Portland General Electric on Monday pre-emptively cut power to about 5,000 customers in high-risk fire areas near Mount Hood in the first public safety power shutoffs (PSPS) to affect Oregon residents.
The utility began cutting service on Monday evening to prevent its equipment from sparking wildfires along a heavily forested portion of U.S. Route 26, stretching from Alder Creek to the high-elevation town of Government Camp, southeast of Portland.
“The proactive safety outage is a last resort to help protect people, property and the environment in the fact of extreme fire danger conditions and high winds forecast for the area,” PGE said in a statement.
PGE said it expected the distribution outages to last from 24 to 48 hours, “subject to repair times for any damage that may occur.”
The shutoffs coincided with a small wildfire that burned about 2 acres near the Mount Hood Meadows ski area on the south side of the mountain, shutting down nearby hiking trails. The cause of that blaze, which occurred away from any power lines, was still under investigation.
On Monday, Mount Hood and its foothills were shrouded in a thick haze as high winds carried in smoke from larger fires burning to the east. With winds expected to gust as high as 65 mph, a red flag warning is in effect for the Mount Hood National Forest through Wednesday evening, indicating an increased danger of wildfire.
While PSPSes have become increasingly commonplace during California’s growing wildfire seasons, the practice is new to the Pacific Northwest.
“Even in historically wet, mild Oregon, summers are getting hotter and dryer with longer wildfire seasons, and the overall risk of wildfires is increasing,” PGE said.
The utility said it is taking other steps to prevent wildfires in its service territory, including increased vegetation management and inspection along its 12,000 miles of power lines and replacement and modification of equipment to reduce the risk of sparking fires.
PGE said it is also training crews in basic firefighting to learn “what to do if a fire ignites at their work scene” and “help prevent it from escalating to an even more dangerous situation.”
Portland-area Outages Top 100,000
Monday evening also saw more than 100,000 Portland-area customers of PGE and Pacific Power lose power as high winds with gusts as high as 55 mph snapped tree limbs and knocked down distribution lines throughout the region. An additional 15,000 PGE customers in Marion and Yamhill counties south of the metro area also lost service.
Even as PGE crews restored service to customers, the utility’s website showed outages continuing to climb throughout Monday night and into the early morning hours today.
The high winds are expected to persist throughout the region into midweek as a late-summer heat wave pushes temperatures into the mid-90s. Milder conditions are in the forecast for later in the week, according to the National Weather Service.
In the face of another heat wave and raging wildfires, CAISO avoided rolling blackouts but declared Stage 2 emergencies on Saturday and Sunday after losing transmission and generating capacity without warning.
Sunday was “undoubtedly the most stressful grid day we had this year, maybe 10 years,” Vice President of Operations Eric Schmitt said in a media briefing Monday.
At midday Sunday, the ISO said it faced a 4,000-MW “mismatch” between supply and demand and could order rolling blackouts affecting millions of residents unless massive conservation efforts and aid from neighboring utilities allowed it to avert or limit outages.
If that had happened, it would have been the second time in less than a month that CAISO resorted to rotating outages to avoid jeopardizing the Western grid. The blackouts of Aug. 14-15, which affected more than 1 million customers, were the first time the ISO used its emergency powers in nearly 20 years. (See Theories Abound over California Blackouts Cause.)
A heat wave set record or near record temperatures across the West on Sunday, including 109 degrees Fahrenheit in downtown Los Angeles and 113 F in Las Vegas. Wildfires raging in Central and Southern California took transmission lines out of service, stranded hydroelectric and solar resources and fouled the air in major cities.
On Saturday evening, the ISO suddenly went from an energy warning to a Stage 2 emergency when fires near Fresno and in Southern California interrupted power flowing from a hydroelectric plant in the Sierra Nevada foothills and solar arrays in the Imperial Valley, said John Phipps, director of real-time market operations.
The fires cut off 1,600 MW, forcing CAISO to an emergency status that allowed it to borrow 300 to 400 MW each from the Los Angeles Department of Water and Power (LADWP) and the Sacramento Municipal Utility District (SMUD). Blackouts were narrowly averted.
Triple-digit heat across much of the West is straining CAISO’s system.
About 600 MW of the lost power returned Sunday, Phipps said, but in the middle of the briefing, he said he had just learned another 500 to 600 MW had been lost because of fire at a plant.
Sunday’s peak demand was projected to exceed 49 GW, by far the highest load of the year, but it ended up being slightly more than 47 GW, still a record high for 2020, Schmitt said. Neighboring states struggling with the heat didn’t have much electricity to spare, he said.
On Sunday, Schmitt warned that when California’s solar power waned in the evening while demand remained high, severe shortfalls would occur. “We still haven’t been able to find enough energy to make up that shortage,” he said.
During the mid-August heat wave, Nevada’s NV Energy strained to serve load, especially in the Las Vegas area, and issued emergency alerts.
On Friday, FERC granted PacifiCorp temporary authority to make short-term sales of electricity to NV Energy during emergency conditions at CAISO’s 15-minute market LMP at the Palo Verde price node (ER20-2816). The sales would otherwise be prohibited by PacifiCorp’s tariff.
“Due to credible information about possible reliability problems, we find that the exercise of our discretion to grant this waiver in part is warranted,” FERC said.
Events of Sept. 6
CAISO predicted problems to start around 5 p.m. Sunday and grow worse until as late as 10 p.m. There was a 4,000-MW difference between forecasted supply and demand at 1 p.m.
Unless circumstances changed, CAISO said it would likely declare a Stage 2 emergency between 4 and 5 p.m. and move to a Stage 3 emergency, commencing blackouts, around 5 p.m., Schmitt said. Outages could have affected 2.5 million to 3 million customers, or about 7.5 million to 9 million residents based on average household size.
The Stage 2 emergency was declared later than expected at 6 p.m., when a high-voltage DC line linking California to Oregon was suddenly derated by 1,100 MW and adjacent AC lines became overloaded, causing CAISO to lose 1,600 MW in minutes, Phipps said.
Then a 260-MW generating resource tripped offline. Having lost 1,900 MW, CAISO was “close to the edge,” Phipps said.
It called on large-scale consumers to honor their demand-response contracts and limit consumption, taking 960 MW of load off the system, he said. LADWP and SMUD again supplied additional power, while residents did their part to conserve, he said.
CAISO did not have to progress to a Stage 3 emergency.
The weather forecast called for a cooling trend starting Monday but also high winds that Pacific Gas and Electric and other investor-owned utilities warned could lead to public safety power shutoffs (PSPS) to prevent wildfires. CAISO said it did not expect the PSPS events to impact its system.
FERC on Friday rejected NYISO’s proposal to make it easier for public policy resources to clear its capacity market, prompting a fiery dissent from Democrat Richard Glick, who warned the ruling “will ultimately doom NYISO’s current capacity market construct by forcing New York to choose between the commission’s constant meddling and the state’s commitment to addressing the existential threat posed by climate change.”
Chairman Neil Chatterjee and fellow Republicans James Danly and Bernard McNamee — in one of his final rulings before leaving the commission — joined in rejecting the proposal, which would allow public policy resources in New York City and capacity zones G-J to avoid buyer-side mitigation if enough existing capacity exits the market, or if demand increases enough to boost capacity requirements (ER20-1718-001).
The proposal was recommended by NYISO’s Independent Market Monitor and supported by majorities of all of the ISO’s stakeholder sectors. (See Five New Recommendations from NYISO Monitor.)
‘Similarly Situated’
But the commission majority said NYISO’s plan was “unduly discriminatory because it does not provide sufficient justification for prioritizing the evaluation of public policy resources before nonpublic policy resources, independent of cost.”
The ISO contended public policy resources — renewables, battery storage and other zero-emission resources — are not “similarly situated” to nonpublic policy resources because the latter are unlikely to be completed under New York’s aggressive emission-reduction goals.
But the commission said they should be treated the same because “they must adhere to similar requirements for interconnection and for participation in the” ISO’s Installed Capacity (ICAP) Market.
“Further, our finding that NYISO’s proposal is unduly discriminatory is dispositive,” the commission added. “We need not reach NYISO’s arguments that its proposal would not cause price suppression.”
James Denn, spokesman for the New York Public Service Commission, said the state will seek to overturn the ruling.
“Long standing FERC policy and precedent respected state’s rights. But this constitutionally protected idea apparently means nothing to this administration. If allowed to stand, this decision would cause tremendous economic and environmental harm across the country by intentionally increasing energy prices for consumers to line the pockets of fossil fuel interests, and undermining successful renewable energy policies that have created hundreds of thousands of jobs.”
“We worked closely with market participants on a design we felt addressed FERC’s jurisdictional obligations and New York’s right to implement renewable energy policies,” said NYISO CEO Rich Dewey. “We’re reviewing the order to assess next steps and remain confident we can find a regulatory solution acceptable to all parties that supports the changing grid.”
The ISO’s buyer-side market power mitigation rules require new ICAP resources in New York City and zones G-J to offer at or above the default offer floor — 75% of the net cost of new entry (CONE) of the hypothetical unit modeled in the most recent ICAP demand curve reset — until they clear 12 monthly auctions.
To win an exemption from mitigation, a new entrant must pass one of two exemption tests. Part A allows exemptions if the forecast of capacity prices in the first year of a new entrant’s operation is higher than the default offer floor. Part B permits exemptions if the forecast of capacity prices in the first three years of a new entrant’s operation is higher than the net CONE of the new entrant.
4 Changes
NYISO proposed four changes to its rules, saying they would “better reflect changes in resource investment and retirement decisions and, ultimately, the composition of the overall resource mix that are expected to take place in New York state.”
The changes would:
modify the ISO’s current practice of performing the Part B test before the Part A test by swapping their order;
establish two separate mitigation study periods (Group 1 and Group 2), each covering three consecutive years;
evaluate resources under the Part A test for each capability year of a resource’s three-year mitigation study period; and
put public policy resources ahead of nonpublic policy resources in Part A evaluations.
The commission said the proposal “would unjustifiably limit nonpublic policy [resources’] ability to pass the Part A test and participate on an equal footing with public policy resources.”
The ISO contended public policy resources are more likely to secure the necessary permits and siting permissions, secure firm off-takers and receive favorable financing, and that nonpublic policy resources are unlikely to enter the market in the future.
It cited the Climate Leadership and Community Protection Act, which calls for 70% of New York’s electricity to come from renewable resources by 2030 and for electricity generation to be 100% carbon-free by 2040. It also nearly quadrupled New York’s offshore wind energy target to 9 GW by 2035.
It also cited the Accelerated Renewable Energy Growth and Community Benefit Act, which established an office to accelerate the permitting of large renewable energy facilities. (See Cuomo Proposes Streamlining NY’s Renewable Siting.)
Because of these policies, NYISO said a resource’s cost structure is no longer the best predictor of whether it will ultimately get built. Because its proposal will not change how much capacity qualifies under the Part A test, it will not result in price suppression, the ISO said.
“While NYISO’s filing makes references to certain New York state laws, regulations and policies that it argues will drive the composition of New York state’s resource mix, we disagree that the prevalence of public policy resources in the future composition of New York state’s resource mix means they are not similarly situated to nonpublic policy resources for the purposes of the Part A test,” the commission said.
It also said it was not persuaded by the Monitor’s contention that the proposed realignment will minimize surpluses and avoid inefficient incentives for investment in new resources. States “are free to make their own decisions regarding how to satisfy their capacity needs, but they ‘will appropriately bear the costs of [those] decision[s],’ … including possibly having to pay twice for capacity,” the commission wrote, quoting from a 2009 D.C. Circuit Court of Appeals ruling.
“While we respect that New York state may have initiatives to favor the development of certain types of resources, we reiterate that we must base our decision on our duty to ensure just and reasonable rates pursuant to the [Federal Power Act], and not on whether the proposal is consistent with federal, state or municipal renewable energy policies.”
Glick Dissents
Glick said the majority’s “deeply misguided” ruling “is just the latest in the commission’s ever-growing compendium of attempts to block the effects of state resource decision-making,” an apparent reference to its December ruling requiring PJM to expand its minimum offer price rule to include all new state-subsidized resources.
“This time the commission does not even bother trying to hide behind ‘price suppression,’ ‘investor confidence,’ ‘market integrity,’ ‘the premise of capacity markets’ or any of the other inscrutable buzz words that it has used to justify its efforts to ‘nullify’ state policymaking,” Glick said. “Without disputing NYISO’s explanation that these reforms would not cause any ‘price suppression,’ the commission nevertheless rejects the filing because it would expressly facilitate the entry of resources needed to meet New York’s public policy goals.”
Glick termed the ISO’s proposal “a set of minor but eminently reasonable changes” to ensure that the Part A exemption test reflects the commercial and regulatory realities under state policies. The majority’s order used “perfunctory reasoning that displays not even the slightest effort to wrestle with, or even correctly characterize, the arguments advanced by NYISO or the other supporting parties.”
He said the fact that the public policy resources are subject to the same market and interconnection rules as nonpublic policy resources is “irrelevant.”
“The commission has repeatedly recognized that state support may constitute a distinguishing factor that renders resources not similarly situated. For example, in its order accepting ISO New England’s Competitive Auctions with Sponsored Policy Resources construct, the commission approved of an entire new market — the substitution auction — that was open only to state-sponsored resources,” he said.
The order “appears to stake out the new, and even more radical, position that it is improper for an RTO to design its Tariff in a way that even acknowledges, much less accommodates, state public policies — an approach that is both fundamentally misguided and a striking departure from commission precedent and practice,” Glick said.
The majority “puts RTOs and ISOs in an impossible position, forcing them to juggle the commission’s ideological antipathy toward state efforts to shape the resource mix with the realities that Congress gave states responsibility over resource decision-making and that the physical system will ultimately, and rightfully, reflect those state choices. …
“The proposal received a supermajority of votes in the stakeholder process, and not a single party protested this issue before the commission, including any of the generator groups that have cheered on the commission’s slew of recent buyer-side mitigation orders. But, of course, the commission thinks it knows better than NYISO’s stakeholders, better than NYISO’s Market Monitoring Unit, better than the New York state Public Service Commission and better than the people of New York. …
“The most likely outcome of the commission’s misguided campaign to ‘protect’ capacity markets is their ultimate dissolution. Today’s order makes that result all the more likely. New York is currently considering whether to ‘take back’ resource adequacy from NYISO, a move motivated in large part by the commission’s efforts to prevent the NYISO market from reflecting the state’s policy choices. The evident hostility toward state policies displayed in this order will only add fuel to that fire.”
Reaction
“This decision is a stunning example of overreach from Washington, further proof that FERC-regulated wholesale capacity markets are fundamentally flawed. The FERC majority is once again demonstrating hostility to the legally established authority of states to determine how best to provide power to their citizens,” said Chris Casey, a senior attorney with the Natural Resources Defense Council.
“Like other states put in the same bind by FERC’s power grab, New York officials and the grid operator should work together to develop a state-controlled capacity market that serves the public interest while ensuring that New York can meet its clean energy goals.”
The New England Power Pool and the New England States Committee on Electricity (NESCOE) are hiring consultant Peter Flynn, a former National Grid executive, to serve as administrator of the Transition to the Future Grid project.
Flynn, a former senior vice president and deputy general counsel for National Grid, was introduced Tuesday at a joint meeting of the NEPOOL Markets and Reliability committees.
Flynn will report to the committees regularly to ensure the study meets NEPOOL’s and NESCOE’s goals. The study may be outsourced by ISO-NE or conducted by the RTO with assistance from a consultant.
At the joint meeting, Day Pitney attorney Eric Runge presented observations on six past and ongoing studies for their “potential to inform” the Future Grid study. Runge also commented on the proposed scope of the study, which is intended to identify the resource mix needed to meet state climate change goals and gaps in the RTO’s ability to reliably operate the grid under the new conditions.
Carissa Sedlacek, ISO-NE’s director of planning services, also presented the RTO’s preliminary feedback on the 10 study proposals submitted for the Aug. 4 meeting. (See NEPOOL Reviews ‘Future Grid’ Study Requests.)
Straw Proposal
Runge said the next step in the process will likely be development of a straw study proposal presented for stakeholders to debate. He reviewed the objectives, scenarios and modeling used for the 2016 NEPOOL Economic study; the 2019 NESCOE Economic study, as expanded by the Anbaric Development Partners 2019 Economic study; the Massachusetts 2050 Roadmap initiative; Eversource Energy’s “Grid of the Future” study; the “Electric Reliability under Deep Decarbonization” study by Energy+Environmental Economics (E3)/Energy Futures Initiative (EFI); and Brattle Group’s 2019 “Achieving 80% GHG Reduction in New England by 2050” study.
Runge said the NEPOOL, Eversource and E3/EFI analyses seem most consistent with the scope of the Future Grid study.
Interconnection points used for the 12,000-MW OSW scenario in the Anbaric 2019 Economic Study | ISO-NE
Some of the data, analysis and assumptions from the Massachusetts 2050 Roadmap study and the Brattle study could help establish assumptions and identify gaps because they seem to focus on how to achieve an end-state goal, although both use modeling tools the RTO lacks, Runge said.
The NESCOE study is more limited in scope and would provide only a part of the analysis and information being sought in the Future Grid study, he added.
10 Proposals
Commenting on the study proposals submitted, Runge said one from National Grid was generally consistent with the scope but has a transmission/storage focus, with a suggestion to use bidirectional, controllable transmission for optimizing energy storage between New England and Québec.
“The Eversource proposal seems like a complete economic and reliability study and [is] consistent with the intended scope of the Future Grid Study,” Runge said. “The modeling tools associated with it [Gridview and GE MARS] are used” by ISO-NE.
[Note: Although NEPOOL rules prohibit quoting speakers at meetings, those quoted in this article approved remarks afterward to clarify their standing on the issues.]
The NESCOE-proposed “pathway” scenario, which would look at the impact of certain electrification assumptions, could work into a larger study as a scenario, he said.
Anbaric’s call for identifying an onshore and offshore power system that is carbon-free by 2035 seems outside the scope of the Future Grid study because it identifies a goal and then studies how to achieve it, Runge said. He said it could inform assumptions or sensitivities to the study, rather than being its focus.
This 2016 NEPOOL Economic Study graph shows total relative annual resource costs, 2030, with changes compared to 2030 Scenario 4 (constrained) (cents/kWh). Economic modeling was done by ISO-NE using the Gridview tool available to the RTO. | ISO-NE
Runge did not make any comments about the American Petroleum Institute’s request to study how the grid will balance policy goals with other reliability, affordability and energy-access objectives.
He said the remaining proposals had limited focuses “that could be worked into a larger study, or potentially could be used as change cases/scenarios/sensitivities”:
A proposal by Energy Market Advisors on behalf of several public power systems suggested an analysis of how capacity interconnection and minimum interconnections would impact markets and operations. FirstLight Power said the base scenarios should not assume significant new electric storage entry to avoid understating potential reliability problems.
Multi-Sector Group A (Acadia Center, Advanced Energy Economy, Brookfield Renewables, Conservation Law Foundation, Energy New England, Natural Resources Defense Council and PowerOptions) spotlighted a potential need for ramping, regulation and load-following resources.
Multi-Sector Group B (Advanced Energy Economy, Borrego Solar, Conservation Law Foundation, Energy New England, ENGIE, Natural Resources Defense Council and PowerOptions) asked for a long-term transmission system assessment to identify investments that could eliminate obstacles to reaching net-zero-carbon emissions.
NextEra Energy and Dominion Energy jointly requested an analysis of the impact of the loss of NextEra’s Seabrook and Dominion’s Millstone nuclear power plants.
Stakeholder Comments
Anbaric Senior Vice President Theodore Paradise said, “When we were doing our request, we picked 2035 because it fits between the Rhode Island carbon-free goal of 2030 and the Connecticut goal of carbon free by 2040. … The year probably doesn’t matter, though it might for electrification more than for what transmission we think is realistic.”
The request isn’t to do an integrated resource plan, but to figure out if the market and transmission planning rules work to meet state goals, Paradise said. “We need to know what some version of that system looks like. … If the transmission isn’t there, market signals won’t lead to more resources.”
RTO Feedback
Sedlacek said no single modeling platform could provide all the answers requested. She said the RTO does not have a model for projecting Forward Capacity Market clearing and is wary of developing one “because the marketplace may view it as a projection of anticipated market outcomes by the market administrator.”
The Analysis Group has performed FCM price projections for the RTO in the past. Developing study assumptions and modeling parameters typically takes three to six months, and it could take another six to 12 months for the consultant to complete work and provide results. An economic study would likely require use of a probabilistic reliability model such as GE MARS and could be done in about 12 months if done concurrently with the 2020 economic study.
“What I’ve learned over the last two years working on economic studies … is that it’s very difficult to do multiple economic-type studies all at the same time,” Sedlacek said. “There are efficiencies in concentrating on a single study at a time, especially on a topic as complex as the future grid. And the more granular the analysis, the longer it takes.”
“Recall it took us four months to nail down the assumptions for the National Grid study,” she noted.
Projecting ancillary service needs could take at least 15 months because of the need to further develop the Electric Power Enterprise Control System (EPECS) model developed by Dartmouth College, which is a “customized tool that is still in the development stage. It performs the analysis it was designed to do, but additional enhancements are warranted,” Sedlacek said.
She also noted that the RTO generally studies incremental changes to the transmission system rather than the detailed transmission expansion some stakeholders seek.
The RTO’s staff is too small to handle a large design and modeling project while also performing required interconnection and reliability studies, Sedlacek said, and lacks the necessary skills to appropriately estimate transmission costs. Such an analysis, she said, “would be best performed by engineers with relationships with transmission equipment vendors.”
“We would be more than willing to work with ISO-led consultants to conduct this expanded effort once stakeholders have had an opportunity to derive a well defined study scenario,” she said.
If stakeholders agree by November on the modeling assumptions for the Future Grid study, the RTO would need to displace the current 2020 National Grid economic study request to make Future Grid the top priority.
Joe Rossignoli, director of business development for National Grid, said he would like to discuss with the RTO how his company’s study request would be treated upon being delayed, but he added that “we’re good with making way from the resource perspective.”
Pete Fuller of Autumn Lane Energy said, “My concern today is that we know how to study what we know, but not how to study what we don’t know … so, I’m not sure our study will tell us what to do to move toward this new future.”
Sedlacek said the RTO is unaware of any current model that can provide the “detailed, operational dispatch needs of a system with significant inverter-based resources, interaction between the transmission and distribution systems, and evolving load profiles that may occur in the future.” The RTO is beginning work to develop such a model, but it will be “a multiyear effort,” she said.
CAISO called for extra capacity and conservation Thursday and put grid maintenance on hold as it faces a Labor Day weekend heat wave like the one that caused rolling blackouts and strained its system in mid-August.
“We’re lining up everything we can to be prepared for this as best we can,” said John Phipps, the ISO’s director of real-time operations.
In market notices Thursday, CAISO said it is “seeking any available capacity the ISO can procure under its Capacity Procurement Mechanism (CPM) or under section 42.1.5 of the ISO Tariff” from Saturday through Monday. It restricted maintenance operations, urged coordinators to schedule their load in the day-ahead market “considering anticipated high loads” and issued a statewide flex alert calling for voluntary electricity conservation. (The ISO has not yet suspended convergence bidding, as it did during the August heat wave.)
Much of the West will experience triple-digit temperatures during the holiday weekend — similar to the “heat storm” that engulfed many Western states Aug. 13-18 and forced CAISO to order rotating outages Aug. 14-15, an emergency step it hadn’t taken in nearly 20 years. (See Theories Abound over California Blackouts Cause.)
On Sunday, Las Vegas and Phoenix are expected to hit highs of 112 and 111 degrees Fahrenheit, respectively, the National Weather Service forecasted. NWS issued an excessive heat warning for Los Angeles and most of inland California. Even normally cool cities such as San Francisco and Portland, Ore., are expected to reach 90 F.
This Labor Day weekend will see triple-digit temperatures across much of the West.
“A strong ridge will develop over much of the Western U.S.,” NWS said. “This will set the stage for … very hot temperatures, including a likelihood of seeing record-high temperatures. In some cases, the high temperatures are forecast to be as much as 20 to 25 degrees above normal, which will lead to many areas across the Great Basin and especially the Desert Southwest seeing temperatures well over 100 degrees.”
As in mid-August, California could run into a situation in which it is unable to draw on imported energy from neighboring states to meet its evening net peak demand, after the sun sets and solar power shuts down but air conditioning use remains high, CAISO officials said.
“The entire West is competing for supply going into this hot period,” said Mark Rothleder, vice president of market policy and performance. “We rely on what is a limited set of capacity in California and the West, and when you get to these high load levels, it’s stretching that capacity.”
Phipps said CAISO predicts peak demand of 44,237 MW on Saturday, 46,636 MW on Sunday and 45,060 MW on Monday. Those figures are typical of summer peak loads in California and fall far short of the ISO’s peak of 50,116 MW on Sept. 1, 2017, and 50,270 MW on July 24, 2006, both of which it met without resorting to rolling blackouts.
But CAISO’s supply-and-demand has changed dramatically in recent years, said Rothleder and Vice President of Operations Eric Schmitt during a press briefing Tuesday.
Fossil fuel plants, particularly coal-fired plants, have retired across the West. Neighboring states are serving higher demand from population growth while their own ramping capacity diminishes, leaving less for California to import during West-wide heat waves, Rothleder said.
Schmitt said 10,000 to 12,000 MW of solar, including 7,000 to 8,000 MW of behind-the-meter solar, now ramp down at sunset. Compared with the past, “it’s really apples and oranges,” Schmitt said.
ISO-NE is proposing an installed capacity requirement (ICR) of 34,153 MW for Forward Capacity Auction 15, a 722-MW (2%) increase over FCA 14, in part because of reduced expectations of assistance from its neighbors in an emergency.
The RTO presented its ICR proposal and tie line calculations to the New England Power Pool Reliability Committee on Tuesday. The committee will vote on the ICR and related values on Sept. 23.
ISO-NE calculates the ICR — the minimum system capacity needed to meet Northeast Power Coordinating Council reliability criteria — based on sequential Monte Carlo simulations to probabilistically compute the behavior of loads and resources.
The RTO’s annual calculations also account for operators’ ability to purchase energy from neighboring balancing authority areas during a capacity deficiency under Emergency Operating Procedure No. 4.
The RTO’s Fei Zeng told the committee that the Maritimes, Hydro-Québec Phase II, Québec Highgate, New York AC and Cross Sound Cable ties will provide a combined 1,735 MW of tie line benefits for FCA 15 (2024/25), a 205-MW (11%) reduction from FCA 14 (2023/24).
Benefits from the New York AC ties showed the biggest reduction, a drop of 104 MW (29%), followed by a 47-MW reduction for the Maritimes (9%).
ISO-NE is proposing a net installed capacity requirement of 33,270 MW, a 2% increase over FCA 14. The FCA will start at a price of $13.932/kW-month. | ISO-NE
The New York reduction was largely the result of the state’s need to meet higher peak and energy demand forecasts because of increased load forecast uncertainty (40 MW). New York’s increasing need for emergency assistance available from the Canadian control areas reduced the assistance available to New England, Zeng said.
Another 50-MW reduction was attributed to a change in New York’s behind-the-meter PV model: The penetration and hourly shape increased the correlation in the hourly loads between New York and New England.
In addition, a lower Northeast Massachusetts/Boston transmission import capability contributed to a 40-MW reduction, while the retirement of Mystic Units 8 and 9 resulted in a 25-MW decrease. “Tie benefits are a function of how much assistance New England needs and how much assistance our neighboring areas are able to provide,” RTO spokesman Matt Kakley explained. “The retirement of Mystic results in a small decrease in what we would need to be able to replace in an emergency.”
Interconnected system representation for 2024 (MW) | ISO-NE
The region’s internal transmission interface transfer limits reflect several anticipated transmission upgrades: the Greater Boston upgrades with the 345-kV Wakefield-Woburn line in service (2021/22); the Greater Hartford/Central Connecticut upgrades; southwest Connecticut upgrades; and the Southeast Massachusetts/Rhode Island reliability project upgrades.
Subtracting the Hydro-Québec interconnection capability credits (HQICCs) of 883 MW (down from 941 MW the prior year), the net ICR is 33,270 MW, a 2% increase over FCA 14. The reserve margin is 16.6% with the HQICCs and 13.5% without.
“HQICCs are capacity credits that are allocated to interconnection rights holders, which are entities that pay for and, consequently, hold certain rights over the Hydro-Québec Phase I/II HVDC transmission facilities,” Kakley said.
The gross cost of new entry (CONE) for the cap of the marginal reliability impact system demand curve for FCA 15 is calculated as $11.951/kW-month, with net CONE at $8.707/kW-month. The FCA will start at a price of $13.932/kW-month.
FCA 15 will model the same zones as FCA 14, with Maine nested inside Northern New England as export-constrained and Southeast New England as import-constrained.
The Participants Committee will vote on the ICR and related values on Oct. 1, with a FERC filing expected by Nov. 10.
FERC on Thursday rejected SPP’s proposed Tariff revision to develop uniform local transmission planning criteria, siding with stakeholders who argued they would be unduly discriminatory or preferential (ER20-2334).
GridLiance High Plains, Tri-County Electric Cooperative, Kansas Power Pool and a group of eight cooperatives and municipalities protested the filing, which proposed to use zonal planning criteria to evaluate the need for zonal reliability upgrades in SPP’s regional transmission planning process.
The RTO proposed that the network customer with the zone’s largest total network load would designate each year a transmission owner within the zone as the facilitating TO. That TO would develop a single set of zonal planning criteria, conducting open meetings with the zone’s other TOs and transmission customers taking long-term service within that zone.
SPP’s transmission pricing zones | SPP
All TOs within the zone would apply the zonal planning criteria “comparably” to all the zone’s load.
SPP has 18 transmission pricing zones, 10 of which comprise multiple TOs. Currently, each TO submits its own local planning criteria to the RTO, which then uses its regional transmission planning process to determine whether a reliability violation requiring new reliability upgrades should be considered.
Those objecting to SPP’s proposal charged it would give facilitating TOs “unilateral power” and “unduly” benefit them and the zone’s largest network load customer by allowing a single customer, based on the size of its load, to dictate planning criteria for everyone else in the zone.
In a joint protest, GridLiance and Tri-County said “this puts every other entity within the zone at a disadvantage and unduly discriminates against smaller loads in the zone and non-facilitating” TOs. KPP and the cooperatives contended the facilitating TOs are not obligated to take stakeholder input into account when establishing the planning criteria.
The comments echoed their concerns over transparency and equality when the revision request was discussed and approved during SPP’s April governance meetings. Four representatives on the 21-person Members Committee, which advises the Board of Directors with a show of hands, voted against the measure and a fifth abstained. (See “Directors Approve Zonal Planning Criteria, Z2 Elimination,” SPP MOPC Briefs: April 14, 2020.)
FERC agreed with the protests, finding that in zones with multiple TOs, SPP’s proposal would give an undue preference to the network customer with the zone’s largest total network load and to the facilitating TO.
In an email to RTO Insider, GridLiance High Plains President Brett Hooton said, “FERC’s important ruling recognizes that the proposal would have given large incumbent transmission owners complete control over transmission upgrade criteria.”
“Under SPP’s proposal, the network customer with the largest total network load in the zone would have sole authority to designate a single transmission owner in the zone as the facilitating transmission owner, which could be the network customer itself (if it is also a transmission owner) or a transmission-owning affiliate,” the commission said.
Transmission lines in the WAPA footprint | Southwire
“This raises concerns that the facilitating transmission owner could potentially select zonal planning criteria that address its own local reliability needs … or could potentially foreclose SPP’s consideration of local reliability needs of other transmission owners in the zone when identifying the need for zonal reliability upgrades,” FERC wrote. In that case, it noted, the resulting reliability upgrades’ costs would be allocated to all customers in the zone.
The commission said SPP’s proposal would be unduly discriminatory toward the zone’s other transmission customers that do not serve the largest share of load and toward non-facilitating TOs. Aside from attending open meetings, FERC said the zone’s other customers and TOs would have “no formal process rights” or the ability to influence the facilitating TO’s decisions in establishing the planning criteria.
“Facilitating transmission owners could potentially prevent the local reliability needs of other transmission owners in the zone from being considered and thus prevent zonal reliability upgrades from being constructed in response to those needs,” FERC said.
The Tariff proposal was one of 21 recommendations from the Holistic Integrated Tariff Team, which spent 15 months in an effort to help SPP adapt to the evolving grid and electricity markets.
As new solar and wind energy resources come onto the grid, NYISO is preparing to be able to adapt its reserve requirements quickly to a changing resource mix by procuring supplemental reserves during times of system uncertainty.
Supplemental reserve procurements can help provide for system uncertainty introduced by weather-dependent resources, both distributed and grid-connected, as well as potentially more volatile load, according to NYISO. It hopes to have a market design complete this year, Pallavi Jain, energy market design specialist, told the Installed Capacity/Market Issues Working Group on Tuesday.
NYISO is not proposing to add any supplemental reserve requirements now. Rather, it will propose Tariff revisions to establish the process and procedures for implementing requirements when warranted in the future, Jain said. The reserves would be priced lower than the proposed lowest shortage pricing value, $25/MWh, in tiers:
Any 30-minute reserves: $10/MWh
10-minute total reserves: $12/MWh
10-minute spinning reserves: $15/MWh
To help determine the appropriate values, the ISO analyzed historic reserve shadow prices and reserve supply offers.
Pricing analysis of historic reserve supply offers, with those from New York City and Long Island broken out separately to help identify any potential for material differences in offer costs from resources in these regions. | NYISO
Stakeholder Concerns
Couch White attorney Kevin Lang, representing New York City, said he was concerned about extending undue discretion to the ISO to change reserve requirements without stakeholder authorization.
Increasing reserve requirements is in conformity with current practice, with any action taken brought to the soonest meeting of the Operating Committee, said Aaron Markham, director of grid operations at NYISO. “We want to be prepared to change quickly to meet reliability needs,” he said.
Brian Wilkie, manager for New York wholesale strategy at National Grid, suggested that the ISO could communicate its needs beyond the OC, as many stakeholders do not attend its meetings.
Michael DeSocio, NYISO’s director for market design, said there is a way to balance stakeholder concerns and still provide flexibility for the grid operator.
“We’re not delaying addressing any reliability needs, and still have the issue of developing the software we need,” DeSocio said. “I do worry that there is a notion that we can continue to rely on out-of-market actions … which is probably not in the best interests of consumers in the long run, nor in the best interests of achieving the state’s clean energy goals.”
Stakeholders were also presented a consumer impact analysis to aid further discussion of the proposal. NYISO currently plans to seek stakeholder approval of the proposal at the October meetings of the Business Issues and Management committees. If approved, the enhancements would be implemented in 2021, which the ISO expects to occur after implementation of the Reserves for Resource Flexibility project.
The COVID-19 pandemic has roiled the clean energy industry and caused the loss of more than 600,000 related jobs nationwide, and the economic slowdown has also exacerbated social and environmental inequities.
Jeremy McDiarmid, NECEC | NECEC
The Northeast Clean Energy Council (NECEC) on Wednesday held the first in a series of webinars — called the Clean Energy Back to Work Challenge — which brought together a public official, an environmental advocate and a solar developer to explore how energy infrastructure and policy affect environmental justice and social welfare.
“As we know, clean energy is a key element to the economic recovery and the way out of the recession and economic challenges posed by COVID-19,” said Jeremy McDiarmid, vice president of policy and government affairs at NECEC. “We need to make sure that the recovery is just and equitable, and that traditionally disadvantaged populations are getting access to the benefits of clean energy while avoiding the environmental harms associated with fossil generation and pollution.”
Following is some of what we heard at the event.
Broad Goals, Public Policy
Kathy Kelly, Daymark Energy Advisors | NECEC
The clean energy industry now faces three key issues: the environmental justice question, social welfare needs and the intersection of those with public policy on new energy infrastructure, said Kathy Kelly, vice president of operations at Daymark Energy Advisors.
“We have very broad energy goals as a country around decarbonization and the adoption of clean energy and how that fits into our long-term plans,” Kelly said. “We need to make sure that as we do that, unlike the past, that all sectors of our society have access to clean energy and are treated equally as we implement the clean energy infrastructure.”
The disadvantages from energy development in the past hit poor people worst, which has lessons for overcoming the challenges of today, she said. For example, the housing stock in low-income areas is unable to accommodate renewable energy improvements, whether because of outdated wiring inside, or roofs unable to support solar panels.
John Odell, Worcester | NECEC
It’s important not to repeat the mistakes of the past, said John Odell, director of energy and asset management for the city of Worcester, Mass.
Certain parts of the community bear more of the burden than others, which is why the city is developing a Green Worcester Plan to serve as a roadmap, he said.
“We want to get as much clean energy out there, remove as much waste from the waste stream, make sure our natural systems are enhanced as best we can and to do as much of that as fast as we can,” Odell said. “It’s often easier to do those things in areas that don’t have the disadvantages, so that’s where the issues of social equity come to the forefront. It’s easier to build on your strengths than it is to correct your weaknesses.”
Environmental Justice and Social Welfare
Eugenia Gibbons, HCWH | NECEC
Health care accounts for more than 10% of greenhouse gas emissions nationally, but the sector also represents about 18% of GDP and is the largest employer in Massachusetts, said Eugenia Gibbons, Boston director of climate policy for Health Care Without Harm (HCWH), an international nonprofit organization with a network of more than 1,200 hospitals in the U.S.
“We employ about 500,000 people in the state and the sector also holds a significant amount of real estate across the commonwealth,” Gibbons said. “So when hospitals and hospital systems begin to implement climate strategies and try to address climate change in their own systems it’s actually having a huge impact on the surrounding communities and on the state as a whole.”
The pandemic has reinforced the link between air quality and poor health outcomes, which is now undeniable, she said. Low-income communities and communities of color have been proven more susceptible both to the virus and to the effects of climate change and air pollution.
“They have been ravaged by COVID,” Gibbons said. “We have to move away from the impulse to think about climate action as strictly an exercise in reducing GHG emissions, and really try to anchor the work in the communities and anchor the work around people.”
86-kW solar installation financed by Sunwealth at the Provincetown, Mass., Water Treatment Plant | Sunwealth
The pandemic has caused many disruptions to supply chains, and a combination of the coronavirus and recent protests against racial injustice across the U.S. has “forced a lot of organizations and businesses to have a come-to-Jesus moment and say, ‘We’re either prioritizing this or we’re not,’ and a lot of people are making those commitments,” Gibbons said. “It’s up to everyone to see that they follow through.”
Jon Abe, Sunwealth | NECEC
Solar development, finance and construction is “pretty resilient,” said Jon Abe, CEO of solar finance firm Sunwealth, which backs small- and medium-size projects, especially in lower-income communities.
Early on in the pandemic, in many states, solar was deemed an essential service, so while it was complicated, it was relatively easy compared to other businesses to implement the appropriate safety measures at job sites, he said. Sunwealth has almost a dozen developers and installers in the field employing more than 100 electricians and installers at various sites across the U.S.
Sunwealth has been lobbying on low-income community solar inclusion in Massachusetts, where neither the administration nor the legislature has done enough, Abe said.
The Natural Resources Defense Council’s Sustainable FERC Project has released a new interactive map of MISO’s interconnection queue, highlighting how many renewable gigawatts the footprint has lost out on because of limited transmission capacity.
The organization’s director, John Moore, said it’s important for regulators and policymakers to see where once economic renewable generation projects have evaporated.
“The primary reason we did this is the MISO doesn’t offer a lot of insights into the locations of these projects. And I don’t think people are aware of the projects that are growing and dying right in their backyards,” Moore said in an interview with RTO Insider.
The map displays in-progress and canceled projects on the county level. The Sustainable FERC Project found that 245 clean energy projects — or 40% of withdrawn projects over the past four and a half years — “had reached advanced stages of the generator interconnection process” when they were shelved. The organization said the projects could have generated 30.9 GW.
Michigan and Minnesota had the most withdrawn generation projects, the organization said. Michigan, which experienced a capacity shortage to meet local load obligations in this year’s MISO capacity auction, saw 42 projects worth about 5.1 GW abandoned from 2016 to 2020. Minnesota saw 36 projects that could have generated nearly 5 GW withdraw.
“It illustrates in another way that problem,” Moore said of the map. “Twice as many projects are falling out of the queue than normal because of the cost of integrating them.”
The Sustainable FERC Project said many developers are forced to scratch projects because of MISO’s inability to approve “large-capacity transmission lines and grid upgrades.” Moore said that while the cost of network upgrades isn’t the only reason for projects falling out of the queue, it’s become the most significant one.
MISO earlier this month announced it will embark in a series of long-range transmission studies that could produce project approvals as early as the end of 2021. (See MISO Processing Heftiest Interconnection Queue Ever.) The grid operator is also working with stakeholders to try to better line up its annual transmission planning with needed network upgrades that are identified in interconnection queue studies.
The MISO queue currently contains 756 projects totaling 113 GW, 64% of which is solar. It’s the grid operator’s largest-ever interconnection queue, with 353 project proposals representing about 52 GW of new generation entering in July alone.
Moore isn’t hopeful all that solar generation will see the light of day. He said MISO is late to arrive at the long-term transmission studies, and he predicted that many projects in the record-breaking queue will fall off.
“I’m still not hopeful because I don’t think the planning is keeping up with the queue,” Moore said. “The costs for the network upgrades are obviously far too expensive for any developer to absorb. So, no, I’m not hopeful.”
Clean Grid Alliance, Solar Energy Industries Association and the American Wind Energy Association said upgrade costs have been raising the cost of renewable generation projects in MISO West by more than 60% on average.
The Sustainable FERC Project’s map doesn’t yet include the lineup of new projects that entered in July, but Moore said his organization plans to update it and continue to keep tabs on unrealized projects for regulators and policymakers.
“Leaders aren’t familiar with the types of projects that are coming and going and trying to get on the system,” he said.
Moore said that though MISO is moving in “better directions” with a long-term transmission process approach and trying to coordinate grid planning, states’ clean energy targets could be compromised by project withdrawals. He pointed to integrated resource plans in Michigan and Minnesota, which order more renewables online while the two states see promising proposals vanish.
“Whatever the intention of utilities, the lack of transmission makes it significantly harder,” Moore said, adding that MISO could benefit from using longer-term study assumptions for both generator interconnection and transmission planning.
The Sustainable FERC Project pointed to EDP Renewables’ planned 100-MW wind farm in southwestern Minnesota that was dropped this year after MISO assigned the project an $80 million network upgrade cost — eight times what the developer expected.
EDP Origination Manager Vipul Devluk said the project could not absorb the cost burden. “Ultimately, we had to cancel our power purchase agreement discussions with the customer, and we had to relay to the local community that the benefits they were expecting from this project would not be forthcoming,” he said.
Moore said that even MISO South is susceptible to thwarted renewable megawatts because of MISO’s lack of transmission buildout. The map shows Mississippi lost nearly 2 GW in planned solar generation from 2016 to 2020.
“There is economic development and carbon-free energy being left on the table,” Moore said. “Once there were projects, and now there are none; once there were plans, and now they’re gone.”
MISO spokesperson Allison Bermudez said the RTO “continues to work with our stakeholders to determine the most cost-effective transmission investments needed to support future energy needs.” She declined to comment further on the map.
The RTO has said it can likely operate its system reliably with renewable penetration targets up to 50%, but only if members engage in dramatic transmission expansion. (See MISO Renewable Study Shows More Tx, Tech Needed.)
