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.
Hitachi ABB Power Grids, a multinational supplier of technology for the energy industry, has agreed to join the Asset to Vendor (A2V) Network for Power Utilities, a cybersecurity-focused information sharing network for North America’s bulk power system.
A2V was launched earlier this year by Fortress Information Security and American Electric Power to provide utilities with a platform for sharing information on cybersecurity risks in their equipment supply chain. Initially aimed at helping entities meet the requirements of NERC’s CIP-013-1, A2V was later expanded to include provenance assessments for the foreign affiliations of suppliers in response to President Trump’s declaration of a national emergency in May aimed at enhancing the cybersecurity posture of the BPS. (See Trump Declares BPS Supply Chain Emergency.)
Most of the utilities and vendors participating in A2V have not been disclosed because of sensitivity issues. High-profile exceptions include Southern Co., the first utility to sign on, and now Hitachi ABB, the largest vendor to join the platform to date. Fortress hopes the presence of well known names such as these may serve as a vote of confidence in the platform that will attract participation by the ecosystem’s numerous smaller players.
“In order for the Asset to Vendor network to … be ideally suited as a community sharing platform for industry, we need a tremendous amount of participation from the vendor community,” Tobias Whitney, vice president of energy security solutions at Fortress, told ERO Insider. “And we’ve had that, frankly, from the beginning … but we wanted to make sure that our industry recognized that in order for the supply chain security issue to be addressed across the board, we need participating vendors like Hitachi ABB to come to the table [and] be transparent.”
United Response to Greater Threat
For Hitachi ABB, the introduction of A2V is part of a broader move toward common information-sharing practices that will be increasingly essential to the industry given not just the rise of cyber threats against critical infrastructure but also a “significant increase in the effort required by utilities” to comply with demands by the U.S. and Canadian governments for proof of cybersecurity readiness.
For example, NERC and the Department of Energy last month filed simultaneous requests for information on utilities’ exposure to foreign adversaries and their practices for mitigating supply chain vulnerabilities. (See Industry Seeks Clarity on Supply Chain Orders.)
While multinational firms like Hitachi ABB may already have processes in place for finding and sharing such information with their customers, this kind of industry-wide appetite can still create burdens for suppliers, especially smaller organizations with fewer resources. A common platform for sharing data on cybersecurity threats could provide a paradigm shift that benefits every industry player.
“We see the A2V network as a way to simplify and bring greater consistency to the reporting requirements that have arisen,” said Dave Goddard, head of digitalization at Hitachi ABB. “Through this process, Hitachi ABB … can provide answers to a large selection of questions typically asked by our utility customers … potentially serving a large pool of utilities with an accurate and consistent assessment response.”
Whitney agreed that easing utilities’ concerns about complying with the supply chain orders and Critical Infrastructure Protection standards is a primary goal of the platform. However, he cautioned that it will be difficult, if not impossible, to provide a simple blacklist of vendors to avoid, as some utilities have requested, and that entities should focus on building the groundwork for a united front against the common threat.
“I’m not sure if these foreign adversarial relationships are that clear; many large, multinational organizations can have … some ties with countries that may deal with foreign adversaries, but that doesn’t necessarily mean that those products and systems are already infiltrated,” Whitney said. “What has to happen now is that … utilities, vendors and suppliers need to raise their awareness and understanding of how these influences can impact the system.”
FERC last week partially accepted Dayton Power and Light’s transmission rate incentives request, requiring more information on its petition for an RTO participation adder for its continued membership in PJM (ER20-1068).
DP&L submitted a request for approval on Feb. 25 of incentives for investment in transmission projects it asserted are needed for reliability, including:
a 50-basis-point adder to reflect its continued PJM membership;
inclusion of 100% of construction work in progress (CWIP) for the projects;
and 100% recovery of all “prudently incurred transmission-related development and construction costs” if one or more transmission expansion plan projects are canceled or abandoned because of factors beyond the company’s control.
In its petition for the PJM participation adder, DP&L argued that the commission has a “longstanding policy” to provide a 50-basis-point adder to the base return on equity of a transmission owner’s entire rate base as a way to encourage utilities to join an RTO. The company said it has not had a rate case to seek the incentive since joining PJM in 2004.
FERC on Aug. 17 accepted the adder proposal but suspended it for a five-month period subject to the outcome of a paper hearing “exploring whether Dayton has shown that its participation in PJM or another RTO is voluntary, as required for it to be entitled to the adder, or if such participation is mandated by Ohio law.”
Dayton Power and Light building
The Public Utilities Commission of Ohio and the Ohio Consumers’ Counsel objected to the adder, arguing that, under state law, all TOs with facilities in the state are required to be members of an RTO. The OCC also contended that if DP&L were not a member of an RTO, the utility would be forbidden to own or control transmission facilities in Ohio.
Commissioner Richard Glick dissented in part to the RTO participation adder decision. He said the record made clear that Ohio law requires DP&L to be a member of an RTO. As a result, Glick said, there was nothing for the commission to incentivize by awarding an additional adder for the utility’s PJM membership.
“Where the law is as clear as it is here, I see no reason to give Dayton a second bite at the apple after it has already failed to adequately prove an essential element of its case for the requested incentive,” Glick said. “Under those circumstances, our role is to answer the legal questions presented to us, not to punt those questions to another day.”
Expansion Plans
FERC granted DP&L’s requests for the CWIP and abandoned plant incentives for Category 1 and Category 2 projects. Category 1 projects include baseline upgrades identified and selected by PJM through the Regional Transmission Expansion Plan (RTEP) process to resolve NERC reliability violations, while Category 2 projects are identified as supplemental projects operating at or above 125 kV and are required under Ohio law to be approved by the Ohio Power Siting Board.
DP&L’s abandoned plant incentive requests for two of its Category 2 projects are effective May 3, including the Buckeye Haas Delivery Point in Bethel Township and the 138-kV Gebhart Substation. Three other Category 2 project requests are effective upon approval from the state siting board: the 345-kV South Charleston Substation, the 345/69-kV Clinton transformer and the Fort recovery line, transformer and capacity bank.
But the incentives were denied for Category 3 projects, which are supplemental projects that DP&L said are “required to enhance reliable operations but, because they operate at voltage levels below 125 kV, are not subject to approval from either the PJM RTEP or the Ohio Siting Board.”
“Dayton indicates that Category 3 includes projects that primarily improve segments of its 69-kV transmission system and states that the majority of these projects will improve reliability by reducing outages and line overloading,” the commission said. “However, we note that the PJM Board [of Managers] does not approve or select supplemental projects in the RTEP. Further, Dayton provides no congestion analysis nor any third-party analyses of reliability benefits.”
DP&L said its transmission expansion plan projects are estimated to cost approximately $170 million, which is projected to increase its gross transmission plant in service by approximately 40% over the next four years and its net transmission investment by 90%. It said almost all the projects will be placed into service by the summer of 2023.
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.
NYISO energy markets performed competitively in the second quarter of 2020, with the economic shutdown caused by the COVID-19 pandemic leading to the lowest load levels and average fuel prices seen in more than a decade, according to the Market Monitoring Unit.
“Demand was extremely low, and fuel prices were extremely low,” Pallas LeeVanSchaick of MMU Potomac Economics told the ISO’s Installed Capacity/Market Issues Working Group on Tuesday in presenting its quarterly report on the markets.
“All-in prices ranged from $15 to $61/MWh, down 9 to 31% from 2019 in all regions except New York City, which saw an increase of 12% because of the higher capacity prices we saw there,” LeeVanSchaick said.
For the first time in more than a decade, capacity costs constituted the majority of the city’s all-in prices (71%), compared to the usual third or so, because of an increased locational minimum installed capacity requirement (LCR) and very low energy prices, he said.
All-in prices by region | NYISO
Energy consultancy ICF International in June 2018 highlighted the possibility of increasing capacity prices in New York City, citing NYISO’s revised assumptions and references for its buyer-side mitigation analysis that forecasted the LCR for the city at 2.5 to 4.5% above its then-current level of 80.5% in the 2020/2021, 2021/2022 and 2022/2023 capability years, saying the “higher LCRs are equivalent to approximately 320 MW of demand in 2020 and 550 MW in 2021 and 2022.”
The report said the actual LCR rose from 82.8% to 86.6% in New York City. Capacity costs fell by 5% on Long Island and 40% in the Lower Hudson Valley but rose by 64% in the city and doubled in the Rest-of-State regions, both from changes in demand and supply.
“In ROS, Kintigh retired at the end of March, and both Cayuga units retired in June, marking the end of the coal era in NYISO,” he said.
Natural gas prices continued to fall, with quarterly averages being the lowest witnessed over the last decade, regardless of season: $1.43/MMBtu at the Transco Z6 hub, down from $2.25/MMBtu in the same quarter a year ago.
Swing Low and Loose
The 5% average load reduction was a decrease against what had previously been the lowest second-quarter load in more than a decade, although peak load levels were consistent with last year because of a heat wave in June that drove energy demand higher.
The pandemic had a significant reductive impact on loads, reducing New York City’s load by 11%, based on weather-normalized values. The pandemic drove most of the load reduction from 2019, continuing the trend seen in the first quarter. (See NYISO Q1 Energy Prices Hit 11-Year Low.)
Generation patterns and capacity supply changed with the retirement of the Indian Point 2 nuclear unit, as well as the last two coal plants in the state, and some of those impacts were offset by the new entry of the Cricket Valley Energy Center, LeeVanSchaick said.
Lower load levels and gas prices led to lower transmission congestion and uplift.
Mapping Congestion
The report featured a new system congestion map, which LeeVanSchaick said offers a truer representation of congestion patterns.
“Where there’s a generator, it shows you what the pricing of that generator location is, but all of the load zones are shown according to the average price of the load zone on the other chart; but on this one, it’s on a gray background, and that’s helpful to distinguish between areas where there’s not a lot of generation versus areas where there may be a concentration,” he said.
Day-ahead congestion revenues totaled $62 million, down 46% from a year ago, primarily because of lower gas prices and load levels. Day-ahead congestion fell across the system, with most of the decrease occurring on the Central-East interface and in the West Zone.
System congestion real-time price map at generator nodes | NYISO
New York City constraints accounted for only about 5% of congestion, which fell by nearly 80% in the city from the previous year.
Unlike most other transmission corridors, congestion from the North Zone to central New York rose by more than 100% from a year ago, and 90% of this congestion occurred on the 230-kV Moses-Adirondack MA1 line when the parallel MA2 line was out of service in most of May and June.
“We also saw wind curtailments about 8% of the time because of unusually high congestion from the north,” he said.
Day-ahead Congestion Revenues
The report included a graph of day-ahead congestion revenue shortfalls, identified by transmission corridor, with the majority coming on the West Zone lines.
Day-ahead congestion revenue shortfalls by transmission facility | NYISO
To the extent that the congestion revenue shortfalls weren’t associated with Lake Erie circulation, they were generally related to outages at the Niagara plant of transformers 1, 2 and 4, as well as the Niagara-Rochester line, LeeVanSchaick said.
“Those outages will reduce how much can flow through there, so you see where that resulted in significant uplift,” he said. “We also saw in May and June very significant amounts of shortfalls coming down from northern New York, and those were associated with the outages of those Moses-Adirondack lines related to the [New York Power Authority] Smart Path Reliability Project.”
NERC CEO Jim Robb said in a media briefing Thursday that the organization has no plans to request further delays in the effective dates of seven reliability standards that were deferred earlier this year in light of the COVID-19 pandemic.
FERC Agrees to Defer Standards Implementation.) Affected measures include the following cybersecurity supply chain standards, whose implementation dates were pushed back from July 1 to Oct. 1:
PRC-027-1 (Coordination of protection systems for performance during faults)
In addition, the effective date of certain provisions of PRC-002-2 (Disturbance monitoring and reporting requirements) and PRC-025-2 (generator relay loadability), originally scheduled to take effect July 1, was moved to Jan. 1, 2021.
In discussing the decision not to seek further deferrals, Robb drew a distinction between these measures and other COVID-19 responses that NERC has sought to extend in recent months as the pandemic wears on, with no end in sight. For example, the organization announced last week it would keep its offices in Atlanta and D.C. closed through the end of 2020. (See NERC Extends Self-logging, Deferments Through Dec.)
While NERC and FERC have discussed giving registered entities more time to complete their compliance preparations in light of the evolving public health situation, the organizations ultimately decided that the standards — particularly those dealing with cybersecurity — were too critical to reliable operation of the grid to delay any further (echoing criticism voiced at the time of the original deferral).
“Given how important [the] supply chain is, it just doesn’t feel prudent to continue to push [those standards] off,” Robb said.
NERC Compiling Alert Responses
Manny Cancel, NERC | NERC
The briefing also included an update from Manny Cancel, senior vice president at NERC and CEO of the Electricity Information Sharing and Analysis Center, on the Level 2 alert issued by the ERO earlier this year requesting information on the bulk power system’s vulnerability to cyberattacks by foreign governments. (See Trump Declares BPS Supply Chain Emergency.)
With the Aug. 21 deadline for responses to the alert past, NERC is now busy compiling the results for a report to be submitted to FERC, Cancel said. Data from the alert will be used to determine “how many devices [on the grid] have been manufactured in potentially rogue nation-states that might be looking to take advantage of our infrastructure here.” While the information itself will be confidential, NERC may share “themes” of the results with the public if necessary.
China and Russia have been identified as particularly concerning “foreign adversaries” with the capability to launch cyberattacks against the grid, with Iran, Cuba, North Korea and Venezuela also referred to as noteworthy threats.
Details of NERC’s Level 2 alert were confidential, but Mark Kuras, senior lead engineer in PJM’s Reliability Compliance Unit, told the RTO’s Operating Committee that the information requested focuses on transformer control and protection systems that are 10 years old or newer. The alert applied mostly to generation and transmission owners, and on “distribution providers to some extent,” he said.
Oregon regulators are grappling with how to modernize the state’s customer-choice electricity program to accommodate a rapidly changing energy landscape that’s being reshaped by decarbonization policies across the West.
The Oregon Public Utility Commission last year opened an investigation (UM 2024) into the state’s 20-year-old long-term direct-access programs, which give large energy consumers the ability to obtain electricity service outside the regulated cost-of-service regime. The commission is now seeking how to shape the inquiry.
The state legislature authorized the PUC to implement direct access as part of a raft of provisions in SB 978, a 1998 law intended to equip the commission with authority to implement programs that could address investor-owned utility greenhouse gas emissions, encourage the development of a regional electricity market and create retail choice options for nonresidential customers.
Oregon’s two main IOUs, Portland General Electric (PGE) and PacifiCorp, function as gatekeepers for the programs, providing larger consumers with a yearly process for applying to opt out of regulated service in order to enroll in either a utility-run, market-based program, or contract with a third-party direct-access electricity service supplier (ESS). Similar to the process in other Western states, opting in to direct access carries certain “transition” costs for customers that ensure utilities reduce their exposure to stranded costs for providing regulated service, including meeting resource adequacy requirements. Those costs ultimately fall to the larger pool of cost-of-service customers.
Evolutionary Need
UM 2024 comes in response to a June 2019 petition from the Alliance of Western Energy Consumers (AWEC), whose membership represents companies with 160 facilities (that employ 170,000 workers) comprising both direct-access and cost-of-service customers, according to the organization.
Oregon PUC Commissioner Letha Tawney | Oregon PUC
In seeking the investigation, AWEC’s petition cited “significant disputes” over the programs in recent years, including those related to whether the state should further expand or restrict the programs and whether the programs have benefited or harmed cost-of-service customers. AWEC also noted that PGE’s direct-access program — what it called the only one “that has successfully contributed to the development of a competitive market in Oregon” — is nearing its 300-MW cap, making it soon unavailable for customers.
“My goal, when I think about this docket, is to sort of see how and where this customer-choice option needs to adapt to the current and likely future of the system — the policy, the regulation, the markets and technology that are all evolving alongside a customer-choice program that we set and have tinkered around the edges with but not fundamentally grappled with for two decades,” Commissioner Letha Tawney said during a Thursday workshop on the issue.
The PUC is proposing that its line of investigation address four sets of questions:
Does the direct-access law currently raise concerns about unwarranted cost-shifting “or other relevant harms to the public interest?” Would expansion of the programs in size and reach create additional “concerns related to unwarranted cost-shifting or other relevant harms to the public interest?”
Can program design mitigate unwarranted cost-shifting or other relevant harms? “What mechanisms should be used; how should such mechanisms be structured; and what are the legal or practical barriers to implementing them?”
“With such mechanisms in place, are unwarranted cost-shifting or other relevant harms to the public interest mitigated to the degree that the commission should expand access to direct-access programs?”
What evidence has been presented or could be presented in the docket (or a future one) to show that existence of cost-shifting and whether it would occur under an expansion of the program, and whether mitigation would be effective at preventing cost-shifting?
“I think our task here is in no small measure updating direct access and this particular kind of customer choice to where the world is today and the realities that are unfolding before us. … We talk a lot about existing cost-shifting, but I worry about the future,” Tawney said.
From Cost-shifting to Risk-shifting
In comments filed ahead of the workshop, PGE asked the commission to consider the future potential for future “risk-shifting” in addition to historical concerns around cost-shifting.
Nidhi Thakar, PGE | Oregon PUC
Elaborating in the workshop, PGE Director of Strategy Nidhi Thakar offered an example of risk-shifting: the fact that IOUs must serve as “de facto” energy providers of last resort in cases when an ESS fails financially, foisting its customers back on the utilities.
“We just want to call out again that we really see a distinction between the terms ‘cost-shifting’ and ‘risk-shifting,’” Thakar said during the workshop. “There are … going to be risks that are quantifiable. We really do believe that there are risks that are going to be harder to quantify, which to the extent that they can be quantified, those numbers could continually be changing.
“The markets are constantly evolving and changing at a rapid pace in the West, and I think it’s important that there is some breathing room from the regulatory standpoint to readjust what some of these pricing mechanisms may look like that may potentially come out of this discussion.”
Etta Lockey, PacifiCorp | Oregon PUC
Etta Lockey, PacifiCorp vice president of regulation, seconded PGE’s take: “We don’t want to get hung up on not being able to take action now because a particular risk can’t be fully quantifiable or there’s not full evidence of an unintended consequence that is likely to happen in the future.”
Speaking for the Northwest & Intermountain Power Producers Coalition, which represents ESSes, attorney Carl Fink rebuffed the notion that the PUC’s proceeding should examine potential future risks for the IOUs.
“I don’t really believe that’s within the scope of what we can be doing here, nor do I think it’s appropriate to really be looking at some of the opportunity costs that may or may not occur to the extent that utilities lose market share,” Fink said.
Oregon PUC Chair Megan Decker | Oregon PUC
PUC Chair Megan Decker clarified her own thoughts about how to address potential opportunity costs for IOUs that could lose market share while still needing to maintain resource adequacy in their service territories.
“When I’m talking about that opportunity cost around meeting a flexible load in the grid, I’m very open to how that load comes to the table and participates. I think there’s a need, and I have an interest in how the ESSes might participate in that flexible future,” Decker said.
Fink also advocated for further expansion of direct access.
Carl Fink, Blue Planet Energy Law | Oregon PUC
“We do want to stress that, to the extent the commission is looking back at how we should be doing direct access, we always need to start with the statute, as we say in every one of our pleadings,” Fink said. “The statute puts requirements on the commission. It doesn’t ask the commission to decide whether direct access is supposed to be OK; it says you shall ensure direct access. And it says it needs to be direct access for all customers.”
Tawney expressed concerned that, under the current structure, “a sort of wall comes down” after an electricity customer converts to direct access, cutting it off from the mechanisms in the regulated sector, “even though these customers have some of the most flexible and most interesting — and most capable — on-site resources that might help us through our transition to a clean-energy, high-renewables-based grid.”
“There is a lot to be said for policy stability, but that means we need to set out boundaries or structures that will be resilient for how this future unfolds in the next decade, and that really requires thinking about the unexpected and setting up policies and structures that will manage those changes effectively,” Tawney said.
Tyler Pepple, Davison Van Cleve | Oregon PUC
Tyler Pepple, the attorney who filed the petition on AWEC’s behalf, asked whether the PUC would proceed under the presumption that direct access is in fact in the public interest.
Oregon PUC Commissioner Mark Thompson | Oregon PUC
“Is that the intention there, that we’re sort of assuming that direct access is in the public interest because it’s required by statute, or do you think that it’s important for the parties to present evidence on the benefits of direct access and whether that would be helpful?” Pepple asked.
Commissioner Mark Thompson said he didn’t think the PUC is being asked to consider whether direct access is in the public interest because state law has already established the program.
“I guess where I think the public interest question enters into it for us is with respect to how do we implement the statute’s guidance that we’re supposed to protect against unwarranted cost-shifting; and I do think the statute clearly contemplates us having a role there to put potential limits or guidelines on how that program is implemented,” Thompson said.
