Search
`
October 5, 2024

Posted on

Heat Wave to Test Western Grid this Weekend

Forecasters say a Western heat wave like the one that pushed CAISO’s grid to the breaking point over Labor Day weekend 2020 will hit California and the Desert Southwest this weekend, with temperatures that could set records in inland areas of Northern California.

The extreme heat promises to be the latest in a series of weather anomalies that have tested power systems from Texas to Washington state in the past two years.

“An extended period of dangerously hot conditions with record temperatures up to 115 [degrees F]” will threaten residents of inland areas of Northern California over the holiday weekend, with the highest temperatures anticipated on Sunday and Monday, the National Weather Service (NWS) said in a heat advisory.

Inland areas of Southern California, including downtown Los Angeles, could see highs up to 105 degrees on Sunday and Monday, with “abnormally warm overnight lows” that could cause millions of residents to run their air conditioners long after the region’s supply of solar ramps down in the evenings.

The NWS predicts highs of 112 degrees in Sacramento, 111 degrees in Las Vegas, 109 degrees in Phoenix and temperatures pushing into the 90s in areas of the Pacific Northwest (although not in major population centers such as Portland and Seattle), potentially limiting CAISO’s ability to import electricity from neighboring states.

Any interruptions to transmission or generation, which wildfires have caused the past two summers, could exacerbate the situation.

CAISO Responding

West-wide heat waves and supply constraints struck the Western grid in August and September 2020, causing CAISO to order rolling blackouts in mid-August of that year and to declare energy emergencies over Labor Day. The August blackouts affected more than 2 million residents for periods ranging from roughly 30 minutes to 3 hours.

Since then, CAISO has interconnected several thousand megawatts of lithium-ion batteries to its grid, almost all with 4-hour discharge capacities. The batteries are intended to make up for shortfalls during hot summer evenings and have performed according to expectations so far. How the batteries will perform in more extreme conditions could be tested this weekend.

California’s summer has been relatively mild this year with the exception of a less-severe heat wave in mid-August, when CAISO issued a “flex alert” asking customers to reduce usage.

In preparation for the upcoming heat wave, the ISO said it is carefully watching the situation on Sunday and Monday when it expects peak loads of around 48,000 MW.

“We are taking measures to bring on all available resources and considering potential load relief actions, including flex alerts,” CAISO said in an emailed statement. The alerts will ask customers to set thermostats at 78 degrees from 4-9 p.m., to avoid using large appliances and to turn out unnecessary lights.

“Flex alerts have been an effective way to lower electricity use and help the grid through the most stressed time,” it said.

The ISO has also called for restricted maintenance operations from Wednesday through Tuesday.

“Market participants are cautioned to avoid scheduled maintenance to ensure all available generation and transmission lines are in service,” it said.

In a video posted to YouTube Tuesday, CAISO CEO Elliot Mainzer said, “With extreme heat forecast across California and the West over the next week through the Labor Day holiday, we need the public’s help to keep the power flowing without interruption. The ISO will use all available resources and tools to meet the heightened demand for electricity during this regional heat wave, but intense weather events like these call on all of us to do our part.”

Weather Anomalies

Record temperatures this weekend would continue an unpredictable series of extreme weather events, which many attribute to climate change.

February 2021’s winter storm nearly collapsed ERCOT’s grid amid widespread blackouts ordered by the Texas grid operator and SPP. A heat dome over the normally mild Pacific Northwest in June 2021 pushed temperatures to 116 degrees in Portland, Ore., and 108 degrees in Seattle, with some inland areas hitting 118 degrees. (See Avista Orders Blackouts as Temperatures Soar.)

In July of last year, a massive wildfire in southern Oregon severely derated the Pacific AC and DC interties during a Western heat wave, shutting off essential summer power from hydroelectric dams in Washington and Oregon to California.

Mainzer said in a recent interview with RTO Insider that extreme weather events are affecting load planning.

“How different weather patterns may behave in different parts of the West and what it means for our energy infrastructure is an issue that’s becoming front and center,” Mainzer said. “The basic physics of greenhouse gasses, where you’re trapping more heat in the atmosphere, means greater extremes.”

In an Aug. 19 webinar, two Stanford University students who performed summer fellowships with the Western Interstate Energy Board (WIEB), presented their findings on extreme weather and the grid.

Temperatures across the region have generally increased by about 1 degree F since 1995, researchers Jake Hofgard and Evan Savage said in the WIEB webinar. “However, this … smooths over the extreme temperatures which have the most impact on the grid,” Savage said.

All regions in the West saw an increase in extreme temperatures during heat waves, particularly the Pacific Northwest, California, Nevada, Arizona and Colorado, they said.

Their research focused on weather anomalies because “identifying extreme weather events and their impact on the grid is going to be particularly useful for regulators that want to prevent outages, especially in summer months,” Hofgard said. The researchers concluded that “extreme weather anomalies are becoming more common across the entire West, with a particularly significant increase in the Pacific Northwest.”

Their forward-looking analysis showed Phoenix could eventually see temperatures of 125 degrees in a 1-in-100 weather event, with Albuquerque and Salt Lake City also experiencing abnormally high temperatures.

Grid planners need to better incorporate weather anomalies into their load forecasts and to increase reserve margins, while making those margins more dynamic in response to weather variations, they said.

“We found that assuming historical weather patterns for long-term forecasting is no longer reliable,” Savage said. “As extremes become more prominent, [it] could expose utilities to risk. And similarly, long-term energy load forecasts should also include climate modeling in order to capture the increase in extreme temperatures that we may see in the future and [the corresponding] increase in air conditioning load growth.”

Posted on

ERO Supports FERC’s Extreme Weather Standards Proposal

In a joint filing to FERC last week, NERC and the regional entities gave their support to the commission’s proposal to modify NERC’s reliability standards in response to the ongoing impacts of climate change (RM22-10).

The comments of the ERO Enterprise came in response to FERC’s Notice of Proposed Rulemaking, issued in June, to direct NERC to update reliability standard TPL-001-5.1 (Transmission system planning performance requirements) to set expectations for long-term extreme weather planning by utilities. (See FERC Approves Extreme Weather Assessment NOPRs.) The standard is set to take effect next July, replacing current standard TPL-001-4. FERC’s proposed changes would require responsible entities to:

  • develop benchmark planning cases based on historical extreme heat and cold weather events and future meteorological projections;
  • use steady-state and transient stability analyses, covering a range of factors such as the grid’s changing resource mix and its performance during extreme weather, to plan for future extreme events; and
  • create a corrective action plan (CAP) to mitigate any occasions where performance requirements for severe weather have not been met.

The commission also sought comment on whether standard MOD-032-1 (Data for power system modeling and analysis) should be revised to address climate change concerns, and whether drought, tornadoes or other extreme weather conditions should fall within the scope of the final rule.

TPL-001

In their comments, NERC and the REs agreed that TPL-001-5.1 is unsuited to “the risks posed by extreme heat and cold weather conditions” and called for the standard to be revised or augmented with a new standard focused on transmission planning. The ERO noted that the rising incidence of severe weather and the ongoing transition to renewable resources, both of which are directly connected to climate change, are moving forward at a rate that NERC’s standards development process has been unable to match, despite its best efforts.

“Understanding and addressing the reliability risks posed by these extreme hot and cold conditions has been a high priority of the ERO Enterprise,” the entities said in the filing, citing NERC and FERC’s joint report on last year’s winter storms, NERC’s cold weather standards project (Project 2021-07) and other weather-related work by the ERO. “The ERO Enterprise supports the commission’s attention to the role [that] reliability standards for long-term transmission planning can play in helping to address the risks posed by extreme heat and cold conditions.”

Regarding the proposed changes to TPL-001-5.1, the ERO reminded FERC that it originally suggested updating the standard during a technical conference the commission held last year — the same conference that FERC cited when it issued the NOPR in June. (See FERC Tackles Grid Planning for an Unpredictable Climate.)

Both TPL-001-4 and its planned successor “require transmission planners and planning coordinators to evaluate … wide-area events affecting the transmission system,” including severe weather, but do not require the creation of CAPs — which NERC said was “appropriate at the time” the standards were approved. However, the ERO believes these requirements are no longer sufficient for the challenges currently facing the grid, and that “there is opportunity to improve the … standard to better account for the … impacts of extreme heat and cold … and to require entities to take corrective actions [in response to] system performance issues.”

Flexibility for the ERO

While NERC and the REs endorsed FERC’s desire to revise the transmission planning standards, they did have some suggestions regarding the implementation process. In particular, the ERO asked the commission for as much flexibility as possible to “best address the considerations discussed in the NOPR.”

First, the ERO noted that “significant work would be required to develop the necessary technical foundation for a uniform planning approach [accounting] for regional differences in climate and weather patterns” that could affect how entities implement the new standard. With this in mind, it asked that FERC’s final order not limit it to the example benchmark-based development approaches listed in the NOPR.

NERC and the REs also reminded FERC that the impact of climate change does not only involve sudden crises like last year’s winter storms, but also long-term environmental conditions that can severely affect the grid over sustained periods. As a result, the ERO urged that any studies mandated by the new standard should also take these phenomena into consideration.

In regard to other extreme weather conditions, the ERO said these should be included in future versions of TPL-001, though again with consideration to the climate conditions experienced by different regions. For example, in the Western U.S., drought and wildfire risks constitute a major threat from the changing climate, while in other areas hurricanes, flooding and icing may be larger concerns.

Finally, NERC noted that MOD-032-1 already allows planning coordinators and transmission planners to request “other information … necessary for modeling purposes” from entities, including data related to extreme heat and cold conditions.“To the extent NERC’s stakeholders identify that specific revisions would be beneficial for reliability, those revisions could be included in the scope of a TPL-001 revision project; however, the commission does not need to direct revisions to reliability standard MOD-032-1 to account for any new extreme heat and cold study requirements at this time,” the ERO said.

Posted on

5th Circuit Finds in Favor of NextEra’s ROFR Appeal

A federal appeals court on Tuesday ruled that Texas’ right-of-first-refusal law violates the U.S. Constitution’s dormant Commerce Clause, giving NextEra Energy (NYSE:NEE) a glimmer of hope in its bid to build two transmission projects in the state’s non-ERCOT footprint.

The 5th U.S. Circuit Court of Appeals found that NextEra’s challenge of the 2019 law (Senate Bill 1938), applied to interstate markets and not ERCOT, should proceed beyond the lawsuit’s pleading stage. It remanded the case back to the U.S. District Court for Western Texas (20-50160). (See NextEra Appeals Court Decision on Texas ROFR Law.)

The 5th Circuit agreed with NextEra that legal precedent did not shield SB 1938 from dormant Commerce Clause. The holding of the “dormant” clause is that implicit in the Constitution’s grant to Congress of power over interstate commerce is a prohibition against states passing legislation that discriminates against such commerce, such as laws meant to protect a state’s own economy.

NextEra Energy Capital Holdings and four other NextEra transmission owner/developer entities said in their appeal that the Texas law violated the clause because it only allowed the incumbent state owners of a transmission line’s end points to build, own and operate new lines.

In rejecting NextEra’s claim in February 2020, the district court said the legislation didn’t discriminate against interstate commerce because it “regulates only the construction and operation of transmission lines and facilities within Texas.” (See District Court Dismisses Texas ROFR Repeal.)

“That is wrong for the areas of Texas that are part of interstate electricity networks,” the 5th Circuit said, pointing to SPP’s and MISO’s East Texas footprints and SPP’s service territory in the Texas Panhandle.

“SPP and MISO territory … is part of an ‘interconnected “grid” of near-nationwide scope’ that has long been subject to FERC oversight,” the court said. It noted that the commission abolished ROFR provisions in its FERC-sanctioned rate agreements with its jurisdictional RTOs and ISOs. The commission “reasoned that federal rights of first refusal might ‘be leading to rates … that are unjust and unreasonable,’ in large part because ‘it is not in the economic self-interest of incumbent[s] to permit new entrants to develop transmission facilities,’ even if those facilities ‘would result in a more efficient or cost-effective solution.’”

The court also said that the Supreme Court, in finding dormant Commerce Clause violations, does not mention in which states companies are incorporated and the fact that most of Texas’ in-state transmission incumbents are incorporated outside the state does not save SB 1938.

“A law can discriminate against interstate commerce even though most of the incumbent transmission line providers that benefit from SB 1938 are incorporated or headquartered outside Texas,” the court said. “What matters instead is that the Texas law prevents those without a presence in the state from ever entering the portions of the interstate transmission market that cross into Texas. A law that ‘discriminates among affected business entities according to the extent of their contacts with the local economy’ may violate the Commerce Clause.”

The ruling may not be enough to save NextEra Energy Transmission (NEET) Midwest’s winning competitive bid for a $130 million, 500-kV project in East Texas. The Hartburg-Sabine Junction project was awarded in 2018, but MISO said in July that planned capacity in the region had negated much of the line’s economic benefits. (See MISO on Verge of Cancelling Hartburg-Sabine Tx Project.)

NEET Southwest also applied to the Texas Public Utility Commission in 2018 to transfer ownership of 30 miles of 138-kV facilities from Rayburn Country Electric Cooperative in SPP’s East Texas footprint. That application was withdrawn in 2020 after SB 1938 became law (48071).

The appeals court said any claims related to Hartburg-Sabine Junction seem premature because NextEra never applied for a certificate of public convenience and necessity. It also said it would allow the district court to determine whether NextEra is entitled to any preliminary injunctive relief by suspending the ROFR while the case is pending.

It would then be up to NextEra to seek a permanent order eliminating the ROFR. NextEra did not respond to a request for comment by press time.

The 5th Circuit’s ruling lists all five Texas PUC commissioners as defendants and appellees, though none of them held their seats when NextEra filed its appeal. A PUC spokesperson said staff are reviewing the decision with its attorneys.

“The commissioners justify SB 1938’s incumbency requirement as a law that promotes the safety and reliability of the electricity grid by ensuring that only those with a track record of building transmission lines in Texas can build new lines,” the 5th Circuit said. “That may end up justifying the discrimination against out of-state interests, but it does not avoid the conclusion that the law discriminates. Limiting competition based on the existence or extent of a business’s local foothold is the protectionism that the Commerce Clause guards against.”

Circuit Judge Jennifer Walker Elrod concurred with much of the majority’s opinion, noting the decision applies only “to the interstate electricity networks in Texas (but not the intrastate ERCOT network)” controlled by MISO and SPP. However, she dissented from the conclusion that SB 1938 “discriminates on its face” against interstate commerce.

“The distinction between incumbents and non-incumbents in SB 1938’s text, without more, does not constitute facially discriminatory treatment of out-of-state entities,” Elrod wrote. “That something more would have to be evidence of discriminatory purpose or discriminatory effect. And as the majority stated, the ‘pleadings-stage dismissal of [the discriminatory-purpose and discriminatory-effect] claims was premature. Claims that turn on intent and effects typically require factual development.

“On remand, I have no doubt that the able district court will carefully analyze these thorny issues,” she concluded.

Posted on

Oregon Moving Quickly to Adopt Advanced Clean Cars II Rules

Oregon regulators are racing to adopt by the end of the year a California rule requiring all new cars sold in the state to be zero-emission or plug-in hybrid by 2035.

Adoption this year would mean that the rule, known as Advanced Clean Cars II, would take effect starting with vehicle model year 2026. The regulation would require car manufacturers to provide an increasing percentage of ZEVs for sale each year, beginning with 35% in 2026.

The California Air Resources Board voted to adopt the regulation last week. (See Calif. Adopts Rule Banning Gas-powered Car Sales in 2035.)

In Oregon, the Department of Environmental Quality held its first meeting of the Advanced Clean Cars II Rule Advisory Committee on Tuesday. Rachel Sakata, a senior air quality planner at DEQ, said the agency expects to release the rule for formal public comment in September.

The proposal would then go to the Environmental Quality Commission for potential adoption in December, Sakata told the committee.

Oregon is one of 17 states that have adopted California’s current Advanced Clean Cars regulation, which covers new vehicles through model year 2025. Under the Clean Air Act, states may choose to follow federal vehicle emission standards or adopt regulations that are essentially the same as those of California.

There’s a rush to adopt the new Advanced Clean Cars II by the end of this year because of a two-year waiting period that’s required before the regulation can take effect. Model year 2026 vehicles will be released starting in 2025, Sakata noted.

Infrastructure Concerns

Committee member Greg Remensperger, executive vice president of the Oregon Auto Dealers Association, said dealers support the transition to electric vehicles, although some have concerns about how quickly they’ll face the 100% sales requirement.

Remensperger said he will recommend a mid-term review of ACC II to see if the pieces needed for the program’s success are falling into place.

“[If] we implement the rules as stated and the availability isn’t there or the cost is too expensive or the infrastructure is not there to support it, it’s just going to drive consumers to leave the state to buy … the ICE vehicle and bring it back into Oregon,” Remensperger said.

Not everyone at the meeting was on board with the proposed ACC II regulation. Oregon Rep. David Brock Smith (R) said the proposal is “not well thought out” when it comes to factors such as having sufficient transmission and capacity.

“That is why it’s the legislature that should be directing these policies and not rulemaking through agencies,” said Smith, adding that he will propose legislation to “unwind” the rulemaking work.

Jumping to 35%

The current Advanced Clean Cars regulation, which Oregon has adopted, also includes a ZEV sales requirement that increases each year, topping off at 22% for model year 2025.

However, ZEV credits are calculated differently in the current regulation as compared to ACC II. In the existing system, credits are based on factors, including the electric range of a vehicle, with some ZEV models receiving multiple credits per vehicle.

ACC II will use ZEV “values” rather than credits. One zero-emission vehicle will equal one value.

Despite the differences, Sakata acknowledged it will be a “jump” for car manufacturers to meet the 35% ZEV requirement in 2026. But automakers will have a variety of tools to help close the gap, she said. Those include the ability to carry over credits earned under the current Advanced Clean Cars rules, an early credit system and a system for transferring credits between ACC II states.

And under ACC II, manufacturers can meet up to 20% of their ZEV requirement with plug-in hybrid vehicles.

In addition, manufacturers can take advantage of voluntary environmental justice credits, which will be awarded for actions such as providing low-priced ZEVs for sale in model years 2026 through 2028. The ZEVs or PHEVs must have an MSRP of $20,275 or less for passenger cars and $26,670 or less for light-duty trucks.

States adopting California’s ACC II rule will have some flexibility in implementing environmental justice credits. That’s a topic on which the advisory committee will provide input.

Moving Forward in 2022

Oregon is one of four states, along with Washington, Vermont and Massachusetts, that have said they intend to adopt ACC II by the end of this year, according to a blog post from the Natural Resources Defense Council. Several other states may follow suit in 2023.

For example, Nevada published an initial draft regulation on June 30 as a first step toward adoption of ACC II. The Nevada Division of Environmental Protection plans to analyze potential costs and benefits of the regulation and receive public comment before bringing it to the State Environmental Commission for possible adoption next year.

NDEP expects to release more details on the process in coming weeks, the agency told NetZero Insider.

In Oregon, the Advanced Clean Cars II Rule Advisory Committee will hold a second meeting on Sept. 20 to review statements of fiscal, economic and racial equity impacts of the rule.

Informal comments may be submitted to the committee until Sept. 7 at noon. More information on the ACC II rulemaking is here.

Posted on

Granholm Says DOE Keeping an Eye on Winter Fuels

The federal government is standing ready to help New England with fuel supply and grid reliability this winter, Energy Secretary Jennifer Granholm told the region’s governors in a recent letter.

Granholm’s letter came in response to the states’ request for help, in which they asked the Biden administration to consider a waiver of the Jones Act for LNG deliveries, proposed a new energy reserve system for the region and asked for coordination ahead of what could be a difficult winter. (See New England Governors Ask Feds for Help with Winter Reliability.)

At the Department of Energy “and across the Biden administration, we recognize that the New England states face unique energy challenges, and your letter raises important areas for continued coordination and new collaboration with the administration,” Granholm wrote.

She said DOE is monitoring prices and inventory levels of natural gas, gasoline and distillates, and that she has been meeting with domestic producers and refiners to talk about their inventories and preparedness for storms.

On the East Coast, inventories are 20% below the seasonal five-year average for gasoline and 47% below the seasonal five-year average for distillates. In New England, diesel inventories are 63% below their five-year average.

“These data points raise concerns about the impact of any physical disruption of supply and require that both states and the federal government are prepared to use all the tools in our toolkit to improve preparedness and respond if needed,” Granholm wrote.

But while she offered general assurances that the federal government is on the case, she didn’t directly agree to any of the governors’ specific asks.

Granholm noted that requests to waive the Jones Act, which requires that ships hauling cargo between U.S. ports be built in the U.S., are handled by the Department of Homeland Security, and that the department would “expeditiously consider” individual waiver requests that come in. The governors had asked for a broader suspension of the Jones Act for winter LNG deliveries.

She also said that DOE “welcomes” the thoughts of governors on modernizing strategic energy reserves but gave no indication that her department is working on the subject itself.

She did say, however, that DOE and the states should “consider if a minimum fuel stock holding requirement for liquid fuels is a necessity moving forward.”

FERC is leading a meeting in Vermont next week to discuss winter reliability issues in New England. (See ISO-NE: Reliability Still Depends on Mass. LNG Import Terminal.)

Posted on

SPP’s Markets+ Offering Attracts 6 More Western Entities

SPP said Monday that six more Pacific Northwest entities are interested in participating in the next phase of the grid operator’s energy market services in the Western Interconnection.

The six organizations — Avista, Chelan County Public Utility District (Wash.), Grant County Public Utility District (Wash.), Puget Sound Energy, Tacoma Power and Canadian marketer Powerex — made their intentions public in an Aug. 19 letter to SPP, saying they intend to work with the RTO to develop a Western market that “supports reliability and delivers value to our customers.”

They join Bonneville Power Administration in formally committing to funding the further development of Markets+, a conceptual bundle of services that would centralize day-ahead and real-time unit commitment and dispatch and provide hurdle-free transmission service. Markets+ has been framed as a voluntary, incremental opportunity to realize market benefits by utilities that aren’t ready to pursue full RTO membership. (See BPA Commits to Funding Markets+ Development.)

SPP said the seven entities willing to move forward with the development of Markets+ represent a “well connected footprint with extensive transmission capability, a large fleet of clean flexible hydro resources and a peak load” of over 30 GW. That is 50% larger than ISO-NE, the nation’s smallest grid operator, it said.

“We are very encouraged by the governance and market design progress for Markets+ over the past several months, which has been achieved through SPP’s collaborative, stakeholder-driven approach,” Powerex CEO Tom Bechard said in a statement.

Powerex Managing Director Mark Holman has been one of the most vocal and inquisitive participants in SPP’s Markets+ development sessions, which began late last year. The grid operator has held three in-person meetings with Western stakeholders to review work on the market’s service offering and discuss outstanding items and next steps. (See SPP Continues to Build on Markets+ Offering.)

“By participating in this process, we are working together to build Markets+ on a strong foundation of input from Western stakeholders, ensuring the market meets the needs of the West and brings value to all participants,” SPP CEO Barbara Sugg said.

A draft service offering that explains how the proposed service will address governance structure, market design, transmission availability and other items will be distributed Sept. 30, setting off a public comment period. The final service offering will be distributed Nov. 18. Interested parties will make a commitment to fund further market development in early 2023.

Posted on

MISO Gathering Stakeholder Input on LRTP Cost Allocation

MISO is collecting stakeholder suggestions on the design elements that should be included in a new cost allocation for some of the long-range transmission planning (LRTP) projects.

Milica Geissler, the RTO’s cost-allocation specialist, said Tuesday the goal is to create by the end of 2023 a methodology to allocate costs for the third and fourth LRTP portfolios. She said the design could be used footprint-wide or exclusively for MISO South.

During a meeting of MISO’s cost-allocation stakeholder group, Geissler said staff is looking to balance “granularity, feasibility and consistency” in the cost-sharing design.

“The most accurate reading for some benefits may be at the MISO footprint or sub-regional-level,” she said, advising against stakeholders expecting cost-benefit calculations at the transmission pricing-zone level.

MISO is using a 100% postage stamp rate for the first two LRTP project cycles, with those costs confined to MISO Midwest. (See FERC OKs MISO’s Bifurcated Cost-allocation Tx Design.) When planners begin looking for long-range projects in MISO South, the grid operator plans to use a more specific cost-allocation design. (See MISO Seeking New Tx Cost Allocation for Major Buildout.)

Some stakeholders have voiced concerns of disparate treatment between LRTP portfolios, saying a different cost allocation for MISO South projects will violate FERC’s principle that inconsistent allocations must not be applied to the same class of projects.

At any rate, the new cost allocation might contain cost assignments for interconnecting generation in addition to load.

Darcy Neigum, with Montana-Dakota Utilities Co., proposed that the RTO impose long-range transmission costs on interconnecting intermittent resources only. He said MISO could include a new intermittent generation MWh value in the denominator when calculating LRTP project rates.

Neigum said assigning a portion of long-range transmission costs to intermittent resources would “align cost-causers and beneficiaries.” He said states and utilities with carbon-reduction goals are driving the generation fleet change that necessitates the transmission in the first place.

“Not all states and loads are equal cost causers and beneficiaries,” he said.

Clean Grid Alliance’s Natalie McIntire raised concerns that only intermittent generators would bear the lines’ costs. She said thermal generation will benefit from long-range projects as well.

McIntire also argued that the LRTP’s primary purpose is to ensure grid reliability through the resource transition, and not to simply accommodate generator interconnections.

Sustainable FERC Project attorney Lauren Azar said Montana-Dakota Utilities’ proposal “gave her pause.”

“LRTP is not only responding to the challenges of changing grid … but extreme weather events as well. The fact of the matter is that resilience is a goal of LRTP, and everyone in MISO Midwest will benefit,” Azar said.

MISO stakeholders will next discuss LRTP cost allocation during an Oct. 18 meeting.

Posted on

NJ Eyes Rules to Protect, Gather Advanced Metering Data

New Jersey is studying how to set data-gathering rules to ensure that the growing implementation of advanced metering infrastructure (AMI) helps ratepayers cut energy use and support efforts to meet the state’s ambitious clean energy goals.

The state’s Board of Public Utilities (BPU) will hold a second hearing on Sept. 6 into its straw proposal intended to ensure that ratepayers and other stakeholders can get speedy, accurate data on which to make energy decisions while protecting the privacy of consumers and securing the system.

State officials believe AMI is an important element to implementing Gov. Phil Murphy’s Energy Master Plan, which sets a state goal of 100% clean energy by 2050. It calls AMI a “foundational component of a modernized electric distribution grid” and describes it as “a prerequisite of many additional clean energy objectives.”

AMI is the use of “smart” meters that can compile data on a ratepayer’s energy use and transmit it to the user or third party, often in real time. Analysis of the data can help the ratepayer adjust their energy use, facilitating changes such as shifting the time of day for completing tasks to when energy is cheaper, halting some practices or allowing the user to switch away from high energy-consuming appliances.

The first utility in the state to implement an AMI strategy, Rockland Electric Co., installed about 74,000 smart meters by 2019. The state expects its other three utilities to deploy more than 3.9 million smart meters over the next five years.

Benefits of AMI

The straw proposal, released a year ago, would create a standardized system of rules that govern how utilities handle issues such as data sharing, data access, data privacy and billing reconciliation. The state’s four utilities would each be required to file data access plans to implement the rules.

AMI “holds the potential to be an integral part of New Jersey’s clean energy transition, enhance retail competition and efficiencies, and enable customers to better understand and control their own energy usage,” the proposal says.

The straw proposal emphasizes that the data, although often collected by the utility, are owned by ratepayers, who should control who can access them and whether that should include third parties. The BPU’s plan recommends the use of the “Green Button Connect” system, a standardized, relatively user-friendly system through which ratepayers can access their own data through a green button on their utility company’s website. The proposal also would require utilities to follow standard cybersecurity measures to protect the data.

Metrics that should be collected, according to the proposal, include: total usage and demand in kilowatt-hours, the number of customers who access the data, and how many customers sign up for energy-saving tools, energy-usage information and saving tips.

Speakers told the first hearing on the proposal Aug. 16 that the speed at which data become available is important to ensuring their value and to keeping consumers focused on their energy usage.

“Energy data is a highly fungible commodity whose value is maximized when accessed and interpreted shortly after the energy consumption,” said Christopher Oprysk, an engineer at the BPU who presented parts of the proposal at the hearing. “Consumers are more likely to respond with behavior changes if the data reflects recent consumption patterns and more closely ties [it] to cause and effect.”

The proposal argues that “billable data,” which are collected by the utilities to calculate ratepayer bills, should be available within 48 hours and customers should be provided with an energy monitoring device that would make available unvalidated data within 15 seconds, which could be accessed through a home area network.

Murray Bevan, a lobbyist for several energy suppliers, including NRG Energy and Vistra, echoed the point, telling the BPU that rapid access to data is critical.

“If I run my dishwasher at 4 in the afternoon, or I run it at 10 at night, there’s like a 40% difference in the price of running it,” he said. “So if I really need the clean dishes for dinner at 6 or 7, OK, I’ll go ahead and run it. But if I can wait until 10, that’s a significant price win.”

“Getting the data as close to the real time usage as possible, is the most valuable,” he said. “If I’m making this decision on Monday, and I’ve learned about it, that I should have run the dishwasher at 10, on Tuesday or Wednesday, obviously that’s not as valuable to the customers.”

AMI Implementation Surge

The BPU in January gave approval to a plan by Public Service Electric and Gas to invest $700 million over the next four years to provide smart meters to its 2.3 million electricity customers. The company at the time said the move would “help expedite electric service restorations when severe weather strikes, help customers increase their home energy savings and improve service quality.”

In July 2021 the board approved a plan a plan by Atlantic City Electric to spend $177 million on installing 565,000 smart meters. And the state’s fourth utility, Jersey Central Power & Light, has a plan before the BPU to spend $360 million on AMI.

Yet the state’s adoption of AMI has lagged, even as other states have embraced the technology. There were 94.4 million advanced meters in operation as of 2019, the latest that figures are available, according to FERC’s annual Assessment of Demand Response and Advanced Metering report released in December. That accounted for 60.3% of the meters of all types operating in the country and was an increase of 8 million smart meters over the year before, the report said.

The Mid-Atlantic region had the second worst penetration in the nation, with only 37.4% of the meters being advanced, the report said. The worst was New England, with 22% penetration, while the highest penetration was in the West South Central Region, which includes Texas, and the Pacific region, both with about 74% penetration.

Yet even those areas in which AMI penetration is high, the technology may not be fully used, according to a study that Mission:data, a nonprofit advocacy organization that works to promote AMI usage, is set to release next week. More than a decade after the federal American Recovery and Reinvestment Act (ARRA) disbursed $3 billion for AMI projects, “most of the data-access benefits promised to customers have been deactivated,” the report says. Only about 2.9% of the 17.4 million advanced meters funded by the program are enabled, the report says.

Still, New Jersey’s slow uptake could end up helping the state, said Michael Murray, president of Mission:data. The state can learn from projects in other states where “customer benefits of smart meters have not materialized,” he said in an interview with NetZero Insider. And the state’s program could be bolstered by the recently enacted Inflation Reduction Act, which includes funds that can be used for AMI, he said.

While some consumer advocates are skeptical that the benefits from AMI are worth the investment, a dozen studies have shown that “6 to 18% energy savings are possible when consumers have easy, electronic access to their meter data,” he said. Aside from helping customers cut energy use, AMI data can help them buy the right size of appliance they need based on actual electricity use and can help with the purchase of energy-efficient equipment such as heat pumps.

Posted on

MISO Recommends Lower Distribution Factor to Address Congestion

To cut down on its surging congestion, MISO is suggesting a tighter limit on how much new generation can affect the surrounding grid without triggering more network upgrades.

The grid operator announced it is considering halving new generation’s allotted distribution factor impact on transmission from 20% to 10% for its basic level of interconnection service, called energy resource interconnection service (ERIS).

Some MISO members maintain that interconnecting generators are unacceptably raising congestion and a narrower distribution factor threshold would keep runaway congestion in check by flagging a need for more transmission upgrades.

MISO said a preliminary analysis showed that lowering the distribution factor for ERIS to 10% identified “several” new network upgrades in its annual interconnection queue cycles, “the majority being in the 69 to 161 kV voltage range.”

Interconnection customers can either elect to secure ERIS, or the higher-quality network resource interconnection service (NRIS), which ensures that the entire installed capacity of resources is deliverable. NRIS is generally more expensive than the unguaranteed ERIS.

MISO said ERIS elections from new generation “can lead to more congestion on the transmission system.” It said a lower distribution factor cutoff could result in fewer system reliability issues and have more interconnection customers sharing in network upgrade costs.

The RTO now faces billion-dollar congestion costs on a quarterly basis. MISO’s long-term transmission plan is set to assuage some of that congestion, but the first in-service dates of the 18 new lines are at least eight years out.

Meanwhile, the grid operator is again bracing for a historic level of interconnection requests in its 2022 queue cycle. During an Aug. 30 transmission cost allocation meeting, MISO’s interconnection team estimated the RTO will field about 700 new interconnection requests totaling about 100 GW in a few weeks.

MISO staff also said they’ve been receiving complaints from new generators that have interconnected but cannot get their output delivered on the system due to transmission congestion.

Some of MISO’s clean energy advocates have said lowering the distribution factor threshold seems punitive to renewable energy, which makes up the overwhelming majority of MISO’s interconnection queue.

At a mid-August Interconnection Process Working Group, Xcel Energy’s Randy Oye said increased expenses for new generation isn’t a valid argument against lowering the distribution factor threshold. He said if a project stands to affect lines by 20%, then the project’s business case might need to be reexamined.

“The load is going to pay $10 billion for transmission. I think a fair question is: what should generation pay?” he said, referring to the cost of MISO’s recently approved long-range transmission portfolio.

Stakeholders asked for some sort of MISO demonstration that lowering the distribution factor threshold will in fact reduce congestion. They also criticized MISO for concocting a policy change in secret before bringing a proposal to a stakeholder meeting.

MISO’s stakeholder community is again set to again debate a stricter distribution factor at an Oct. 10 Interconnection Process Working Group meeting.

Posted on

MISO Cancels Hartburg-Sabine Competitive Project

A MISO staff planning committee has determined that MISO South’s only competitive transmission project, the $130 million, 500-kV Hartburg-Sabine Junction project in East Texas, is no longer necessary.

The decision wasn’t surprising. MISO has been warning for months that its analysis indicated that the project was no longer helpful to the system. (See MISO on Verge of Cancelling Hartburg-Sabine Tx Project.)

The project’s cancellation comes as the 5th U.S. Circuit Court of Appeals Tuesday ruled that Texas’ right-of-first-refusal (ROFR) law violates the U.S. Constitution’s dormant Commerce Clause. (See 5th Circuit Finds in Favor of NextEra’s ROFR Appeal.)

Brian Pedersen, senior manager of competitive transmission administration, said the RTO is evaluating the opinion for possible impacts to Hartburg-Sabine. However, “the opinion and order does not change the planning analysis,” he told stakeholders Wednesday during a Planning Advisory Committee meeting.

Pedersen added that MISO isn’t planning to conduct any more economic or reliability analyses on the project. He said studies have already shown the project has “near-zero” production cost benefits and did not uncover any transmission system issues without the line.

The grid operator said the project’s benefits dissolved because of recent Entergy generation additions near the line’s route. The utility brought the 993-MW Montgomery County Power Station online in 2021, and it intends to construct the 1.2-GW natural gas- and hydrogen-powered Orange County Advanced Power Station by 2026.

MISO approved the market efficiency project as part of its 2017 Transmission Expansion Plan, based on expectations it would alleviate congestion, ease import limitations and allow access to lower cost generation for customers in the chronically congested West of the Atchafalaya Basin and western load pockets in Entergy’s MISO South footprint.

“It’s been a little over four and a half years since the project was approved,” Pedersen reminded stakeholders.

In 2018, MISO selected NextEra Energy Transmission Midwest’s bid for a new 23-mile, 500-kV transmission line, four short 230-kV lines and a new 500-kV substation. NextEra’s proposal beat 11 other competitors. (See NextEra Wins Bid to Build MISO’s 2nd Competitive Project.)

However, Texas later passed a law in 2019 giving incumbent utilities ROFRs for any projects built in the state. With NextEra unable to secure permitting for construction and the 2023 in-service date approaching, MISO this year initiated its variance analysis, a process used to reanalyze projects that experience material changes. Following the analysis, the RTO had two choices: cancel the project or reassign it to a new developer.

“MISO always has deference to states’ rights in these types of matters,” director Mark Johnson explained in 2019.

MISO’s bid selection report is now considered moot. The grid operator now plans to file with FERC in the fourth quarter to terminate its selected-developer agreement with NextEra.