MISO transmission owners have filed with FERC to eliminate all reactive power and voltage-control charges from their own and affiliated generation resources.
The TO sector said the revisions will result in a rate decrease for transmission customers. They agreed in October to make the filing and requested FERC backdate the change to Dec. 1 (ER23-523).
Under Schedule 2 of MISO’s tariff, most generation owners can apply to receive separate compensation for their reactive supply. The TOs said they no longer want any separate charges to pay for reactive service supplied within the standard power factor range of 0.95 leading to 0.95 lagging power factor.
The TOs proposed that online generation called up or manually redispatched by MISO to furnish reactive power outside of the generator’s deadband (a control system’s band of input values where the output is zero) should still be compensated. They said their proposal would put an end to generation receiving “compensation whether or not it ever actually supplies reactive power or whether or not it is located in an area where there is an actual need for additional reactive power.”
FERC has previously ruled that generators don’t have to be paid for reactive power within the standard range, the TOs said.
During an Advisory Committee meeting Wednesday, members asked whether the TOs expect resistance to the filing.
“I think there are a number of different views on the filing, so there is a possibility that it will be protested,” Stacie Hebert, a TO representative for Otter Tail Power, said.
MISO said it has not taken a position on the filing but submitted it to FERC on behalf of its TOs.
The TOs emphasized that their proposal will not affect the grid’s reliability.
“The proposed revisions eliminate the capability-based reactive power compensation via Schedule 2, and impact neither the need for or creation of reactive power nor the ongoing obligation of generators to provide reactive power,” MISO TOs said. “In other words, new generators will still be required to have the capability to provide reactive power within the deadband as a condition of obtaining interconnection and all generators will still be required to operate with that capability enabled as a condition of maintaining an interconnection.”
As ISO-NE continues to hack away at the complicated process of updating its capacity accreditation method, the grid operator is turning its attention to gas.
In a presentation to the NEPOOL Markets Committee on Tuesday, ISO-NE officials outlined principles for how they plan to upgrade accreditation of gas resources, which has been an emphasis for many stakeholders frustrated that the current process fails to take into account fuel storage limitations.
ISO-NE is planning to introduce a qualification rule that would reflect gas generators’ fuel storage capabilities and fuel contracting arrangements for the winter, said Tongxin Zheng, the RTO’s director of advanced technology solutions.
Gas resources’ qualified capacity for the winter season would be divided into firm and non-firm capacity. Non-firm capacity — that which is not backed up by on-site fuel storage or firm fuel contracts — would lead to a lower capacity rating for resources.
“Gas resources will be required to demonstrate firm fuel arrangements (e.g., LNG contracts, firm pipeline transport, proposed dual-fuel capability and on-site storage capability) in the qualification process,” Zheng said.
ISO-NE is also planning major changes to how it models resource adequacy during the winter. The grid operator is planning to use forecasts of available pipeline capacity and LNG under different scenarios to enhance its modeling.
Early Concerns from LS Power
Ben Griffiths of LS Power offered a rebuttal to ISO-NE, presenting on the company’s initial criticisms.
In particular, Griffiths said LS is “concerned that the ISO is deviating from its unit-specific approach when addressing pipeline gas availability.”
Unlike other pieces of ISO-NE’s marginal reliability impact (MRI) approach to accreditation, he said, the proposed fuel framework “relies on class-level accreditation mechanisms.”
ISO-NE’s resource capacity accreditation project “will be a failure unless it can reasonably distinguish between high-quality, gas-only resources and low-quality ones,” Griffiths said.
Among the various discrepancies between resources, he said, are that gas availability is spottier at downstream delivery points; different pipelines go to different points; and different units have gas arrangements with varying levels of “firmness.”
He noted an incident from March of this year, when multiple gas-fired generators warned the grid operator that they might be short on gas imminently. To fill the gap, several additional fast-start resources came online — including another gas plant, LS Power’s Wallingford facility.
“If some gas resources are coming offline for fuel unavailability while others can come online with no notice to replace them, then gas resources cannot be treated as one-for-one,” Griffiths said.
The West Coast’s first offshore wind auction got off to a cautious start Tuesday, with bids closing the day at levels far lower than two East Coast wind auctions held earlier this year.
By the close of bidding at 5 p.m. ET, the high bids for five leases off the California coast had reached an average of $1,037/acre, a little less than the $1,083/acre paid for wind leases off the Massachusetts coast in 2018, the Interior Department’s Bureau of Ocean Energy Management reported.
The auction will resume Wednesday morning at 10 a.m. ET, and some observers predict bidding could continue through Thursday, with prices more than doubling from Tuesday.
The California auction involves 373,267 acres in two large wind energy areas — the Humboldt Wind Energy Area off the coast of Northern California and the Morro Bay Wind Energy Area off the coast of Central California. (See BOEM Sets California Offshore Wind Auction Date.)
The California bidding totaled $387.1 million at the close of business Tuesday. By comparison, winning bids for the New York Bight area in February set a record of $8,837/acre, totaling $4.7 billion, while a North Carolina auction in May fetched $2,900/acre, for a total of $315 million.
As the auction began Tuesday morning, California Gov. Gavin Newsom hailed it as a “historic step.”
“Together with leadership from the Biden-Harris administration, we’re entering a new era of climate action and solutions that give our planet a new lease on life,” Newsom said in a news release. President Biden established a goal last year for the U.S. to deploy 30 GW of offshore wind by 2030.
California has a mandate to provide retail customers with 100% clean energy by 2045 under 2018’s Senate Bill 100. The state’s Energy Commission has proposed offshore wind goals of 25 GW by 2045 to help fulfill that target.
Environmental groups and trade associations lauded the start of the auction.
“California will be the big winner in this first lease sale for the state’s multigigawatt floating offshore wind resource,” Adam Stern, executive director of Offshore Wind California said in a statement. The trade group declined to comment on the bidding so far.
Reasons for Caution
Analysts had warned that bidders could be cautious given the West Coast’s lack of offshore wind infrastructure, including developed ports, and the floating wind turbines required in California’s deep offshore waters.
ClearView Energy Partners called floating offshore wind “a far more nascent and undemonstrated technology,” saying the higher risks could mean lower lease prices.
“The record number of [43] eligible companies bidding for the areas suggests a highly competitive environment that may not conclude until tomorrow or Thursday,” ClearView said in a statement previewing the auction.
“However, we are not yet convinced that final per-acre prices will exceed those reached for the WEAs leased off New Jersey and New York earlier this year,” the firm said. “While California has aggressive decarbonization targets and needs new non-solar renewable resources, it does not yet have policies specifically targeting offshore wind akin to those adopted by several East Coast states.”
The Business Network for Offshore Wind said it was “excited to see the commencement of the first West Coast and first floating offshore wind lease auction” but warned not to expect record prices.
“The Network does not believe the California leases will fetch as high of auction fees as the New York Bight but will likely eclipse what we saw in the Carolinas,” the trade association said in a statement. “The New York Bight had several key elements including a very visible path to offtake, strong monetary and public support from state governments, a visibly emerging port infrastructure and supply chain, and apparent willingness to tackle transmission. …
“Today, the California market is not as strong, and adding in new technology development will likely result in a lower price,” it said. “However, California is a premier market with strong political and public support and being the first to market is very attractive, as auction prices will only rise over time.”
Driven by global concerns about energy security and new government support — such as the Inflation Reduction Act in the U.S. — renewable energy could see unprecedented growth in the next five years, outpacing natural gas and coal as the world’s top source of electricity, according to a new report from the International Energy Agency.
“In the next five years, the growth will be equal to what we have seen in the last 20 years,” IEA Executive Director Fatih Birol said Tuesday at an online rollout for the Renewables 2022 report. “Solar will be the No. 1 source of electricity in the world.”
Heymi Bahar, IEA | IEA
The IEA has upped its projection for renewable capacity growth to more than 2,400 GW by 2027, a 30% increase over its five-year projections in Renewables 2021, said IEA Senior Analyst Heymi Bahar, a lead author of the 2022 report.
But even this accelerated growth, based on existing policies, will not be enough to ensure climate change can be limited to 1.5 degrees Celsius, the global goal set in the Paris climate accords of 2015. To stay on track for that target, the IEA estimates total renewable capacity would have to grow by more than 3,500 GW in the next five years.
“Most advanced economies face challenges to implementation, especially related to permitting and grid infrastructure expansion,” the report says. In the U.S., an estimated 1,400 GW of solar, wind and storage projects are currently in interconnection queues, according to figures from the Lawrence Berkeley National Laboratory.
In developing and emerging countries, policy, weak grid infrastructure and lack of access to financing are the main obstacles. Addressing these challenges, in both developed and developing countries, could close the gap about halfway, the report says.
Still, the IEA report is mostly optimistic. “Annual solar PV capacity additions increase every year for the next five years,” the report says. “Despite current higher investment costs due to elevated commodity prices, utility-scale solar PV is the least costly option for new electricity generation in a significant majority of countries worldwide. …
“Distributed solar PV, such as rooftop solar on buildings, is also set for faster growth as a result of higher retail electricity prices and growing policy support to help consumers save money on their energy bills,” the report says.
In other words, Behar said, “Cheap renewables are providing new capacity that is cheaper than existing systems or new additions.”
Renewables coming online will account for 90% of new capacity growth in energy markets worldwide and almost 40% of all electricity production by 2027, Behar said
By 2027, renewables will be the top source of electricity in the world, surpassing both natural gas and coal. | IEA
“We expect the share of all the other fuels to decline, and their share basically [to move] to the renewables,” he said. Solar capacity will surpass natural gas in 2026 and surpass coal in 2027, Behar said.
The report also sees a gradual shift in global supply chains, with government incentives, like the IRA’s tax credits for solar manufacturing, helping to create domestic supply chains, both in the U.S. and India, which can in turn lessen U.S. dependence on China for solar imports.
The IRA’s manufacturing tax credits, which come with a direct pay option, “could bring all segments of PV manufacturing to cost parity with the lowest-cost manufacturers” in China and Southeast Asia, the report says.
But such policies will, at best, put a dent in China’s dominance of renewable energy supply chains, the report says. The IEA estimates that the country’s share of global supply chains could dip from the current level of 80 to 95% to 75 to 90%. Maintaining trade policies that limit solar imports and encourage domestic production could shrink China’s market share further to 60 to 75% by 2027, the report says.
But, Behar said, the build-out of supply chains in the U.S., India and China could produce a supply glut, with supply “doubling the need of the demand in the coming years. So, there will be an important opportunity to merge several manufacturers in terms of their plants or basically decommission the old capacity, which has the oldest technology today,” he said.
1.5 Still Alive
As it did in its recent report on energy efficiency, the IEA frames drivers and trends in renewable energy development with the impacts of Russia’s war on Ukraine. The war, and the global energy crisis it has triggered, have “turbocharged” renewable energy growth, Birol said. (See IEA: Global Energy Crisis Puts Efficiency at ‘Center of Policy Agendas.’)
Fatih Birol, IEA | IEA
“Many countries around the world see renewables now as an option to address energy security concerns” and replace Russian gas imports, especially in Europe, he said.
Another key driver is cost, Birol said. “The high-end, volatile fossil fuel prices [for] gas and coal make renewables competitive, even more competitive when it comes to electricity generation and high oil prices,” he said. “So solar is and will be the king of global power markets.”
The IEA report also, for the first time, looks at green hydrogen production as an emerging, but significant driver for renewable energy growth. More than 25 countries, including the U.S., and the European Union have introduced “policies and support measures.”
At present, IEA says about 500 MW of solar and onshore wind are dedicated to green hydrogen production, powering electrolyzers that produce hydrogen without carbon emissions, unlike most “grey” hydrogen produced from natural gas. IEA expects 50 GW of renewables will be used for green hydrogen production worldwide by 2027, a 100-fold increase, Behar said.
Hydrogen production emerges as a new driver for solar and wind growth. | IEA
Looking specifically at the U.S., IEA predicts a 74% increase in renewables, adding more than 280 GWof solar and wind to the grid by 2027, with only a very small 4 GW dedicated to green hydrogen production. At present, the U.S. has about 131 GW of solar, according to the Solar Energy Industries Association.
Supply chain interruptions and the Commerce Department’s preliminary decision extending solar tariffs on solar cells and modules imported from companies in Cambodia, Malaysia, Thailand and Vietnam have slowed solar growth, with a 20% dip predicted for 2022, the report says. (See Solar Industry Slams Commerce Decision Extending Solar Tariffs.)
IEA expects the slowdown to be short-term. A range of incentives and tax credits in the IRA are “expected to make the business case more attractive for utility-scale projects,” the report says. Growing momentum in offshore wind is also expected, with the potential for up to 15 GW of projects in the development pipeline to go online by 2027.
President Biden’s goal of 30 GW of offshore wind by 2030 faces a list of barriers, the report says, “including long federal and state-level permitting wait times; Jones Act requirements that reduce the number of installation vessels available; and the need for port and transmission infrastructure development.”
The Jones Act requires that ships moving goods between U.S. ports be U.S.-owned and -operated. Such vessels for offshore wind deployment are currently limited.
The obstacles still slowing renewable energy growth inevitably raise questions about whether the Paris accord’s 1.5-degree limit on climate change is still possible, as one reporter asked Birol at the end of Tuesday’s webcast.
While acknowledging the difficulties ahead, Birol said, “It is far too early to write the obituary of the 1.5-degree target.”
Investments in clean energy are expected to reach $2 trillion by 2030, only about half of the $4 trillion needed to get to net zero by 2050, he said.
“Is it easy? Not at all,” Birol said. “Especially if we note that the bulk of this money needs to go to emerging and developing countries, it’s a big challenge. But in our view, to say that a 1.5-degree target is dead is factually poor and politically irresponsible. Such a conclusion may even jeopardize [our ability] to reach the targets of 1.6 [and] 1.7 degrees.”
California ranks highest in a nonprofit advocacy group’s annual report on states’ energy-efficiency policies and programs, while the next eight entrants on the list are all clustered in the Mid-Atlantic and New England regions.
The American Council for an Energy-Efficient Economy on Tuesday issued the 2022 edition of its State Energy Efficiency Scorecard, first compiled in 2007.
It was the second year in a row that ACEEE put California at the top of the list; the report’s authors said it has become a leader for other states with its clean energy building codes and standards for vehicle emissions and appliance efficiency. As a result, it was awarded 47 of a possible 50 points.
“California recently approved the Advanced Clean Cars II rule, which will help the state meet its carbon neutrality targets,” the report noted. “The rule, if adopted by other states, will greatly grow the zero-emission vehicle market and deliver significant clean air and climate benefits.”
This year’s scorecard gave greater weight to states’ efforts to ensure that the clean energy transition benefited all segments of society, including those marginalized in the past.
During a webinar Tuesday discussing the scorecard, California Public Utilities Commissioner Genevieve Shiroma said the state has a very aggressive environmental justice plan to ask the question “are we lifting the least among us” as it moves the energy transition forward.
California attained a near-perfect score on equity, but 34 states earned less than half the possible points, according to ACEEE’s Sagarika Subramanian, lead author of the study.
“A small but growing number of states are making progress toward [equity],” she said during the webinar. “I think leading states are really understanding the importance of all customers being included in the clean energy transition.”
Among the 50 states and D.C., Maine made the biggest jump in the annual ratings, moving up 11 spots to No. 5 on the strength of its climate leadership, particularly in the buildings sector.
Projects funded by Maine’s housing authority are now required to be all-electric and include EV charging; weatherization and heat pump incentives have been increased; and Maine’s Clean Transportation Roadmap sets out a plan to advance EV adoption.
Dan Burgess, director of the Maine Governor’s Energy Office, said Gov. Janet Mills and the Legislature have set out ambitious energy-efficiency and net-zero goals. “We’ve been hard at work across state government and with partners across Maine working on how to achieve those targets,” he said.
The scorecard reflects the great diversity of opinion and policy within the U.S. The authors note that while some states are taking extensive steps to encourage electrification, at least a dozen others forbid incentives to switch from fossil fuel heat to electric.
South Carolina took the biggest drop in the rankings, falling nine spots to tie with Kansas at 49th because of policies that discourage use of efficiency funds for fuel switching; restrictions on jurisdictions adopting a more stringent energy code than the statewide code; and not having equitable planning or processes.
Dead last on the ACEEE scorecard was Wyoming, at 51st place with 2 points.
The scorecard flags Colorado (13), Michigan (15), Nevada (21), New York (3), North Carolina (25), Oregon (11) and Washington (11, tied with Oregon) as “states to watch” because of their high ranks within their own regions and the promising model they offer their neighbors.
NV Energy has filed a proposal aimed at reducing Nevada’s dependence on the open energy market through the addition of geothermal resources, battery storage and a 440-MW, gas-fired peaker facility.
The plan proposes to postpone by either five or 10 years the retirement dates of several gas-fired units in both northern and southern Nevada. The proposal also addresses NV Energy’s removal from its energy portfolio of two solar-plus-storage projects that the company said have stalled because of supply chain issues.
The plan was filed last week with the Public Utilities Commission of Nevada (PUCN) as an amendment to the company’s 2021 integrated resource plan. A commission decision on the plan is expected by mid-May. But NV Energy is asking the PUCN to approve the Silverhawk peaking facility by March 10, so that operations can start by July 2024.
NV Energy said Nevada’s energy supply has faced challenges over the last three summers caused by energy shortfalls in California and increased competition for energy across the West. The company said the proposal is intended to “shield” its customers from the impacts of regulatory changes in California and resource adequacy challenges.
“Our plan will advance Nevada’s energy independence — ensuring reliable energy for our customers no matter how hot it gets across the western United States while also advancing our state’s sustainability and clean energy goals,” NV Energy CEO Doug Cannon said in a statement.
NV Energy’s push for Nevada’s “energy independence” comes as the state faces a 2030 deadline for its transmission providers to join an RTO as mandated by Senate Bill 448 of the state legislature’s 2021 session.
NV Energy has been participating in the RTO discussions. It is also a participant in the Western Markets Exploratory Group (WMEG), a stakeholder group that is discussing the design of two proposed day-ahead markets: CAISO’s extended day-ahead market and SPP’s Markets+. (See NV Energy Seeks Recovery of RTO-related Expenses.)
“Our filing aligns with our support of a regional transmission organization that will improve resource adequacy and improve reliability for our customers,” an NV Energy spokesperson told NetZero Insider.
Plan Components
NV Energy’s new proposed resource plan includes a 200-MW, grid-tied battery storage system on the site of the coal-fired Valmy Generating Station in Northern Nevada, which is slated for retirement by the end of 2025. The estimated cost for the battery storage is $466 million.
The Valmy battery storage would be a four-hour system, in contrast to the recently approved two-hour Reid Gardner battery storage system. Reid Gardner was designed to target the tip of summer net peak load, while Valmy will cover a broader portion of the peak, NV Energy said in its filing.
Another component of the plan is 440 MW of natural gas-fired combustion peaking turbines on the site of the Silverhawk Generating Station in southern Nevada. Silverhawk is a 520-MW, gas-fired power plant near Las Vegas.
NV Energy said in its filing that the Silverhawk peaking plant would be able to run on a 15% hydrogen fuel mix, with a potential for 100% hydrogen operation in the future.
The geothermal piece of the plan includes a 120-MW package of geothermal projects from Ormat and a 20-MW geothermal system from Eavor. The pricing for the geothermal energy would be $69/MWh for the Ormat portfolio and $70/MWh for the Eavor project — prices that NV Energy called “historically low” for a geothermal resource. For example, the Eavor price would be 28% lower than the last geothermal energy price that PUCN approved.
NV Energy’s proposal also includes transmission upgrades to accommodate the new energy resources.
Solar Projects Stalled
NV Energy received PUCN approval in January to purchase the Iron Point and Hot Pot solar-plus-storage projects from Primergy Solar. The projects — totaling 600 MW of solar and 480 MW of battery storage — were intended as replacement resources for the Valmy coal-fired plant.
But now, Iron Point and Hot Pot are “no longer expected to move forward as previously approved,” NV Energy said in its filing, blaming supply-chain issues.
“Due to the recent … price increases in the solar and energy storage market, [the developer] was unable to complete procurement on the schedule and at a price supporting that approved by the commission,” the filing said.
NV Energy said it is working with the developer to find ways that one or both projects could be delivered. Primergy didn’t immediately respond to a request for comment sent to the solar company’s publicist.
WASHINGTON — The transition to a more distributed power system is well underway, but system operators need better visibility into that shift, experts told GridWise Alliance’s gridCONNEXT 2022 on Tuesday.
“I’ve got 5,800 EVs and plug-in hybrids on my system, and I control 21,” said Mark Gabriel, CEO of Denver area cooperative United Power. “This number is going up between 100 and 200 a month. It is ramping like crazy, and we have no ability to control it.”
United Power has seen 9,400 of the 107,000 meters it serves adopt distributed solar, but it has control over none of those, he added.
The old days of vertically integrated utilities featured power systems that were much easier to run, and all of the risk was at the utility. But now the assumption of risk is moving toward the customer — or member in the co-op’s case, Gabriel said.
In response to the changes, United Power is shifting from its role as a generation and transmission cooperative to become a distribution system operator that will need to be linked up to a wholesale market, Gabriel said. Colorado law (SB 72) requires the state’s utilities to enter an RTO by 2030, but Gabriel said that shift should happen at least five years earlier.
Portland General Electric, which is facing many of the same issues, will get one-quarter of its supply from the distribution system by 2030, said Vice President of System Operations Larry Bekkedahl. The Oregon utility is also adding 3,000 MW of renewables and 1,000 MW of storage over the next decade to a system with peak demand of 4,400 MW.
“If anybody thinks they’re bored in our industry right now, come see me,” Bekkedahl said.
Those changes to supply are coming on top of climate-driven demand shifts. PGE saw its all-time peak in June 2021, when temperatures hit 116 degrees Fahrenheit in Portland. PGE’s demand was 10% higher than it ever had been.
“Our previous peak was 4,100 MW,” Bekkedahl said. This summer’s high was 97 F, with a peak load of 4,250 MW. “So everyone that didn’t have air conditioning the year before now has air conditioning in their house.”
Such rapid demand growth makes the historic utility practice of using the previous 15 years as a guide questionable, he added.
CAISO recently broke a 15-year-old demand record as high temperatures led to consumers using 52,061 MW on Sept. 6, said Hani Alarian, the ISO’s executive director of power systems, technology and operations. CAISO avoided rolling blackouts with a text message from the governor’s office urging Californians to conserve.
CAISO, which has seen solar grow to more than 14,000 MW, also has 12,000 MW of rooftop solar, which is only seen by the grid operator when it impacts demand. The ISO also has seen more than 3,000 MW of battery storage added in recent years, which will continue growing, Alarian said.
All that solar has made the hours of 4 to 9 p.m. during high demand days the most difficult to manage, as solar production falls off while demand remains high.
“In three hours we [ramped] almost 18,000 MW; that’s a sustained 100-MW ramp rate [per] minute for three hours,” Alarian said. “That’s a lot of ramp.”
While the demand side is changing because of climate change, distributed generation and electrification, advanced metering technology is keeping pace and is now much more functional than the first round of the technology, which only eliminated meter reading jobs and helped utilities with operations, said Jonathan Staab, manager of product development at Landis+Gyr. The second wave of advanced meters allowed for more engagement with consumers by enabling dynamic pricing and increasing customer visibility into their power usage patterns.
“The third wave in this evolution happens to be the wave that we’re in right now,” Staab said. “This wave, I would argue, is probably the largest technological advancement, and it involves direct and often real-time engagement with consumers.”
While Landis+Gyr provides the meters for that engagement, the firm Sense offers software that can show customers exactly which of their appliances are using power — and even whether something is wrong with one of them, said its vice president of energy services, Colin Gibbs.
Gibbs demonstrated how his company’s app showed his home’s energy uses as his wife, who was across the country, turned on appliances such as the coffee kettle and their clothes washer. The appliances immediately showed up on his app with their total power use. “It’s important to note that this is not a smart coffee kettle; this is not an IOT [internet of things] device; this is just some regular, old electric resistance coffee kettle that we use in the morning,” Gibbs said.
Sense currently has to add a small submeter to customers’ utility meter that costs about $300 and another $150 for an electrician to install it, but eventually that will go away as more utilities roll out advanced smart meters. Sense will offer apps for new smart meters, Gibbs said.
FERC last week approved a $700,000 penalty on FirstEnergy Utilities (NYSE:FE) as part of a settlement between the utility and ReliabilityFirst for violations of NERC’s facility ratings standards.
NERC submitted the settlement as a Notice of Penalty in October (NP23-1). FERC said in a statement Wednesday that it would not further review it, leaving the penalties intact.
FirstEnergy’s penalty stems from infringements of FAC-008-3 (Facility ratings) and FAC-009-1 (Establish and communicate facility ratings). Requirement R8 of the FAC-008 specifies the information that transmission owners and some generator owners (GOs) must provide about their facilities to reliability and planning coordinators, and to transmission planners, owners and operators; R1 of the latter standard mandates that TOs and GOs “establish facility ratings for [their] solely and jointly owned facilities that are consistent with the associated facility ratings methodology [FRM].”
On May 9, 2019, FirstEnergy reported to ReliabilityFirst that it was in violation of FAC-009-1. The utility said it had discovered that a facility rating for a 345-kV line was incorrect; after a further extent of condition review on 10 substations, FirstEnergy decided to expand the review to include field walkdowns at all facilities to which the standard applied.
That expanded review “revealed further issues with the accuracy of [FirstEnergy’s] facility ratings across its entire footprint,” according to the settlement. While the full walkdown is expected to be completed by Dec. 31, the utility has already discovered inaccurate ratings at 443 facilities, about 35% of those reviewed by the date of the filing; 301 of those facilities have had their ratings adjusted downward, while the others had to be adjusted upward.
The FAC-008-3 violation arose from self-reports that FirstEnergy submitted in July 2020 and April 2021, stating that it had “failed to provide its TOP [transmission operator], PJM, with the most-limiting facility rating equipment.” The issue began when FirstEnergy realized during a communication with PJM that it had not informed the TOP that a flow circuit breaker was the most-limiting element on a 500-kV transmission line under some circumstances.
An extent-of-condition review found that 50 circuit breakers were similarly incompletely modeled in PJM’s energy management system (EMS). An additional 38 flow circuit breakers were discovered during a later review to either contain ratings discrepancies or to be absent from the EMS altogether.
ReliabilityFirst assessed the FAC-009-1 violations as a “serious and substantial” risk to bulk power system reliability because it could have caused FirstEnergy to operate equipment above its maximum rating, which might have led to equipment degradation and failure, to load shedding in emergencies or to “incorrect post-contingency planning.” The long duration of the violation — the earliest instance began in 2007 when the standard took effect, while the final infringement is expected to end by Dec. 31 — was another factor in assessing the risk.
The FAC-008-3 violations, on the other hand, were assessed as a moderate risk to grid reliability. The factors elevating it from a minimal level were the number of instances, the duration (about four and a half years) and the absence of effective processes to ensure that facility ratings would account for the behavior of circuit breakers in abnormal system conditions.
FirstEnergy’s mitigation actions for the FAC-009-1 violations mainly relate to the ongoing review of facilities, which is expected to lead to corrected ratings for all equipment; the utility has already changed its internal controls to improve the accuracy of its transmission ratings database. For the FAC-008-3 infringements, FirstEnergy’s mitigations include providing PJM with updated EMS model data and ratings, creating internal controls to detect any needed circuit breaker and line rating adjustments, and training personnel to ensure they understand the new processes.
Energy officials from California and across the West weighed the potential benefits of Western electricity system integration for cost savings, transmission and resource adequacy in an all-day workshop Friday hosted by the California Energy Commission.
The workshop was meant to brief a broader audience, including state lawmakers, on regional market developments. In the past year, CAISO and some California lawmakers have advanced the idea that California should play a larger role in regional markets as it faces competition from challengers such as SPP.
Friday’s session was part of the commission’s Integrated Energy Policy Report (IEPR), a biennial assessment of energy issues and policy recommendations in which the CEC tries “to elevate important topics to make sure … the state Legislature is aware of what is happening in the energy space,” Commission Vice Chair Siva Gunda said.
“So, with that spirit, we have included the Western integration topic as an important element of this year’s IEPR,” Gunda said. “A lot has been happening over the last couple of years, and we thought it’s extremely important to provide a transparent, high-level update on what’s happening in the West as it pertains to Western integration and the markets.”
CAISO, for instance, began a stakeholder process in mid-October to explore the benefits of greater regional cooperation and a Western RTO, as California lawmakers had requested in Assembly Concurrent Resolution 188 in August. The resolution’s goals were limited, requiring only that CAISO report to the Legislature on recent studies of RTO benefits, but some saw ACR 188 as a cautious opening gambit in another regionalization effort. (See CAISO, NREL Start to Study Western Cooperation.)
Several prior attempts at turning CAISO into an RTO fizzled in 2016-2018, as most lawmakers balked at broadening its governance to include other states. CAISO is a public benefit corporation created via state statute in 1998; the California governor appoints the five members of its Board of Governors.
However, circumstances have changed substantially since the last legislative attempt to broaden CAISO’s governance in 2018.
SPP is making inroads in the West with its Markets+ day-ahead offering and a plan to expand its Eastern RTO into the Western Interconnection. Utilities in Colorado and Wyoming have indicated they plan to join both. (See SPP Issues Final Markets+ Proposal.)
The Western Power Pool (formerly the Northwest Power Pool) will soon launch its Western Resource Adequacy Program, which could cover much of the Western Interconnection. WPP hired SPP to administer the program, and some observers have speculated that the WRAP might be a logical precursor to another Western RTO.
Workshop participants met in a hybrid in-person and online gathering to weigh these and other developments. They included members of the California Public Utilities Commission, CAISO CEO Elliot Mainzer, Air Resources Board Chair Liane Randolph and Gov. Gavin Newsom’s senior energy adviser Karen Douglas.
Participants from other states included utility commissioners from Colorado and Oregon and representatives of SPP, the Western Interstate Energy Board, the Western Electricity Coordinating Council, the Western Power Pool and the Northwest & Intermountain Power Producers Coalition.
“The attendance here today is indicative of the importance of this conversation,” Gunda said.
Role of Markets
A panel exploring the role of regional markets began the substantive discussions.
This year CAISO fast-tracked its extended day-ahead market (EDAM) proposal for its Western Energy Imbalance Market, a real-time interstate trading forum that has saved participants more than $3 billion in the past eight years. The real-time market, however, involves only a small amount of the transactions that occur in day-ahead trading.
“The success of the WEIM demonstrates that there’s a potential for a lot more,” said Anna McKenna, CAISO vice president of market policy and performance.
A recent study by consulting firm Energy Strategies found the EDAM could generate $1.2 billion a year in benefits, or 60% of the savings of a West-wide RTO, if it encompassed the entire U.S. portion of the Western Interconnection.
Energy Strategies Principal Keegan Moyer said a full Western RTO would generate even greater benefits. His firm estimated the benefits at $2 billion a year in electricity costs in test-year 2030 in a study prepared for state energy offices in Colorado, Idaho, Montana and Utah. (See Study Shows RTO Could Save West $2B Yearly by 2030.)
“The EIM was an excellent first step, and the $3 billion number is impressive,” Moyer said. “But every data point that we’ve seen from our work and others is that there’s still a lot of opportunity out there, which is why you see so much effort, I think, put into this by the industry.”
CAISO’s Western Energy Imbalance Service is expected to encompass nearly 80% of load in the Western Interconnection by next year. | CAISO
CAISO has scheduled a stakeholder meeting for Dec. 7 to discuss its final EDAM design and plans to seek approval from its board and the WEIM Governing Body in February.
Eric Blank, chair of the Colorado Public Utilities Commission, said a study performed by his commission found increased regional coordination could save the state’s electric utilities up to $300 million a year, or about 5% of their costs. State law requires Colorado transmission owners to join an RTO by 2030.
“These benefits were roughly the same whether we went west to CAISO, east to SPP or did something [in between],” the hypothetical study results showed, Blank said.
CAISO’s one-state governance is a potential roadblock to expanding it into a Western RTO unless state lawmakers broaden its governance structure. SPP would maintain its inclusive governance structure in the West, Carrie Simpson, the RTO’s director of Western services development, said in the workshop.
The expectation is that participants in SPP’s existing Western Energy Imbalance Service will eventually join Markets+ and that many Markets+ participants will become members of SPP’s planned RTO West, she said.
One diagram in her presentation showed a larger RTO West and Markets+ transacting business with CAISO and WEIM. Another used a map showing SPP and WPP dominating the Western landscape, with CAISO relatively isolated. (A comparable CAISO map would show the WEIM covering much of the Western Interconnection.)
Seams between RTOs and ISOs are common in the Eastern Interconnection and would work in the West, including between CAISO and SPP, Simpson said.
“You can have many markets next to each other, optimizing efficiently through seams. We have it in the East. It’s very common. MISO, PJM and SPP coordinate regularly together,” Simpson said. “And so, to the extent that we have seams [in the West], absolutely we will want to work with all of our neighbors to make sure we’re optimizing systems as efficiently as possible to bring the greatest benefits to customers.”
Whether California will again seek to form a Western RTO to compete with SPP remains doubtful.
CAISO’s ACR 188 report, performed by the National Renewable Energy Laboratories, is being conducted in partnership with Western entities such as NV Energy, PacifiCorp and the Western Area Power Administration. A draft is expected later this month, and CAISO hopes to deliver the report to the Legislature during the first weeks of its 2022 session, which begins Jan. 3.
New Jersey is seeking projects totaling 1.2 to 4 GW — and potentially larger — in the state’s third offshore wind project solicitation planned for early 2023, according to a draft document released by the New Jersey Board of Public Utilities (BPU) on Thursday.
The Solicitation Guidance Document seeks proposals that are significantly larger than in the first two solicitations, which awarded projects totaling 1.1 GW and 2.658 GW, and expands the state’s already aggressive effort to become a key player in the growing offshore wind sector. The document presents a new solicitation schedule shaped to accommodate Gov. Phil Murphy’s decision in September to increase the state’s OSW target capacity from 7.5 GW by 2035 to 11 GW by 2040.
“The board seeks to promote robust competition in this third solicitation and future solicitations to support the continued development of the offshore wind industry in New Jersey,” the draft says.
The new schedule envisions four more solicitations after the third one next year, with each additional solicitation expected to award capacity of about 1.2 GW, though the BPU “may award projects above or below the target.”
The first project is expected to come online in the 2024-2025 period, with the final project up and running by 2038. The draft says that for the 2023 solicitation, the BPU “reserves the right to select less than 1,200 MW or more than 4,000 MW of qualified projects if circumstances warrant.”
The BPU will seek stakeholder input on the draft solicitation at a public hearing on Dec. 13.
Building an Industry
The requirements set out in the draft solicitation for project applicants show that New Jersey is looking to build upon the state’s OSW infrastructure already in development.
New Jersey awarded its first offshore wind project, the 1.1-GW Ocean Wind 1 developed by Denmark-based Ørsted, in 2019, and in 2021 awarded two more: the 1.148-GW Ocean Wind 2, and the 1.51-GW Atlantic Shores project, developed by a joint venture between EDF Renewables North America and Shell New Energies US. (See NJ Awards Two Offshore Wind Projects.)
The state has accompanied the project awards with an effort to position itself to serve other parts of the East Coast offshore wind sector by developing a logistics, marshalling and manufacturing hub. The heart of the effort is the development of what New Jersey officials say is the first custom-built wind port in the nation, committing $478.2 million to the project with bonding for another $160 million underway.
The wind port, located at Alloways Creek in Salem County, will include a 30-acre marshalling area for component assembly and staging; a dedicated, overland, heavy-haul transportation corridor; and a heavy-lift wharf with a dedicated delivery berth and an installation berth that can accommodate jack-up vessels. (See NJ Wind Port Draws Heavy Hitters.)
The BPU on Oct. 26 approved the expenditure of $1.07 billion for transmission upgrades to deliver 6,400 MW of OSW generation to the grid. The BPU picked the projects — the largest of which is an onshore substation known as Larrabee Tri-Collector Solution — from among 80 proposals submitted by 13 developers in response to a solicitation issued by PJM under FERC Order 1000’s State Agreement Approach. (See related story, FERC Approves PJM Tariff Revisions for SAA Cost Allocation.) However, the BPU largely awarded contracts for onshore work and left the offshore infrastructure mostly unallocated.
The draft solicitation seeks to fill that gap by requiring applicants to outline a “prebuild infrastructure” that would interconnect with the recently approved onshore infrastructure. Applicants would have to provide plans to build duct banks and access cable vaults for transmission to run to onshore interconnection points.
“Developers of future qualified projects would then install their cables through the prebuilt duct banks utilizing the prebuilt cable vaults, with minimal further disruption to the communities” around the interconnection points, the solicitation says.
Diagram of qualified project connections to point of interconnection (POI) with and without prebuild | NJ BPU
Economic Impact
The solicitation also seeks to generate a range of project alternatives, requiring applicants to submit at least one 1.2-GW project while adding that they are “highly encouraged to submit applications covering a range of project sizes up to approximately 4,000 MW.”
Applicants would have to submit a package with a completed application form and an explanation of their project, as well as an in-depth analysis of its economic impact on the state. They would have to detail the “proposed investment in New Jersey offshore wind infrastructure, supply chain, labor force development” and other investments. They would also have to outline the economic development impact on communities in the state and provide detailed job creation information, including location, types and number of jobs it would generate, and wage or salary levels.
The proposal must also say whether the planned project will use the New Jersey Wind Port or “alternative infrastructure” located in the state or elsewhere.
“The BPU encourages use of the New Jersey Wind Port for project marshalling and for locating Tier 1 manufacturing facilities, where feasible,” the solicitation says.
The heart of the application, however, is the cost of the project and its underlying economics. Applicants must set out the level of the OSW renewable energy certificate (OREC) at which the developer believes the project would be commercially viable.
“OREC pricing will be on a pay-for-performance basis,” the solicitation said. “Payments will be made on a dollar-per-megawatt-hour basis.”
The OREC must reflect the total capital and operating costs for the project over 20 years, “including costs of equipment, construction, financing, operations and maintenance, and taxes,” offset by any state or federal grants or subsidies, according to the draft solicitation. “The OREC pricing proposal shall specify the nameplate capacity, expected energy output and assumed capacity factor for the proposed project, along with the number of ORECs that the project will produce.”
