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August 30, 2024

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PUC Shortlists 17 Projects for Loans from Texas Energy Fund

The Texas Public Utility Commission has selected 17 generation projects for further review as part of a $5 billion loan program intended to add dispatchable, or thermal, generation to the ERCOT grid.

During its Aug. 29 open meeting, the commission delegated authority to its executive director to enter into loan agreements with those applicants who can show “they’re worthy” after a due-diligence review. The projects, if completed, would add 9.78 GW of new dispatchable generation for $5.38 billion in state loans (56896).

The portfolio was culled from 72 applications under one of four Texas Energy Fund (TEF) programs approved last year by voters, the In-ERCOT Generation Loan Program. The applications sought more than $24 billion in low-interest funding for projects representing over 38 GW of dispatchable generation.

PUC staff and the TEF administrator assessed each of the applications based on applicants’ experience and financial strength, the proposed projects’ technical and financial attributes, and five commission priorities: diversity among applicant types, diversity in siting location, speed to market, ability to relieve transmission constraints and diversity of resource type.

“I’m happy with the recommendation. I think it’s an amazingly good job of weighing all the issues that the five commissioners brought to you throughout this process,” PUC Chair Thomas Gleeson told staff during the open meeting.

Should any projects fail the due-diligence review, staff could recommend additional applications for review. However, there is a March 2025 deadline to advance those projects for review. Initial disbursements for approved projects will be made before Dec. 31, 2025.

The list of 17 projects includes heavyweights like Calpine, Constellation Energy, NRG Energy and Vistra. It also includes local entities like Kerrville Public Utility Board and Rayburn Electric Cooperative. The projects range in size from 1,350 MW to 122 MW.

“We had 72 folks who were interested and wanted to, if you will, kind of get in the game,” Commissioner Jimmy Glotfelty said. “They put a lot of thought into it and hopefully … there’ll be an opportunity for more to come.”

“We are eager to see these projects break ground and are confident that the commission will proceed in such manner to ensure that the fund is used efficiently to deliver the reliable power,” Tony Bennett, CEO of the Texas Association of Manufacturers, said in a statement. “Texas needs to maintain its top spot as the best place to do business, grow jobs and strengthen communities.”

The TEF’s other programs include the completion bonus grants, outside ERCOT grants and the Texas backup power package. The fund was established in March because of state legislation that passed last year, with the February 2021 winter storm serving as the catalyst. The PUC says the program can support up to 10 GW of new or upgraded generation capacity in ERCOT. (See Texas PUC Establishes $5B Energy Fund.)

Stoic Energy principal and ERCOT observer Doug Lewin said in his weekly newsletter that 80% of the gas plants will be peakers and “will likely displace older, higher-polluting fossil fuel plants.”

“This was not unexpected, but it’s interesting to see that’s what actually happened,” he wrote, noting that gas availability was a “major problem” during the 2021 storm.

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Berkeley Lab Report Highlights Trends in Distributed Solar

Lawrence Berkeley National Laboratory has released the latest iteration of its “Tracking the Sun” report, which looks into the 3.7 million distributed solar systems installed through the end of 2023. 

The size and efficiency of installed residential solar systems has been growing over the past two decades, with the median size rising from 2.4 kW in 2000 to 7.4 kW in 2023, and the average efficiency from 12.7% in 2002 to 20.8% last year. 

“Increases in module efficiencies since 2010 closely track the rise in residential system sizes, suggesting that module efficiency gains have been a primary driver for growth in residential system sizing,” the report said. 

The roof-coverage ratio for residential systems has been relatively stable, ranging from 15 to 40%, with a median of 26% in 2023. Nonresidential rooftop systems have a lower median, but a much broader range. 

The report found that solar panels are increasingly being paired with storage systems over time, rising from nothing in the middle of the last decade to 12% of new residential systems in 2022 and 8% of new nonresidential. Hawaii has the highest storage attachment rate, at 95%, while new policies that went into effect in April 2023 in California have driven its rate to 14% — and most other states have attachment rates of 4 to 10%. 

The new net billing tariffs going into effect are driving more storage pairing in California, with the report noting 60% of systems paid under them are linked with storage. 

Third-party ownership for residential solar systems has been on the decline in general, falling from 60% in 2012 to 27% in 2023. There was a slight uptick in third-party ownership last year, which the report said could be from higher interest rates for solar loans. 

Residential systems are overwhelmingly deployed on single-family homes, but the nonresidential sector sees much more variety in customer type, with half on commercial businesses, one-third on agricultural sites and 15% on tax-exempt customers (government, schools, churches, etc.). 

Berkeley developed inflation-adjusted prices for standalone residential customers, which fell by 10 cents/W in 2023 — the same rate of price decline for the last decade. Median prices for nonresidential systems actually went up by 10 to 20 cents/W, which the report blamed on inflation. 

Between 2021 and 2023, nominal installed prices were up 2 to 3 cents/kW across customer segments, but when controlled for inflation, they were down 50 cents/W for residential systems and 10 cents/W for others. 

“The fact that real prices fell suggests that PV pricing has thus far been less impacted by inflation compared to other consumer goods (as measured by the CPI), though the effects on installed prices for large nonresidential systems may have not yet entirely materialized,” the report said. 

Prices vary depending on a range of factors, from system size to state policy. The report said that residential prices vary by about $1/W between the largest and smallest systems, while commercial generation varies $2.20/W between sizes. 

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3rd ‘Issue Alert’ Compares Pricing Practices in Markets+, EDAM

Enhanced protections against uncompetitive market behavior are among several tools to ensure fair and accurate pricing under a Markets+ framework, according to an “issue alert” published Aug. 28 by 10 entities that back development of the market.

The alert is the third published in a series of seven notices intended to highlight Markets+’s purported advantages over CAISO’s Extended Day-Ahead Market (EDAM) and Western Energy Imbalance Market (WEIM). The first covered differences between how the two markets would be governed, while the second focused on reliability.

The contributing parties include Arizona Public Service, Chelan County Public Utility District (PUD), Grant County PUD, Powerex Corp., Public Service Co. of Colorado, Salt River Project, Snohomish PUD, Tacoma Power, Tri-State Generation and Transmission Association and Tucson Electric Power.

In their third alert, the backers argued that Markets+’s “conduct-and-impact” framework ensures that prices are fair and not distorted by the exercise of market power. The approach is also used in MISO, ISO-NE, NYISO and SPP’s RTO, according to the alert.

“Under this framework, a bid is mitigated if it materially exceeds an established reference level and that bid would have a material impact on market prices, absent mitigation,” the alert said. “This two-part assessment applies mitigation when needed to ensure market prices are not distorted by the exercise of market power, while providing market participants with flexibility to submit bids that reflect their own evaluation of their costs (including opportunity costs).”

Meanwhile, EDAM’s price controls are not as fine-tuned and kick in whenever there is a possibility of price manipulation without a thorough examination, according to the alert.

The Markets+ backers contended that EDAM’s approach risks leading to “more frequent, and overly-broad, mitigation to price levels that can be below a market participant’s actual costs. ”

The parties also argued that Markets+ supports reliability and market efficiency by adopting a graduated scarcity pricing method. Scarcity pricing encourages resources to be available during tight energy conditions and helps “ensure prices reflect actual system conditions during periods of tight supply and that customers receive the benefit of the most optimal market clearing solution,” according to the alert.

EDAM, on the other hand, does not have a scarcity pricing method designed for its full market footprint, the parties said. Instead, EDAM relies on CAISO’s existing pricing method designed to handle shortfalls of ancillary services within the CAISO balancing authority area, the alert stated.

“The effectiveness of this approach is frequently undermined by extensive manual interventions that commonly occur in the CAISO BAA during scarcity conditions, including deploying out-of-market supply and emergency demand response,” the parties said. “This behavior puts inaccurate downward pressure on market prices, producing pricing results that are inconsistent with actual system conditions and limiting shorter-term and longer-term market participation incentives.”

The alert also highlighted that Markets+ utilizes a so-called fast-start pricing approach, a mechanism that factors the cost of starting and operating gas-fired peaking units into the wholesale market price.

Of the six FERC-jurisdictional organized markets, only CAISO doesn’t use fast-start pricing, according to the alert. (See WEIM Expert Calls for Fast-start Pricing to Address ‘Anomalies’.)

“Failing to include fast-start pricing negatively impacts Northwest and Southwest ratepayers, and impedes long-term efficiency by discouraging investment in new flexible resources and storage that could displace the use of gas peaking units in the future,” the parties said.

The parties similarly targeted EDAM’s approach to virtual bidding, noting that it’s not automatically applied across the entire market but is an optional feature each BAA can adopt.

“This BAA-by-BAA approach introduces uncertainty for load-serving entities and other market participants on their ability to hedge real-time energy costs across the market footprint, potentially limiting the tools that can support market efficiency in EDAM,” the alert stated.

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Truckers Group Opposes Wash. Clean Trucks Timeline

Washington has adopted California’s Advanced Clean Trucks (ACT) program to govern the Evergreen State’s long-term transition to zero-emissions trucks, but a group representing truckers is arguing that the timeline for doing so is faster than is practical for the industry. 

Under ACT guidelines, 7% of medium- and heavy-duty trucks sold in Washington in 2025 must be zero-emission vehicles, increasing to 20% by 2028, 30% by 2030, 40% by 2032 and 55% by 2035. 

That schedule is too aggressive, according to the Washington Trucking Associations (WTA). 

“While ACT is meant to move industry toward zero emissions for medium and heavy-duty (M/HD) trucks, WTA members have concerns about vehicle costs, operational challenges and low to non-existent vehicle adoption,” wrote WTA President Sheri Call in an Aug. 15 letter to Gov. Jay Inslee.  

Washington does not have the regulatory infrastructure in place to discourage companies from using out-of-state outside trucks that do not comply with emissions-reduction standards, she wrote. 

“Artificially manipulating the market to mandate ZEV truck sales will have a profound impact on the industry and lead to unintended consequences,” Call wrote “California officials wrote, adopted and implemented the ACT program for the state of California. But Washington is not California.” 

California has been building support for decarbonization for decades, including funding incentive programs for clean commercial trucks. And its ramp-up of zero-emission sales is more gradual than the Washington schedule, she added. (See Groundbreaking California Clean Truck Rules Win EPA Waiver.) 

“A zero- emission truck costs about two and half times more and sacrifices about two and half tons of payload compared to a clean diesel truck today. Electric M/HD trucks also compromise range, while only providing about 150-200 miles per charge,” Call said in the letter. “Fueling infrastructure is also expensive and can take up to two years for permitting and installation. There is also the ongoing uncertainty of electric grid capacity as examples of officials asking vehicle owners to avoid charging cars during hot summer days continue to become more commonplace.” 

Call pointed also to the 12% federal excise tax on new trucks and trailers — “a policy the industry has long thought to inhibit adoption of newer, cleaner diesel trucks.” 

The ACT’s timeline is too aggressive and does not accommodate innovation or current technological limits, she wrote 

“WTA respectfully asks you and the Legislature to reconsider the link to California’s emission standards and adopt the federal standards that are more suitable to Washington’s unique needs. Washington employers should not have to face policies created by another state, with no input from stakeholders or analysis for its impact here,” Call wrote. 

In an email to NetZero Insider, Gov. Jay Inslee spokesperson Mike Faulk said the governor’s office is studying the issue.  

“These regulations were thoughtfully crafted to make compliance feasible. There are a variety of compliance options, including giving credit from previous years sales to meet the first target in 2025 and credit-sharing across weight classes allowing for manufacturers to ramp up availability,” Faulk wrote. 

“The state is committed to supporting the trucking industry in this transition,” Faulk continued, noting it has provided more than $130 million in funding from the Climate Commitment Act — the state’s cap-and-invest program — to help truck owners cover the costs of electric trucks and charging infrastructure. 

“We continue to work with California and Oregon to pursue federal funding to build an electric truck charging corridor along I-5. And we’ve secured over $60 million in state and federal funding to electrify drayage trucks operating in and around ports,” he wrote. 

California, Oregon and Washington recently secured $102 million in federal funding for the West Coast Truck Charging and Fueling Corridor project, a joint effort to a network of chargers between the borders with Canada and Mexico. (See West Coast Truck Charging Corridor Wins $102M in Federal Funds.) 

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BLM Issues Solar Roadmap for 11 Western States

The U.S. Bureau of Land Management on Aug. 29 released proposed guidelines for solar energy development on more than 31 million acres of public land in 11 Western states.

BLM’s original Western Solar Plan covers six Southwest states and dates to 2012. The proposed update reflects increased interest in solar development in five Northwest states and changes in photovoltaic technology during the intervening decade.

It steers solar development closer to transmission lines rated at 69 kV or larger; off slopes greater than 10%; onto previously disturbed lands; and away from protected lands, cultural resources and important wildlife habitats.

Project-specific analysis still would be required on every solar facility proposed.

The plan would not apply to projects that are smaller than 5 MW or not connected to the grid.

The proposal is scheduled to be published in the Federal Register on Aug. 30. Sixty days is allotted for protest and consistency review; any issues identified in that time will be resolved, then BLM will publish the record of decision.

BLM and the National Renewable Energy Laboratory calculated that 700,000 acres would be sufficient to meet the nation’s clean-energy goals.

The total planning area covers 162 million acres of public land in the 11 westernmost states. That was narrowed to about 22 million acres in the draft Western Solar Plan released in January 2024 but expanded to more than 31 million acres in the final proposal.

As of July 2024, BLM had permitted approximately 29 GW of clean-energy projects — 69 geothermal, 52 solar and 41 wind, plus 42 transmission connection lines on federal land.

At that time, it also was processing 62 applications for clean-energy projects in the Western states with a combined potential of 31 GW. It said hundreds more project applications were in preliminary review.

The proposal has drawn considerable attention and feedback — BLM said that after it published the draft in January it received more than 50,000 comments.

Some industry groups said Aug. 29 that BLM had drawn the maps too narrowly in the final proposal.

In a prepared statement, the Solar Energy Industries Association said it has long sought to level the playing field for energy development on public lands, and the solar plan does not do that:

“While we’re still reviewing the details, we’re pleased to see that BLM listened to much of the solar industry’s feedback and added 11 million acres to its original proposal. While this is a step in the right direction, fossil fuels have access to over 80 million acres of public land, 2.5 times the amount of public land available for solar.”

American Clean Power made a similar point and said it looks forward to working with BLM and stakeholders to reduce unnecessary regulatory hurdles:

“ACP appreciates the time BLM has dedicated to reviewing the permitting process for solar development and recognizes the flexibility added into the project design features and additional acres made available in the final plan. However, we remain concerned by the exclusion of some areas which could otherwise allow for development in ways compatible with resource protection.”

The Wilderness Society, however, praised the protective stance BLM took. It said:

“The BLM’s final Western Solar Plan harnesses this clean and abundant resource responsibly, focuses projects away from ecologically and culturally sensitive places, honors community input and realizes the imperative that our public lands must be part of the climate solution. We look forward to working with the administration, the solar industry, communities, Tribes, and other stakeholders to ensure individual projects live up to the strong standard that was set today.”

BLM Director Tracy Stone-Manning said the final plan is a good one:

“It will drive responsible solar development to locations with fewer potential conflicts while helping the nation transition to a clean energy economy, furthering the BLM’s mission to sustain the health, diversity and productivity of public lands for the use and enjoyment of present and future generations.”

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Late August Heat Wave Delivers 122-GW MISO Summer Peak

CARMEL, Ind. — MISO set its 122-GW summertime peak on the unofficial last week of summer, with widespread heat necessitating back-to-back maximum generation warnings.

MISO instituted two separate maximum generation warnings Aug. 26-27 for the Midwest region after issuing conservative operations and a capacity advisory beginning Aug. 25. Much of the footprint registered over 90 degrees on Aug. 26, with a blistering heatwave parked over the Midwest.

“MISO and our members reliably served the highest demand of the summer season due to the extreme heat across our North and Central Regions,” spokesperson Brandon Morris said in a statement to RTO Insider. “The declarations we issued allowed us to access the necessary resources to maintain reliability.”

MISO said the emergency warnings were due to culmination of the higher-than-normal temperatures, forced generation outages and limited transfer capabilities. As it dealt with the heat wave on Aug. 26, MISO sent reminders to market participants with external resources that their interchange schedules must match their capacity obligations to MISO.

The RTO realized a summertime peak of 122 GW on Aug. 26. At an Aug. 29 Reliability Subcommittee, MISO’s John Harmon noted that the peak bested July’s high of 118 GW. MISO originally forecasted a summer peak of 123 GW to occur in July. (See “July Peak Prediction Unfulfilled,” MISO Predicts Painless Fall Despite Missouri Capacity Shortfall.)

“We did have a couple of maximum generation warnings due to the hot weather and lower than normal wind. We managed through that well,” Harmon said. He promised MISO would deliver a more thorough review of the event once it gathers the data for a stakeholder presentation.

Coal and natural gas supplied roughly 70% of demand over the heat wave’s most intense daytime hours. While the warnings were in place, MISO also relied on a few gigawatts of imports from PJM, although it, too, was contending with hot temperatures.

The situation was helped on Aug. 26 by thunderstorms that developed across western Minnesota and moved across central and eastern Minnesota into western Wisconsin.

MISO’s growing solar fleet also may have helped the footprint meet demand. The RTO is nearing 7-GW monthly solar peaks.

After Aug. 27, the system returned to normal operating conditions.

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CAISO’s WEIM Plucks Black Hills Utilities from SPP’s WEIS

CAISO scored a geographically small but symbolically significant victory in its contest with SPP on Aug. 28 with the announcement that two Black Hills Energy subsidiaries serving parts of Montana, Wyoming and South Dakota will move from SPP’s Western Energy Imbalance Service (WEIS) to the ISO’s Western Energy Imbalance Market (WEIM).

The decision by Black Hills Power and Cheyenne Light, Fuel and Power will expand the WEIM’s presence in Montana and Wyoming and extend its footprint eastward to take in a slice of South Dakota, which would become the 12th state included in the market.

“The agreement with California ISO provides the company with options to support reliability and system balancing, while paving the way for Black Hills Energy to participate in California ISO’s Western Energy Imbalance Market, starting in 2026,” Black Hills Energy said in an email to RTO Insider.

“We are very pleased to begin this process with Black Hills Energy to deliver future economic and reliability benefits to its customers,” CAISO CEO Elliot Mainzer said in a statement.

But the decision might be most consequential as another development in the ongoing competition for participants between SPP’s Markets+ and CAISO’s Extended Day-Ahead Market (EDAM), the latter of which builds on the WEIM.

In 2022, SPP said it eventually would phase out its real-time WEIS once its other Western market efforts gathered more momentum and members. (See SPP to Phase Out WEIS as New Market Offerings Expand.) At the time, SPP said it intended “to only provide one market offering in the West in order to provide maximum benefits for Western utilities” and that WEIS participants “will have the option to join the RTO or participate in Markets+.”

That projected outcome seems to have played a role in Black Hills’ decision to migrate to the WEIM.

“The planned formation of the SPP RTO West required us to assess our future market path, as it did not appear that the WEIS market status quo would remain an option after RTO West is operational,” the utility told RTO Insider. “We have found imbalance market participation to be beneficial for our customers, and the opportunity for our utilities to participate in the WEIM allows us to continue to optimize our generation operations while maintaining our high reliability and creating long-term value for the customers we are privileged to serve.”

Asked whether it is now considering joining the EDAM, Black Hills said it “will continue to monitor and be engaged in the development of markets in the Western Interconnection and will pursue future markets that provide additional value for the company and our customers.”

After joining the WEIS in 2023, both Black Hills subsidiaries participated in the extensive “Phase 1” effort to develop the tariff for Markets+, which SPP filed with FERC in March — and for which it received a deficiency notice last month. (See SPP Dispels Concerns over Markets+ Deficiency Letter.)

Black Hills offered an equivocal response to another question about whether it plans to continue funding Markets+ during the Phase 2 implementation process, reiterating that it will continue to “monitor and be engaged in” Western market developments.

An SPP document shows that Black Hills Power would be responsible for providing a 0.9% share of Phase 2 funding, while Cheyenne Light would be on the hook for 0.6%, amounts other funders would be required to cover if the two utilities withdraw from the effort. SPP estimates Phase 2 will cost about $150 million. (See BPA to Delay Day-ahead Market Decision, Sources Say.)

“SPP is aware of the announcement by Black Hills and continues to support each market participant’s ability to decide on a market choice that they consider best for their customers,” SPP spokesperson Meghan Sever said in an email. “The decision by Black Hills does not impact the viability of Markets+ or the RTO expansion in the West.”

Another Western BA

According to an integrated resource plan the utilities filed jointly with the South Dakota Public Utilities Commission in 2021, Cheyenne Light and Black Hills Power together serve more than 117,000 customers and operate 1,344 miles of transmission, most of which are maintained by the latter utility. That system interconnects with PacifiCorp and the Western Area Power Administration’s Rocky Mountain Region.

While both utilities sit within WAPA’s balancing authority area, the WEIM implementation agreement signed between CAISO and Black Hills Energy on July 31 stipulates that one of the utilities will be required to register a new BA to facilitate participation in the market.

The utilities’ 2021 IRP included a study by NAES that found they “are well situated to become a BA” but noted that maintaining it would cost between $5.77 million and $10.21 million annually, compared with costs of $3.54 million to $5.28 million a year for remaining in WAPA. Moving into PacifiCorp’s neighboring BA would cost the two utilities $3.10 million to $3.21 million annually, the study found.

“The implementation agreement supports our South Dakota and Wyoming electric utilities as they prepare to transition from the Western Area Power Authority, which currently provides balancing authority services, to a new BA in 2026,” Black Hills told RTO Insider.

That move would bring the number of Western BAs to 39.

The Black Hills announcement comes two days after the Bonneville Power Administration said it will delay its choice of a Western day-ahead market until next year. (See BPA Postpones Day-ahead Market Decision Until 2025.)

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Colorado PUC Adopts Rules for Utility Participation in Markets

Colorado’s investor-owned utilities must compare available alternatives when asking regulators for approval to participate in an RTO or ISO, under a decision by the Colorado Public Utilities Commission.

The comparison must include “sufficient modeling and other analytical support” showing the expected net benefits of participating in a particular RTO or ISO are similar to, or greater than, net benefits from other available options.

But such a comparison is not required when utilities seek approval to join a day-ahead market, the PUC said in its decision, issued Aug. 22.

The decision comes as CAISO’s extended day-ahead market (EDAM) and SPP’s Markets+ are in a heated battle for day-ahead market participants across the West. Colorado utilities have a choice among EDAM and Markets+, as well as SPP’s RTO West, a proposed extension of services offered in the Eastern Interconnection.

The PUC decision, which adopts rules regarding utility participation in organized electricity markets, was prompted in part by Senate Bill 21-072 from the state’s 2021 legislative session. The bill requires transmission utilities to join an organized wholesale market by Jan. 1, 2030.

The PUC’s new rules list factors the commission will consider in evaluating a utility’s request to join an RTO, ISO or day-ahead market.

PUC Chairman Eric Blank, who was the hearing commissioner in the case, issued a recommended decision in June.

Ten groups then filed a joint request to modify the decision to include a comparison of alternatives in evaluating a request from investor-owned utilities to join an RTO, ISO or day-ahead market. They asked that the comparison of benefits be based on “a nodal mapping of the Western Interconnection and at least three years of simulated market operations.”

“We believe that it is impossible for the commission to determine that utility participation is in the public interest without an analysis of the market options that are available to a utility,” the commenters said in their joint filing.

The groups that jointly commented include Advanced Energy United, Clean Energy Buyers Association, Interwest Energy Alliance, Western Grid Group and Western Resource Advocates.

Loss of Control

In explaining its decision, the commission said utility participation in RTOs or ISOs raises more concerns than participation in less-integrated offerings such as day-ahead markets.

In an RTO, utilities give up control of their transmission assets and much of their decision-making to a regional governance process, the PUC said. The PUC also cited the need for “timely review” of day-ahead market applications.

The PUC adopted the requirement for a comparison of alternatives in an RTO request but left out the need for nodal mapping that the commenters requested. That way, the commission said, utilities will have “more flexibility in the type of modeling or analytical support that may be used.”

In a statement after the decision, Western Resource Advocates said it was pleased with the commission’s decision to require a comparative analysis of options for joining an RTO, but disappointed the requirement didn’t extend to day-ahead market participation.

The joint request from WRA and other groups noted that “the landscape of Western market footprints is rapidly evolving” as utilities evaluate EDAM, Markets+ and SPP’s RTO.

“Because of the highly dynamic nature of market footprints, and the significant impact of these footprints on benefits and risks to Colorado consumers, neither the IOUs nor the commission can truly understand the potential costs and benefits without a comparative analysis of alternative market participation under different footprint scenarios,” the groups said in their filing.

Utility Requirements

The decision keeps in place other requirements from Blank’s recommended decision for utilities that want to join an RTO, ISO or day-ahead market.

The RTO, ISO, or day-ahead market that an investor-owned utility wants to join must have a greenhouse gas tracking and accounting system.

Detailed modeling must show that benefits of joining, such as production cost decreases, reliability improvements and emission reductions, will be greater than the expected costs.

And there must be a plan for efficient dispatch and exchange of energy if there is more than one regional market construct operating or proposed to operate in Colorado.

Additional requirements apply when the request is to join an RTO. For example, the RTO must have a regional resource adequacy construct and a plan for new transmission.

The requirements are simplified for a request from a cooperative electric generation and transmission association

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Report Quantifies Consumer Savings from Biden-era Efficiency Standards

The average household should save $107 on utility bills every year because of the efficiency standards crafted by the Biden administration, according to a new analysis released by the Appliance Standards Awareness Project (ASAP) and PIRG. 

The study calculates savings in each state as old appliances are replaced with new models that meet the standards. Impacts change by state based on energy prices and heating and cooling needs, among other factors. 

The study expects businesses around the country will save $2 billion annually. It also lays out the air pollution cuts (in nitrogen oxides and sulfur dioxide) that each state can expect from the standards. 

“Consumers are going to save money year after year thanks to efficiency standards set during the Biden administration,” ASAP Executive Director Andrew deLaski said in a statement. “Whether you’re replacing a water heater, a clothes dryer or another appliance, these standards are going to ensure you get a better product that doesn’t leave you with needlessly high utility bills.” 

The Department of Energy periodically updates efficiency standards for new products such as refrigerators, water heaters, air conditioners and electric motors. Since President Joe Biden took office in 2021, the department has issued about two dozen standards, which together offer savings in every state ranging from $67 in Utah to $285 in Hawaii. 

Most of the standards set during Biden’s term will start taking effect between 2026 and 2029, with the study looking at how they will impact utility bills and other areas over the next two decades. 

The standards offer net benefits in terms of bill savings, but a handful have more significant impacts, the report said. The biggest savings come from water heaters, light bulbs (“general service lamps”), washing machines, refrigerators, clothes dryers, pool pump motors and furnaces. 

“All the standards save consumers more money than they cost; we estimate that the total utility bill savings for household products outweigh any increases in purchase price by more than a factor of three,” the report said. 

The study quantifies how the new standards will cut NOx and SO2 pollutions, which are emitted by power plants and gas-fired appliances. The pollutants are harmful to the respiratory system and contribute to respiratory conditions, especially in children, the elderly and people with asthma. 

The study said the standards should cut NOx emissions annually by 11,700 tons and SO2 by 5,100 tons. 

“New standards for clothes washers and dishwashers will also reduce water waste, helping to reduce stresses on water supplies in drought-stricken areas,” the report said. 

Smaller states will save about 100 million gallons annually, while the most populated will save billions each year. Cumulatively the entire country will save more than 1 trillion gallons of water over the next two decades, the report said. 

“These updated standards will save consumers money and reduce air pollution for years to come, just by the use of more efficient appliances. It’s a clear win for Americans’ wallets,” PIRG Energy and Utilities Program Director Abe Scarr said in a statement. “For households and businesses across the country, the prospect of sustained annual utility bill savings and cleaner air is welcome news.” 

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NERC Examines Transfer Capability in Draft ITCS Installment

NERC has posted in draft form the first results from the Interregional Transfer Capability Study ordered by Congress in 2023, summing up the transfer capabilities between transmission planning regions in North America.  

The ERO Enterprise — including NERC, the regional entities and all North American transmitting utilities — has been working on the ITCS since Congress mandated the study in the Fiscal Responsibility Act. Under the FRA, NERC must file the finished report with FERC by December. The study includes “significant collaboration” with a host of additional stakeholders, including transmission planners, owners and operators; planning coordinators; state, provincial and federal partners; utilities; and trade groups. 

The Transfer Capability Analysis released Aug. 28 represents Part 1 of the ITCS, following the publication of NERC’s Overview of Study Need and Approach in July. (See NERC Promises 1st ITCS Results by August.) Results from this installment will be used for Part 2, a draft of which is scheduled to be released in November and will recommend prudent additions to transfer capability that could strengthen grid reliability.  

Part 3, laying out recommendations to meet and maintain total transfer capability, is expected to be released in draft form in November as well. A final installment focusing on Canada is to be published in the first quarter of 2025. 

The transfer capability analysis covered two different base cases: one based on summer 2024, the other on winter 2024/25. NERC used the transmission planning regions identified in FERC Order 1000 as a starting point for studying transfer capacity, as required in the FRA. The project team further subdivided these regions in some cases to account for the geographic variations and resulting internal transfer constraints in some areas. 

Performing the transfer analysis involved simulating unplanned outages of various system elements during transfer analysis to discover the point at which the grid could not maintain reliability. The last step prior to a reliability issue was labeled the first contingency incremental transfer capability. This was added to the base transfer level, derived from scheduled interchange tables for each study case, to arrive at the total transfer capability of each. 

The study found that transfer capability “varies seasonally and under different system conditions [and] cannot be represented by a single number.” A map shared by the team showed that winter and summer transfer capabilities are closely matched in some cases — such as Washington to Oregon, which shows just a 200-MW difference between seasons — while other cases exhibit a wide disparity. 

For the link between California South and the Wasatch Front, for example, the transfer capacity in summer was reported as 6 GW, as opposed to just 1 GW in winter. MISO West reportedly could transfer 8 GW to PJM West in winter, but just 2.5 GW in summer.  

Other areas indicated no transfer capabilities in one season at all. SERC Florida was recorded as having a capacity of 1.3 GW into SERC Southeast in summer and none in winter, while California North reported a transfer capability to Oregon of 2.5 GW in winter and nothing in summer. 

NERC said transfer capabilities tended to be higher in the West Coast, Great Lakes and Mid-Atlantic areas, and lower in the Rocky Mountain states, Great Plains, Southeast and Northeast. Limited transfer capability exists between interconnections. This installment includes transfer capabilities from Canada into the U.S., but not the other way around; Part 4 will cover transfer capabilities from the U.S. to Canada and between Canadian provinces. 

In a media release, NERC warned that Part 1 should not be taken as a measure of energy adequacy in itself, but rather as simply a statement of the “magnitude of transfer capability.” That will be examined when NERC explores prudent additions “based on a holistic view of transmission and resource availability” in Part 2.