MISO is putting the final touches on its most expensive annual transmission investment package yet after a final round of subregional planning meetings last week.
The RTO’s 2020 Transmission Expansion Plan (MTEP 20) now contains 519 new projects costing slightly more than $4 billion. Last year’s 480-project portfolio was just shy of $4 billion.
The Planning Advisory Committee will vote on the package during its Sept. 23 meeting. If approved, the Board of Directors’ System Planning Committee will then vote on it during an Oct. 26 meeting, with the full board deciding on final approval during its December meeting.
MISO Executive Director of System Planning Aubrey Johnson last month said MTEP 20 investment closely resembles that of MTEP 19.
The grid operator said the majority of MTEP 20 projects are line and substation work and will go into service within four years. Assuming the portfolio’s approval, MISO members will spend $684 million in baseline reliability projects (BRPs) and another $538 million on generator interconnection projects. Ameren alone proposed 156 new projects costing $1.6 billion for reliability and interconnection reasons in Illinois and Missouri and to replace aging equipment and accommodate load growth. Ameren has embarked on a $7.6 billion, five-year grid modernization plan in Missouri.
Draft breakdown of MTEP 20 spending by region | MISO
MTEP 20 doesn’t yet contain any market efficiency projects.
Speaking during a West subregional planning teleconference Thursday, Senior Expansion Planning Engineer James Slegers said MISO tested four BRPs that were rated 230 kV and higher and cost at least $5 million. The projects — in central Illinois, southeast Michigan, eastern Missouri and eastern Louisiana — didn’t show enough economic benefits, Slegers said.
Project investment in MISO South will be less this year than in 2019. The region will pick up $530 million worth of 46 new projects. Most of the investment — $309 million — is to accommodate load growth. Last year, MISO South was on the receiving end of 71 new projects costing about $811 million.
Entergy Cancels MTEP 16 Project
Entergy Louisiana, meanwhile, will withdraw a major project near New Orleans originally approved in MTEP 16. The utility announced that the nearly $74 million, 27-mile, 230-kV Waterford-to-Churchill transmission line no longer demonstrates the benefits it once did. Over four years, the benefit-cost ratio dropped from 2.3 to about 0.2, according to the company.
The line has not entered the construction phase. It was originally estimated to be in service by early 2022.
Entergy has since built new projects in the area that have eased congestion and eroded the original project’s benefits, MISO Senior Manager of Expansion Planning Edin Habibovic said during an Aug. 25 South subregional planning meeting. He also said Entergy found cost increases after more detailed project scoping.
“We are OK with removing this project from the economic point of view, the reliability point of view [and] the impact of any other processes,” Habibovic said. “If the load didn’t materialize, then obviously there’s no need for this project.”
Competitive transmission developer LS Power on Thursday made a three-pronged attack on MISO’s cost-allocation structure with a trio of FERC filings against the rules.
Two of LS Power’s requests for rehearing pushed back against MISO’s contention that sub-230-kV projects do not demonstrate enough benefits to share costs regionally, while a third decries the RTO’s local allocation for baseline reliability projects.
LS Power said MISO’s use of an “arbitrary” 230-kV threshold for its market efficiency project (MEP) category, a class of projects that enjoy regionwide allocation, is wrong. The RTO gained FERC approval to use the 230-kV cutoff in late July; the commission’s acceptance also denied LS Power’s entreaty for a 100-kV threshold for MEPs (ER20-1723). (See MISO Cost Allocation Plan Wins OK on 3rd Round.)
The company sought rehearing on both its 100-kV petition and FERC’s cost-allocation order. It said relegating economically beneficial sub-230-kV projects to allocation only at the transmission-pricing-zone level does “real harm” and argued that projects as low as 100 kV have proven regional benefits.
“The evidence presented in the proceeding leaves no doubt that a 230-kV minimum voltage threshold for market efficiency projects will preclude from regional consideration sub-230-kV projects that have consumer and regional benefits,” LS Power said. “The commission’s acceptance of the limited expansion of the MEP category seems to conclude that lowering the voltage threshold to 230 kV would be ‘good enough’ and shirked its obligation under [Federal Power Act] Section 205 to fully evaluate whether a 230-kV minimum voltage threshold actually results in a just and reasonable rate in every case.”
| LS Power
The company said FERC dismissed its request for a 100-kV threshold “in the face of substantial evidence” that lines under 230 kV deliver economic advantages.
“[FERC’s] decision ignored evidence that MISO currently identifies the regional benefits of economic projects operating between 100 kV and 230 kV,” LS Power said.
The company also argued for a second time that MISO should devise a better allocation for its baseline reliability projects that identifies beneficiaries beyond transmission pricing zones.
Early this year, LS Power signed on to a complaint against MISO’s current location-based, cost-allocation methodology for baseline reliability projects (BRPs), saying it doesn’t comport with the commission’s principle that transmission projects’ beneficiaries should pay for them (EL20-19). FERC said the complaint failed to show that MISO’s current approach was unfair and said any spillover benefits were modest. (See FERC Upholds Cost Allocation on MISO BRPs.)
MISO allocates BRP costs only to local transmission zones where project facilities are physically located; costs are recovered by the transmission owners developing the projects.
LS Power said FERC was “presented with unrebutted evidence” that the current allocation methodology can result in unjust and unreasonable rates, and chose to ignore it.
“The commission’s complaint denial order appears to be based on the unsupported premise that the commission’s obligation to ensure just and reasonable rates is a ‘most of the time’ standard. There is no precedent to support such a laissez-faire approach to the commission’s obligations under the Federal Power Act,” LS Power wrote.
The company said FERC, in making its decision, instead “reverted to statistics that suggest that the current location-based, nonquantitative methodology gets cost allocation mostly right, most of the time, and therefore meets the commission’s statutory standard of establishing just and reasonable rates.”
LS Power said far from modest spillover benefits, BRPs passed benefits to outside zones 28 to 100% of the time. It again pressed for an allocation based on a line-outage distribution factor methodology.
FERC last week ordered a technical conference to investigate overlapping congestion charges imposed on pseudo-tie transactions between MISO and SPP.
The commission said it was displeased with MISO’s and SPP’s first round of briefs in the matter (EL17-89, EL19-60). Commission staff will set a date for the technical conference.
FERC last September said it would investigate the possibility of overlapping congestion charges between the grid operators after American Electric Power subsidiary Southwestern Electric Power Co. and the city of Prescott, Ark., complained. (See FERC Sets Briefings on MISO, SPP Congestion Fees.)
The RTOs have argued in briefs that though duplicative congestion charges are possible for their pseudo-tie transactions, mechanisms such as virtual transactions, financial transmission rights and firm-flow entitlements (FFE) counteract double charging. MISO has maintained that congestion charges on pseudo-tied generation with SPP do not require special Tariff remedies similar to those it took correcting double-charging with PJM, which it said, are less than those with SPP.
MISO and SPP seams | Organization of MISO States
MISO-SPP pseudo-tied generation has “minimal impacts” on reciprocally coordinated flowgates, and generators can also pursue FFE allocations, MISO said. The RTO also said it models pseudo-tied loads in aggregate with the load at its commercial pricing nodes, “which prevents discretely quantifying the individual impact on pricing, settlement and congestion associated with the pseudo-tied load.”
SPP also said it doesn’t think it needs changes to its Tariff or its joint operating agreement with MISO, and said such changes would disturb FERC’s longstanding position that RTOs and utilities “are not required to offer special terms and conditions to accommodate pseudo-tie requests.”
The commission wasn’t satisfied with those characterizations.
“We find that the current record, after the briefing, is still not adequate for us to either (1) confirm that the mechanisms available to market participants are sufficient to remedy any potential for overlapping congestion charges, or (2) find that MISO and/or SPP must make changes to their JOA and/or individual tariffs,” FERC wrote.
The commission said the RTOs failed to answer when and how many times pseudo-tied generation imposed duplicative congestion charges and their total cost. It ordered another round of briefs and posed additional questions, including how the RTOs handle charges under the simultaneous binding of flowgates, MISO’s aggregation methods and a more detailed description of the grid operators’ FFE process and other existing offsetting mechanisms.
FERC also asked the RTOs to explore a grandfathered treatment of pseudo-tied loads, as SWEPCO suggested.
Exelon said Thursday that it will next year close two Illinois nuclear plants that face hundreds of millions of dollars of revenue shortfalls because of declining energy prices.
In a statement, Exelon said it must close the plants because of “market rules that allow fossil fuel plants to underbid clean resources in the PJM capacity auction, even though there is broad public support for sustaining and expanding clean energy resources to address the climate crisis.”
The Byron nuclear plant is slated to close in September 2021, while the Dresden plant will shut down in November 2021, the company said.
“Today’s unfortunate announcement comes after a long fight to keep these nuclear plants online,” said Maria Korsnick, CEO of the Nuclear Energy Institute. “These closures not only will prevent Illinois from meeting its clean energy goals, but ultimately will keep our nation from reaching a carbon-free future by 2050.”
News of the closure of the plants comes less than a week after Illinois Gov. J.B. Pritzker revealed he will pursue an alternative to legislation that seeks to pull the state out of PJM’s capacity market in order to set up a fixed resource requirement (FRR).
Illinois Gov. J.B. Pritzker | Gov. J.B. Pritzker
Pritzker last week released a report outlining eight principles to guide Illinois to a clean energy economy, ranging from expanding consumer affordability protections to electrifying and decarbonizing the state’s transportation sector.
Publication of the principles comes after a tumultuous summer in which Exelon’s Commonwealth Edison agreed to pay a $200 million fine to settle allegations that it bribed Illinois House Speaker Michael Madigan to back legislation that increased the company’s earnings and bailed out its money-losing nuclear plants. (See ComEd to Pay $200 Million in Bribery Scheme and How ComEd Got its Way with Ill. Legislature.)
“With these principles as a starting point, we will ensure any legislation on energy includes robust consumer protections as we work to increase transparency and restore the public’s faith in this process,” Pritzker said. “I will be an advocate for ratepayers, so they know they will finally have a seat at the table.”
Pritzker called the principles “guideposts for crafting a legislative proposal that puts consumers and climate first.”
Of the principles, it was the FRR alternative that drew the most attention from renewable energy companies and advocates. The proposal calls for implementation of a market-based program separate from the FRR proposal set out in legislation, which the report said “does not seem to accomplish” the goals of reducing emissions. (See Illinois: End PJM Capacity Market?)
The report said the proposed FRR has been a “centerpiece” in energy discussions in the legislature, but it includes annual payments to each of Exelon’s nuclear plants at an amount “equal to three times the current taxpayer subsidy that [they] already receive without any strings attached and without Exelon showing us their math as to why this is necessary.”
“Existing legislative proposals both tacitly assume all of Exelon’s existing nuclear plants, including Quad Cities, need a large amount of money to remain open (and the same amount of money for each plant),” the report said. “Exelon has refused to show their math to explain why this is the case — they are asking us to take their word for it without providing the relevant financial statements for each plant.”
The report went on to say nuclear plants are “integral” to Illinois achieving its clean energy goals and for the economies of the communities where the plants are located. It also said “taxpayer and ratepayer financial support for these plants cannot be a blank check” and that “alleged cost reductions for consumers that might result from current FRR proposals may actually result in cost increases for consumers.”
The report also cites concerns about the FRR raised by PJM’s Independent Market Monitor, who has argued that Exelon “would be compensated at the functional equivalent of giving contracts for [zero-emission credits] to all of the Exelon nuclear plants in Illinois.”
“We cannot afford to increase costs to consumers in the wake of COVID-19,” the report said.
Solutions
The FRR construct in current legislative proposals does not provide the same benefits as a market construct, the report argues, and could bring problems with Exelon’s market power concentration while not guaranteeing the environmental generation mix the state seeks.
Instead of the FRR option, Pritzker gave his support to establishing a market-based program incorporating the social cost of carbon into generation costs.
“Implementing a carbon price makes dirty energy less competitive, reduces emissions, creates room for renewable energy development and raises revenue for the state,” the report said. “Several states participate in the Regional Greenhouse Gas Initiative or some form of cap-and-trade. Illinois can lead the Midwest by pricing the dirty energy that we plan to phase out.”
Pritzker also called for incorporating “equity provisions” into the carbon price that “accelerates closures” of coal-fired plants in communities while redirecting revenue to other clean energy pursuits. The proposal also calls for directing revenue to communities that will experience plant closures.
The COVID-19 pandemic and accompanying recession will significantly reduce electricity demand in California through 2023 and slow consumption until the end of the decade, the state’s Energy Commission predicted in a workshop Wednesday to update its long-term forecast.
“All of us know that massive changes have happened with COVID, with the economic contraction and all the trauma that our society is living through right now,” said Commissioner Andrew McAllister, who is leading the forecast update.
Statewide electricity consumption will decline by 4 to 5% in the next two years, Cary Garcia, with the CEC’s Demand Analysis Office, told the commissioners. Demand was already down 2% in 2019 — falling to about 278 TWh — compared with last year’s forecast, he said. Energy consumption will decline at least another 2% through 2023, he said.
The commission uses data on economic performance, population growth and other factors to predict electricity demand in its 10-year forecasts. The current forecast runs through 2030. It adjusts its forecasts annually, but the changes usually aren’t as significant as this year’s updates, Garcia said. “Nobody was predicting 2020 to turn out this way.”
The coronavirus pandemic will cause a significant dip in energy consumption in the next two years, the Energy Commission said. | California Energy Commission
Population growth has slowed. This year’s update projects 1.2 million fewer residents in 2030 than the 2019 forecast, he said. Household formation and income are also expected to decline, he said.
The biggest downturn will be in commercial employment and “floorspace,” a measure of retail and business activity. Projected growth in commercial floorspace dropped 60% this year compared with last year’s estimate, Garcia said. The pandemic has wreaked havoc on brick-and-mortar retailers and kept residents away from offices.
Manufacturing employment has been declining for decades in California and will continue falling through 2030, the CEC said last year. The update shows it dropping more steeply through 2023 and a larger long-term decline than previously anticipated.
“The big dip seems to be in the commercial and industrial sectors,” Garcia said. “That’s just [a] huge decline. There’s nothing to really get away from massive amounts of people not working.”
Dropping Demand
Taken together, the economic indicators suggest statewide electricity demand will be approximately 15 TWh lower in 2020/21 than the CEC predicted in its pre-pandemic forecast. Consumption will remain at lower levels for years to come, the commission estimated in its preliminary analysis.
A caveat, Garcia said, is the analysis doesn’t account for changes in demand driven by sales of electric vehicles. The commission still is working on those figures, he said.
In addition, he said, the course of the pandemic and an economic recovery remain in question. Will vaccines and therapies trigger a swift return to work, restaurants and movie theaters? Or will medical help be slow in coming and lockdowns continue indefinitely?
| California Energy Commission
To deal with those variables, the CEC forecasted low-, medium- and high-demand scenarios. The mid-case scenario shows a U-shaped dip in demand through 2023. It assumes the pandemic will ease and the economy will recover at a gradual but steady clip.
“In the COVID context … we have a recovery in the economy that is very similar to a natural disaster rather than a full recession,” Garcia said. “In comparison to the Great Recession, you have a much quicker recovery. There’s a rebound that occurs and then a slight lag and sort of a return to normal growth.”
McAllister said the forecast update is intended to consider discrete factors, including the effects of the pandemic and EV adoption. The larger question of demand and resource adequacy, given the decision by CAISO Provides More Details on Blackouts.)
“Obviously, they’re very important … but those are not conversations that are happening today,” he said on Wednesday. “Today, we’re talking about specific elements of the 2020 forecast update.”
MISO and SPP appear to have come up empty once again after a fourth interregional study failed to detect a joint transmission project that could pass the RTOs’ benefit criteria.
After wrapping a coordinated system plan (CSP) study that began in March, the seam neighbors concluded no projects would pass the requisite 1.25:1 benefit-to-cost ratio. The two used transmission owners’ planning-level cost estimates to evaluate project candidates.
This is MISO and SPP’s fourth CSP in six years, all of which have failed to spot a beneficial project. (See MISO, SPP Empty-handed After 3rd Project Study.) Their joint operating agreement requires a CSP study be conducted at least every other year; the grid operators last performed one in 2019.
Speaking during a special MISO conference call Wednesday, economic planner Gavin Christenson said the RTOs evaluated about 200 stakeholder-submitted needs that focused on 10 flowgates in Minnesota, Iowa, Nebraska, Kansas, Missouri, Oklahoma and Arkansas. He said that while MISO is still verifying some planning-level cost estimates with TOs, he doesn’t expect the decision against an interregional project to change.
SPP Director of System Planning Casey Cathey has been optimistic about finding a joint project this year. He noted staff still need to assess cost estimates for projects and that the RTOs’ seam includes a “number of transmission opportunities.”
“We will continue to look at those opportunities with the next coordinated planning study with MISO,” Cathey said.
The RTOs will present final CSP results during their Interregional Planning Stakeholder Advisory Committee (IPSAC) meeting in September, Christenson said.
MISO and SPP’s 10 flowgates studied under the 2020 coordinated system plan | MISO
A plan to use a transformer providing a parallel path for the Marshall-Granite Falls flowgate in Minnesota proved to be one of the study’s better-performing projects. However, the $13 million line could only show a 1.08 B/C, despite eliminating the flowgate’s congestion.
Another promising project would have eased congestion on the 161-kV Raun-Tekamah flowgate on the wind-rich Iowa-Nebraska border. A new $356 million, 345-kV line would have run parallel to the flowgate and eliminated nearly all its congestion, but it would have had a 0.69 B/C.
The study also included the chronically congested 161-kV Neosho-Riverton flowgate on the eastern Kansas-Nebraska border. The flowgate is a repeat visitor on the RTOs’ joint planning studies and has accrued $32.6 million in market-to-market settlements in SPP’s favor, more than four times the next nearest flowgate.
MISO said potential projects tested for the area “saw low or negative benefits to MISO despite clearing congestion.” SPP, however, appeared to benefit considerably “for almost all projects studied on this flowgate,” MISO said.
Several project candidates along the seam showed negative benefits to SPP, where MISO would shift some of its congestion to its neighbor.
Some stakeholders sounded deflated that the RTOs would spend another year without an interregional project on the horizon and asked for more details around the evaluation process.
WPPI Energy’s Steve Leovy found it odd that so many new projects showed negative benefits.
“Benefits can get a little bit hairy when you have a project between two pools. It’s not unlikely that [the modeling software] would sacrifice the benefits on one pool to optimize overall system benefits,” Christenson said.
He added that the RTOs will have more details on the study methodology during the IPSAC call. They each conduct the study using different models and adjusted production costs savings calculations.
Clean Grid Alliance’s Natalie McIntire asked if some of the more promising projects could be restudied using the RTOs’ soon-to-be-updated transmission planning futures.
“Do we need to go through the same process next year to argue for another CSP, or is it possible that MISO and SPP could have an automatic redo on some of the projects that show stronger benefits?” she said.
MISO staff said they would have to discuss and coordinate with SPP before they could commit to any restudies.
“We really like to look at the full gamut of issues. That’s pretty much the first step of the study,” MISO Economic and Policy Planning Adviser Ben Stearney said.
“It just seems like we should take another look if these issues aren’t going away,” McIntire responded.
Economy-wide carbon dioxide emissions in New England fell by 28 to 34% between March and June versus a year earlier, driven by a big cut in transportation because of stay-at-home orders issued in response to the COVID-19 pandemic.
But carbon emissions from the region’s electric generation increased 1.4% in the first half of 2020 because the retirement of Entergy’s 680-MW Pilgrim nuclear plant in Plymouth, Mass., caused an increase in natural gas generation, ISO-NE’s Patricio Silva told the ISO-NE Planning Advisory Committee on Thursday.
Moody’s Analytics expects real gross state product (RGSP) for New England to be 7% lower in 2021 than projected in its October 2019 forecast because of the COVID-19 pandemic. There is a 4% chance that the RGSP will be as much as 14.3% lower in 2021. | ISO-NE, Moody’s Analytics
The U.S. saw a 7% cut in electric generation in April versus a year earlier and a 16% reduction in emissions. The Energy Information Administration is projecting that U.S. energy-related carbon emissions for 2020 will be 11% lower than in 2019.
The pandemic caused significant reductions in electric demand during the spring, but load has rebounded with the hot, humid weather of July and August, ISO-NE’s Jon Black said.
2019 and 2020 year-to-date carbon dioxide emissions by fuel type (metric tons) | ISO-NE, using Moody’s Analytics data
Black provided the PAC a briefing on Moody’s Analytics’ updated macroeconomic forecast and performance of the peak load forecast model in preparation for the 2021 Capacity, Energy, Loads and Transmission (CELT) forecast.
Because of the pandemic, Moody’s June 2020 forecast predicts real gross state product (RGSP) for the region to be 7% lower in 2021 than projected in its October 2019 forecast used in the 2020 CELT, recovering somewhat to 1.4% lower by 2024. Black said that translated to a baseline summer demand forecast for 2021 that is about 113 MW lower in 2021 and 24 MW lower in 2024.
The baseline assumes that new COVID-19 infections peaked in April and there is no second wave that causes states to shut down again, with a 6% confirmed case fatality rate and a 10% hospitalization rate.
Moody’s said there is a 4% chance that the RGSP will be as much as 14.3% lower in 2021, rebounding to 8.5% lower by 2024. That would result in a 232-MW reduction in summer 2021, with a 147-MW reduction in 2024. It is based on a 12% confirmed case fatality rate and 17.5% hospitalization rate with a much higher than expected incidence of new infections and deaths in late 2020.
ISO-NE plans to use Moody’s October 2020 macroeconomic outlook to develop CELT 2021.
Comments due on Boston Tx Project
ISO-NE will open a 15-day comment window on its selection of the $48.6 million Eversource Energy-National Grid project to reinforce the Boston-area transmission grid in response to the retirement of Mystic Units 8 and 9.
The RTO announced the companies’ Boston Area Optimized Solution (BAOS) as the winner of its first competitive transmission procurement on July 17. (See ISO-NE Chooses Incumbent as Boston RFP Winner.)
ISO-NE’s Andrew Kniska, who briefed the PAC on the project, said the comment period will begin once the RTO posts the draft solutions study report.
The BAOS was the cheapest of 36 projects submitted in response to the RTO’s solicitation, which called for addressing an N-1 115-kV line overload and three N-1-1 345-kV line overloads. It also sought a dynamic reactive device (DRD) to aid in system restoration.
The utilities will install one 11.9-ohm, 345-kV series reactor on each of the two 345-kV Woburn-to-North Cambridge cables at the North Cambridge substation. A normally closed bypass breaker will be installed in parallel with each series reactor and opened only when there is a need to switch in one or both of the reactors.
They also will install a direct transfer trip scheme on the 394 line in response to the contingency causing the 115-kV K 163 line overload and install a +/-167-MVAR static synchronous compensator at the 345-kV Tewksbury substation.
Kniska said the RTO’s steady-state analysis found the BAOS solved the thermal needs and did not introduce any new thermal or voltage violations. The short-circuit analysis found all area circuit breaker duties were within their limits, and the DRD was found to meet the needs for reactive injections.
“The reactors have a bypass breaker to allow operators the flexibility to open and close them … as they see [is needed] for either operational flexibility or maintenance,” Kniska said.
One stakeholder asked about the rules for the operator to determine the need for deploying the breakers. “Are we in an N-1 condition and you open the breaker because you’re afraid of an N-1-1 occurring?”
“I don’t have the details on … how the operators will use them,” Kniska responded. “Obviously, from our needs assessment, this is for N-1-1. If you have the first contingency out, they will need to be in to protect the second contingency.”
Kniska said the proposed plan application study will include a transfer analysis “to determine if there’s any adverse impact on any of the operating conditions, including the interface import capability into Boston.”
Eversource and National Grid told the PAC in June they would reduce their return on equity by 25 basis points if they exceed the $48.6 million cost cap by more than 5%, with additional 25-point reductions for each incremental 5% overrun.
The project is expected to be in service in October 2023.
3 Tx Projects Canceled in Revised SEMA/RI 2029 Needs Assessment
ISO-NE will cancel three transmission projects because of reduced load expectations in the revised Southeast Massachusetts/Rhode Island (SEMA/RI) 2029 Needs Assessment.
The RTO’s Kaushal Kumar said the needs assessment was revised to determine if projects that have not started construction are still needed in light of the decrease in forecasted loads and other changes in study assumptions since the SEMA/RI 2026 Solutions Study.
Of the 15 projects from the SEMA/RI 2026 Solutions Study that have not started construction, 11 were confirmed as still needed and will be retained.
Canceled are:
Project 1733: Separate the 325/344 double-circuit tower lines, from West Medway to West Walpole (Estimated project cost: $17.9 million; spending to date: $1.1 million).
Project 1719: Install a 45-MVAR capacitor bank at the Berry Street substation ($5.0 million; $1.5 million).
Project 1723: Reconductor the L14 and M13 lines from the Bell Rock substation to Bates Tap ($38.7 million; $2.6 million).
A project to replace the 345/115-kV Kent County T3 transformer (Project 1724) also was determined to no longer be needed, but “the decision was made [that] this project will move forward,” Kumar said, because of the age of the current transformer and because $3 million of the $5.9 million cost has already been spent.
The existing transformer, which was installed in 1971, is the last remaining 345-kV transformer of its kind in National Grid’s fleet and has a higher-than-normal potential for failure, Kumar said.
Kumar said short-circuit levels have increased to 40 kA on the 115-kV system at the Kent County station, largely because of two new autotransformers. Similar units have failed in recent years because of short-circuit events outside of the transformer protection scheme, he added.
National Grid had put the project on hold late last year. Its new in-service date is March 2022.
Comments on the revised study will be accepted until Sept. 11.
Eversource Outlines $38M Line Rebuild
Eversource will spend $38 million to replace conductors and wood poles on its 10.3-mile 115-kV line between Harwinton and Watertown, Conn. (Line 1191).
Constructed in 1933 as two parallel 27.6-kV lines, the span was bundled and reconfigured to a single 115-kV line in 1957.
Eversource’s Christopher Soderman said the utility will reconductor the line and replace 96 wood H-frames and one lattice tower with new single-circuit weathering steel monopole structures. Four structures will be removed to optimize the line, Soderman said.
Eversource Energy will spend $38 million to replace conductors and wood poles on its 10.3-mile, 115-kV line between Harwinton and Watertown, Conn. | Eversource Energy
Soderman said the existing 2/0 copper conductor and 3/8-inch Copperweld shield wires are obsolete and prone to failure because of thermal rating degradation and degradation from environmental factors.
He said 2/0 copper conductor is no longer used for transmission, and hardware for it is not readily available, requiring “non-traditional” repair methods.
In addition, about 30% of the existing poles show evidence of woodpecker damage, rot, decay, splits or cracked arms, he said.
The in-service date is the second quarter of 2022.
NYISO management has decided to remain in remote work mode for the rest of the year, Executive Vice President Emilie Nelson told the Management Committee on Wednesday.
Nelson thanked stakeholders for their continued engagement and said the virtual meetings seem to be productive. Given the decision to continue meeting remotely, she said it makes sense to welcome any additional input, and she encouraged people to contact Mark Seibert, manager of member relations, and his team with any suggestions for improvements.
Committee OKs Additional SENY Reserves
The MC approved NYISO’s Reserves for Resource Flexibility project to increase the portion of the total statewide reserve requirement for Southeast New York (SENY, zones G-K) during certain hours from 1,300 MW to 1,550 or 1,800 MW, depending on the hour. Stakeholders in July had delayed a vote on the proposal pending additional cost analysis.
The ISO will seek to implement the new project in 2021.
“These additional reserves will help to bring transmission assets in SENY back to normal transfer criteria after suffering a contingency,” said Ethan Avallone, the ISO’s technical specialist in energy market design. “The 2,620-MW reserve requirement will remain as is [for all of the New York Control Area], and this proposal only contemplates shifting an additional portion of these reserves into SENY.”
As part of its Grid in Transition initiative, the ISO is seeking to assess and develop a variety of energy and ancillary services market design changes in response to the ongoing transition of the resource fleet in New York. (See NYISO Moves Forward on EAS Projects.)
New Siting Law Milestones for Class Year Study
The MC also approved a new regulatory milestone in its Class Year Study for any large generator that is required or eligible and elects to undergo the new siting process for major renewable energy facilities under a new state law.
The Accelerated Renewable Energy Growth and Community Benefit Act, enacted April 3, streamlines the siting of new renewable energy generation projects through a new Office of Renewable Energy Siting, supplanting determination by the Public Service Commission under Article 10 for any “Major Renewable Energy Facility.”
Thinh Nguyen, NYISO’s senior manager for interconnection projects, said the revision fills a gap in NYISO’s existing regulatory milestone requirements by creating a specific milestone for large generators meeting the definition of “Major Renewable Energy Facility” to demonstrate that their applications are deemed complete comparable to an Article 10 application.
If approved by the Board of Directors in September, the ISO will make a filing under Federal Power Act Section 205 with FERC.
The Montana Public Service Commission “arbitrarily and unlawfully” reduced solar generators’ payments and contract lengths under the Public Utility Regulatory Policies Act, the state Supreme Court ruled this week.
Upholding a 2019 lower court order, the high court said the PSC improperly reduced solar qualifying facility standard-offer rates by excluding carbon dioxide emissions costs and other costs from NorthWestern Energy’s avoided-cost rate. It also said the regulators acted improperly in calculating solar QFs’ capacity contributions and reducing contracts to a maximum of 15 years.
The ruling Monday remanded the case back to the PSC for reconsideration of Orders 7500c and 7500d, which reduced standard-offer contract rates and maximum contract lengths for solar QFs of 3 MW or less under NorthWestern’s QF-1 tariff rate. The court acted on a challenge by Vote Solar, the Montana Environmental Information Center and Cypress Creek Renewables.
In 2017, citing remarks by Commissioner Bob Lake caught on a hot mic, the Billings Gazettereported that the rules rejected by the court this week “might have been knowingly set to discourage development.”
The ruling came days after the Solar Energy Industries Association and other intervenors asked FERC to rehear its July rulemaking giving state regulators more flexibility in how they establish avoided-cost rates and the ability to require those rates to vary over the span of a QF’s contract.
‘Gold Rush’ Feared
PURPA and the Montana PSC’s regulations require that avoided-cost rates and contract lengths be sufficient to “enhance the economic feasibility of” QFs. NorthWestern historically signed QF contracts for at least 25-year terms.
The dispute began in May 2016, when NorthWestern asked the PSC to reduce standard-offer rates for small solar and wind QFs from $66/MWh to between $34 and $44/MWh. (See Montana PSC Racks up 2nd Lawsuit over PURPA Rates.)
The utility said the reduction was needed for solar QFs because the $66 rate exceeded its avoided costs and threatened to cause a “gold rush” of developers seeking new QF-1 projects. At the time, NorthWestern had executed five power purchase agreements with small solar QFs, and had 43 active interconnection requests for 3-MW facilities under study and another 75 requests in preapplication phases.
NorthWestern Energy and Bozeman Solar Array | OnSite Energy
NorthWestern also sought to abandon use of the “proxy” method of calculating avoided-cost rates, which is based on the projected capacity and energy costs of the utility’s next planned resource additions.
The utility asked regulators to adopt the “peaker” method, separating its avoided-cost rate into separate energy and capacity elements. It also proposed that avoided-capacity costs be based on the levelized cost of internal combustion engines it planned to bring online in 2019.
In October 2016, the commission asked for comment on whether 25-year maximum-length contracts were unduly risky for ratepayers and whether a shorter length would be reasonable — issues not raised by Northwestern or any of the intervenors in the case.
In July 2017, the PSC issued Order 7500c, reducing the maximum contract length to 10 years and cutting standard-offer rates for QFs by more than half — lower even than proposed by NorthWestern.
The PSC continued to use the proxy methodology, but it declined to use as its proxy resource the internal combustion engine identified as the next resource to be added under NorthWestern’s 2015 resource procurement plan. Instead, regulators chose to use a combined cycle combustion turbine as its proxy unit.
It adopted what the court called SPP’s “novel” method for calculating QFs’ capacity contributions. Under the new methodology, NorthWestern and the PSC concluded that solar QFs contributed only 6.1% of nameplate capacity, well below the 38% capacity contribution value then used in QF-1 rates.
The PSC also declined to use a carbon emission adjustment in its avoided-cost calculations, saying “the political forces that once indicated environmental regulatory action at the federal level was likely in the reasonably foreseeable future has diminished and, accordingly, the likelihood of carbon emissions regulation has decreased” — a reference to the election of President Trump.
The commission said a 10-year contract would provide sufficient encouragement for QF development while mitigating forecast risk for customers, citing decisions by Idaho and North Carolina regulators, which reduced QF contracts to between two and 15 years.
In November 2017, however, the commission revised the contract length to 15 years in response to requests for reconsideration (Order 7500d).
Reversal
In April 2019, Montana’s 8th Judicial District Court vacated and modified Orders 7500c and 7500d. The state Supreme Court stayed the district court’s ruling pending the appeal.
In its Monday ruling, the Supreme Court concluded it was discriminatory to exclude carbon costs from solar QFs while permitting them for hydro and wind QFs, saying “mere speculation based on political forecasting hardly constitutes technical or scientific knowledge worthy of deference.”
The court also slammed the PSC’s reduced contract length, saying it “was based almost entirely on a 2014 North Carolina Utilities Commission decision. However, the PSC lacks any intimate knowledge regarding QF development policies in North Carolina or other states. Indeed, we find the PSC’s justification especially dubious given its wholesale rejection of out-of-state decisions as a consideration when setting the avoided-cost rate.”
“To be sure, 15-year contracts, standing alone, are not per se unreasonable,” the court added. “But because the PSC failed to consider shortened contract lengths in conjunction with greatly reduced standard-offer QF-1 rates, 15-year contracts cannot be considered sufficient to encourage and enhance QF development.”
Montana ranks 44th among U.S. states in installed solar generation. Solar supplies only 0.21% of its electricity. | SEIA
The court said the PSC also acted arbitrarily in its distinction between avoided capacity and energy costs. It agreed with the district court’s rejection of the 6.1% capacity factor, which concluded the commission had discounted NorthWestern’s summertime capacity needs and disregarded regional peak demand data. The court said the PSC “focused only on a handful of peak demand hours — 220 hours over a 10-year period — that reflect primarily infrequent wintertime spikes while overlooking evidence that NorthWestern lacks sufficient capacity to meet peak customer demand in both summer and winter.”
The court said the PSC also “misapplied” SPP’s methodology “by acting contrary to the plain language of the SPP criteria and did not articulate a satisfactory explanation for its actions.”
It rejected the argument of the Montana Consumer Counsel that the most critical factor of avoided-cost analysis is protecting the ratepayer.
“Were that the case, there would be no purpose to PURPA, which is to preclude discrimination in the marketplace for sources of energy that provide an alternative to fossil fuel development,” the court said.
It added that NorthWestern’s “frequently uttered trope that the requirements of PURPA and thus approval of solar sources of energy will wildly increase the rates charged to consumers finds little basis of support in this record.”
SEIA said FERC’s rulemaking violates PURPA and discourages the development of QFs by terminating their ability to select a long-term energy rate under long-term supply contracts. It also challenged the commission’s revision of the “1-mile” rule for preventing gaming.
“The commission erred in revoking a qualifying facility’s longstanding right to elect to be paid a long-term energy rate in contract for long-term energy delivery without citing to any evidence in the record that financing is generally available for projects using as available energy rates and fixed capacity rates,” SEIA said.
Hurricane Laura’s impending landfall along the Gulf Coast has MISO, Entergy, SPP and ERCOT bracing for grid impacts.
The intensifying Category 4 storm (as of press time) will unleash torrential rain, coastal flooding and fierce winds on southwest Louisiana and southeastern Texas tonight and tomorrow.
“MISO expects transmission and generation facilities along the path of the hurricane to be unavailable due to damage caused by high winds and flooding. MISO is working with its members to estimate the extent of the impacts, including loss of load, generation and transmission and communication systems,” spokesperson Allison Bermudez told RTO Insider ahead of the storm’s landfall tonight.
MISO on Tuesday declared a severe weather alert and conservative operations in effect for Wednesday and Thursday for portions of its Texas and Louisiana footprint. It asked members to suspend all transmission and generation maintenance.
The RTO also warned of fuel supply limitations, saying Laura could inflict major damage on gas refineries near the Gulf. It asked generators to report any fuel supply issues as soon as possible.
SPP likewise declared conservative operations in the Southwestern Electric Power Co. portion of its balancing authority Wednesday through Friday. With conservative operations, the grid operator can expand unit commitment times and “enforce other reliability safeguards as needed.”
| Entergy
Bermudez said that before MISO made the conservative operations declaration, it was working with members to “maximize availability of generation and transmission assets necessary to ensure grid reliability.” She said the RTO is closely monitoring load in western Louisiana and eastern Texas.
“MISO control room teams are well trained to handle extreme weather events, such as Hurricane Laura, and remain committed to reliable grid operations,” she said. “MISO is taking extensive measures to ensure grid and market operating systems are secure and protected throughout the Hurricane Laura event.”
Entergy said it was readying a nearly 7,400-strong storm crew to respond in the Texas and Louisiana portions of its territory. The utility said it enacted flood protection for its facilities and equipment that could experience high water and secured the use of high-water vehicles, drones, helicopters and air boats for restoration efforts.
The utility also warned that restoration times might be longer than normal because of COVID-19 pandemic safety precautions. It said its field restoration crews will adhere to social distancing.
Entergy said its system was largely spared by Tropical Storm Marco passing through its territory on Monday, as the storm had significantly weakened by then.
“While we were fortunate that Marco had limited impact on our systems, customers should keep their guard up as Hurricane Laura, which is predicted to be much stronger, is on the way,” said Entergy Vice President of Utility Distribution Operations Eli Viamontes. “Please remain storm-ready and take this as seriously as we are. This is expected to be a major hurricane and should be treated as such.”
ERCOT Senior Meteorologist Chris Coleman predicted “devastating” 10- to 15-foot storm surges in some coastal areas of Texas and sustained winds of at least 130 mph.
“This is a very large, powerful hurricane — by far the worst thus far in the 2020 hurricane season,” he warned.
