM MOPR Floor Prices Reduced for Gas, Nuclear, Solar Units.)

MOPR cost — Projected Increase in capacity costs by region and delivery year  ($ millions) | *Grid Strategies*

The new analysis considers two scenarios: one in which FERC accepts PJM’s lower floor prices, and one in which the prices reflect the RTO’s original October 2018 proposal.

The authors say the new report is subject to many uncertainties, but that even under the best-case scenario, the MOPR is guaranteed to raise prices. “There are so many versions of MOPR and factors such as bid levels that vary between versions and over time that it is not possible to definitively conclude, as some have, that MOPR will have limited cost impacts,” the report says. “Under most scenarios, MOPR will result in billions or tens of billions of dollars in excess costs to electricity consumers across PJM.”

The report notes that the clearing price for the most recent Base Residual Auction in 2018 was $140/MW-day, with some zones clearing at between $165.73 and $204.29/MW-day.

PJM reduced MOPR floor levels of $175/MW-day for solar PV with tracking, which would have been low enough to clear in some areas of the RTO in 2018. But the RTO’s proposed $367/MW-day for solar PV without tracking, $1,023/MW-day for land-based wind and $3,146/MW-day for offshore wind are well above prior clearing prices.

PJM’s new proposal would allow multiunit nuclear resources to clear the market along with most or all single-unit nuclear plants. The authors assumed new renewable sources would not clear under either of the two scenarios, regardless of whether they were using the default bid levels proposed by PJM or resource-specific offer floors.

“It is likely that some solar, and potentially some land-based wind projects, could demonstrate evidence for unit-specific bid levels that are low enough to clear the capacity market,” the report acknowledged. “If resources do not clear, capacity market prices increase and redundant replacement capacity must be purchased and paid for by consumers, further increasing their bills.”

Under the first scenario, the new MOPR could increase capacity costs by nearly $10 billion total over its first nine years, an average of more than over $1 billion annually. PJM’s capacity costs last year totaled $8.7 billion.

Under the second scenario, subsidized nuclear units in Illinois, New Jersey and Ohio would fail to clear, resulting in an increase of almost $24 billion over the nine years, an average of $2.6 billion annually, the authors say.

Caveats

The authors said their estimates are likely conservative because they don’t include the impact of subjecting self-supply, state default service auctions, demand response and energy efficiency resources to the MOPR.

Another variable is how quickly PJM states meet their renewable portfolio standards. Grid Strategies estimates almost 47 GW of nameplate capacity wind, solar and storage will be needed by 2030 to meet state targets.

“The cost of MOPR would be higher if renewable deployment is front-loaded into the next few years to benefit from federal renewable tax credits that are phasing down for projects completed through the mid-2020s” as was assumed in the 2019 study, the authors said. “This would result in a larger cost being attributable to MOPR, as those resources are subject to MOPR for a longer period of time and there is a larger price impact in the near term, but likely lower total cost to consumers because the renewable projects benefits from larger tax credits.”

Another course of uncertainty is that PJM is planning to revise the method for calculating the capacity value of wind and solar projects. (See PJM MRC Moves Forward on Storage, Hybrids.)