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November 5, 2024

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Tenn. Congressmen Introduce Bill to Make TVA IRP Process More Public

Two members of Congress from Tennessee have come across the aisle and introduced a bill that would force the Tennessee Valley Authority to make its integrated resource planning process more transparent. 

Reps. Steve Cohen (D) and Tim Burchett (R) added another “IRP” acronym to TVA’s lexicon when they introduced the TVA Increase Rate of Participation Act on March 8.  

The proposed legislation would compel TVA to establish an Office of Public Participation to oversee outreach and make recommendations to the utility to improve public accessibility and accountability.  

The representatives said their plan would “ensure the most efficient, affordable, environmentally conscious and reliable plan for meeting customers’ energy needs.” 

The office would be tasked with making sure TVA’s IRP contains more detailed information like forecasted peak demand and sales data; planned transmission investments; sensitivity analyses on fuel costs, environmental regulations, electrification and distributed energy resources; disclosure of modeling assumptions to intervening parties; and descriptions of public influence on the plan. 

Additionally, the office would be responsible for making sure the TVA Board of Directors makes decisions “approving, denying or modifying the plan, like every other utility regulator, according to the least cost and reliability requirements in the Energy Policy Act of 1992, and require consideration of resilience, extreme weather risk and public health impacts.”  

“Transparency is critical in making public policy and, for too long, TVA’s decision-making has been obscure and opaque, such as their current IRP process where organizations had to be hand-selected to participate in their working group,” Cohen, a longtime critic of TVA “secrecy,” said in a press release. “TVA needs outside guidance to meet the changing needs of utility customers as it addresses resiliency and other foreseeable disruptions to its planning,”  

Cohen made a similar statement Jan. 25 during “The People’s Voice on TVA’s Energy Plan” public hearing in Nashville that was hosted by Appalachian Voices, the Center for Biological Diversity, Southern Renewable Energy Association, Energy Alabama, Southern Alliance for Clean Energy and the Sierra Club, among others. The hearing focused on the shortcomings and shadowy nature of TVA’s IRP process and was held after the utility didn’t respond to requests to host a public hearing on its IRP. (See Nonprofits Attempt to Force a More Transparent TVA IRP Process.)  

Burchett said TVA’s customers “deserve the chance to gain insight into TVA’s decision-making process and the opportunity to offer input.”  

“I appreciate the ways TVA has made an effort to become more transparent in recent years, and this would provide some solid guidelines on how to make that even more of a reality,” he said.  

TVA is conducting its first long-term IRP effort since 2019. The plan not only will guide near-term resource decisions, but steer long-term programs that will determine how the region’s electricity needs will be met through 2050. 

TVA: More Public Engagement to Come

TVA spokesperson Scott Fiedler characterized the federal agency as a “transparent organization that actively seeks public input on and about our decision-making processes.” He said TVA “intentionally seeks out, engages and welcomes a diverse set of voices” in its IRP process.   

“We are currently reviewing the legislation that was introduced today. We believe we have good methodology, but TVA is always open to improving our public input processes,” Fiedler said in an emailed statement to RTO Insider.  

TVA said it will release a draft IRP later in March for public comment. From there, the utility has committed to holding two virtual open houses on the IRP in addition to a series of in-person open houses in Tennessee, Alabama, Mississippi, Kentucky, Georgia, North Carolina and Virginia.  

“This will help ensure that every member of the public will be able to receive information and ask questions and provide feedback,” Fiedler said. “Moving forward, with public stakeholders, TVA is creating a roadmap that will support TVA’s mission of making life better for everyone in the region.” 

TVA kicked off its IRP process last spring and said it began the planning by soliciting public input on considerations for the 2024 IRP. The IRP is evaluated by a nonpublic, invitation-only working group TVA formed, composed of representatives of “local power companies, academic institutions, environmental organizations, state government and other community groups,” according to TVA. The working group reviews the federal utility’s inputs, assumptions and results; TVA posts short summaries of the working group’s meetings to its IRP site.  

Nonprofits Say Law is Overdue

Several environmental and advocacy groups applauded the legislation’s introduction.  

Vote Solar Southeast Regulatory Director Jake Duncan called the TVA Increase Rate of Participation Act “a long-overdue yet monumental stride toward creating a meaningful, transparent and inclusive energy plan for the TVA.” 

“We applaud Congressman Cohen and Congressman Burchett for their leadership in ensuring TVA’s power system planning includes the very people these decisions impact,” Appalachian Voices’ Bri Knisley said.  

Sierra Club Tennessee Field Organizing Strategist Amy Kelly said TVA has operated for too long without “meaningful public and expert engagement during their energy planning.” 

“TVA was founded as a public utility to enrich and benefit the people, industries and environment of the Tennessee Valley, and this legislation would help TVA live up to its mission,” she said. 

The Southern Alliance for Clean Energy (SACE) also has criticized TVA for carrying out “one of the least public IRP processes in the nation” despite being the nation’s sole federally owned utility.  

“This emboldens TVA to invest in new fossil fuel infrastructure, which will expose people in the Tennessee Valley to the risks associated with higher bills, more carbon pollution and more power outages in the future,” SACE said in a statement February. 

By all appearances, TVA will replace two coal units at its 2,470-MW Cumberland Fossil Plant with a 1,450-MW natural gas plant. Early this year, FERC approved a pipeline meant to feed the plant, although TVA has said its decision to build the gas plant isn’t final. (See FERC Approves Pipeline to Supply New TVA Cumberland Gas Plant and TVA’s Cumberland Coal-to-gas Plans Press on over Resistance.) 

SACE has criticized TVA for using the minimum required public engagement outlined in the National Environmental Policy Act as a substitute for comprehensive public interaction. 

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Conservation Groups File Another Lawsuit to Stop Cardinal-Hickory Creek’s Last Mile

Three conservation groups have filed a new civil suit against three federal agencies for consenting to permits and a land exchange that allow the divisive Cardinal-Hickory Creek 345-kV line to carve a final, mile-long path through a protected wildlife refuge in Wisconsin.  

The Environmental Law and Policy Center filed the complaint in the U.S. District Court for the Western District of Wisconsin on behalf of the Driftless Area Land Conservancy, Wisconsin Wildlife Federation and National Wildlife Refuge Association.  

The three allege the U.S. Fish and Wildlife Service, U.S. Rural Utilities Service and U.S. Army Corps of Engineers violated the National Environmental Protection Act (NEPA), National Wildlife Refuge System Improvement Act of 1997 and Administrative Procedure Act by approving permits and allowing a land exchange to assemble the final mile-long stretch of the 102-mile, $650-million transmission line through the Upper Mississippi River National Wildlife and Fish Refuge. 

Co-owners ITC Midwest and Dairyland Power Cooperative late last month finalized an agreement with the Fish and Wildlife Service to turn over about 36 acres of privately owned land along the Mississippi River in Wisconsin for refuge annexation while receiving about 20 existing acres of the refuge near the Iowa state border.  

The conservation groups accused federal agencies of “skewing the required NEPA review and purpose and need statements to avoid rigorously exploring and objectively evaluating all reasonable alternatives.” They also said the east-west 200-foot transmission towers will interrupt a “major north-south migratory bird flyway used by hundreds of thousands of birds annually.”  

“The transmission companies did not evaluate alternative crossings outside of the refuge in their environmental impact statement, and we should not set a precedent that a simple land swap is all it takes to plow through a national treasure,” Driftless Area Land Conservancy Executive Director Jennifer Filipiak said in a press release.  

Wisconsin Wildlife Federation President Kevyn Quamme said a “massive transmission line crossing through this area will be harmful to the important habitats for fish and wildlife in the refuge and to the millions of migrating birds that pass through on the Mississippi Flyway each year.” 

“Building a transmission line through the refuge also will serve as a deterrent to locals and tourists alike who visit the refuge and contribute to the local economy,” Quamme added. 

Cardinal-Hickory Creek is the final piece of MISO’s 17 Multi-Value Projects approved as a $5 billion portfolio in 2011. The line is estimated to facilitate the connection of nearly 20 GW of renewable energy and has been mired in litigation for more than a decade. 

The newest lawsuit concerning Cardinal-Hickory Creek is related to a federal district court decision issued in 2022 that halted construction on the final line segment, finding that federal agencies violated federal law when they cleared the line to route through the refuge. (See Federal Judge: Tx Line Can’t Cross Wildlife Refuge.) Last summer, the Seventh Circuit U.S. Court of Appeals vacated the decision and lifted the injunction, finding that the Fish and Wildlife Service at the time hadn’t issued a final permit for the utilities to build across the refuge.  

The Driftless Area Land Conservancy, Wisconsin Wildlife Federation and National Wildlife Refuge Association said Cardinal-Hickory Creek’s developers were warned in the 2022 ruling against them that stringing lines right up to the protected wildlife refuge would be staging an “orchestrated train wreck.”  

‘Weaponizing NEPA’

Co-owners ITC Midwest and Dairyland Power Cooperative said they were “dismayed” by the latest litigation and said the lawsuit could counterintuitively “delay significant environmental benefits” to the Upper Mississippi River National Wildlife and Fish Refuge.  

The two said the deed exchange stands to expand the refuge when the line is completed. They said an analysis from the Fish and Wildlife Service found that “the proposed land exchange fulfills the refuge’s purposes by exchanging lower-quality habitat for higher-quality habitat, increasing the total protected acreage in the refuge, reducing habitat fragmentation in the long term and allowing the refuge to acquire a high-priority tract that would not otherwise be available.” The Fish and Wildlife Service also said that in the long run, the land swap will supplement the refuge’s breeding grounds.  

ITC and Dairyland said the refuge land they want to use to cross the Mississippi River is adjacent to a road and farmland and has “low habitat value.” They also said construction of Cardinal-Hickory Creek would allow them to deenergize and remove an existing 161-kV line that cuts through the refuge. The Fish and Wildlife Service deemed that a net conservation benefit because it also would increase the protected acreage and cut down on the number of transmission towers in the refuge overall. 

ITC and Dairyland said they’re committed to minimizing impacts to grass habitats, scrub and wetlands, and they pledged to not grade land inside the refuge. They said they’re offering to nearly double the refuge’s land tradeoff for a transmission project that is “vital to the future of our region’s renewable energy and clean energy economy.” 

“As of October 2023, there are 161 renewable generation projects in Wisconsin, Iowa and other Upper Midwestern states representing more than 24.7 GW dependent upon its completion — enough to power millions of homes and businesses with clean energy,” the two said. 

The companies also said the continued litigation over Cardinal-Hickory Creek is delaying its in-service date and driving up costs. They accused the conservation groups of “weaponizing NEPA” and said the Environmental Law and Policy Center should be in favor of the line because it supports a clean energy economy.    

“Over the past few years, several of these same opponents have filed multiple lawsuits in federal and state court trying to stop construction of the project. The co-owner utilities have successfully navigated four separate injunctions and won appeals before the Wisconsin Supreme Court, as well as three different favorable opinions from the U.S. Seventh Circuit Court of Appeals,” ITC and Dairyland said.  

They referenced a county circuit court judge’s decision last year to uphold the Wisconsin Public Service Commission’s 2019 decision to issue a certificate of public convenience and necessity for the line, as well as a 2022 ruling from the Wisconsin Supreme Court that a former state regulator’s years’ worth of encrypted messages to the line developers’ employees did not amount to a serious risk of bias during permitting. (See Wisconsin Tx Project Clears State Litigation; Wisconsin Court Undercuts Lawsuit in Cardinal-Hickory Creek Dispute.)  

Co-owners ATC, ITC Midwest and Dairyland Power Cooperative report that Cardinal-Hickory Creek is more than 95% complete. The eastern half of the line was placed into service in early December.  

ITC Midwest said it expects construction on the western half of the project from the Hickory Creek Substation in Dubuque County, Iowa, to the Hill Valley Substation in Wisconsin to be finished and the line in service by June. ITC said the segment is virtually complete except for a 2.2-mile stretch extending from a spot near the Nelson Dewey Substation in the village of Cassville, Wis., westward across the Mississippi River to a spot near the Turkey River Substation in Clayton County, Iowa. That portion of the line includes the route through the refuge.  

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NJ Bill Would Levy Annual Fee on EV Ownership

New Jersey’s Assembly Transportation and Independent Authorities Committee on March 7 backed a bill that would levy a $250/year fee on electric vehicle registration beginning in July, brushing aside criticism from car sellers and environmental groups that it would be excessive. 

The fee is part of wide-ranging bill A4011, which would amend the law governing the state’s Transportation Trust Fund Authority, which raises funds to pay for transportation investment projects and mass transit. The bill, sponsored by Democrats in both the Assembly and Senate, would reset the fund’s revenue system from 2025 to 2029 to help meet state capital initiatives. 

The initiative comes as states across the U.S. are wrestling with how to raise funds for infrastructure projects that have traditionally been funded through a gas tax as drivers shift from fossil-fueled vehicles to EVs, cutting gas consumption and gas tax income. 

Annual fees on EV ownership are now levied in 30 states, with the highest fee levied in Washington at $225, with Georgia charging $211 and Alabama charging $203, according to a report by Money in August 2023. 

New Jersey’s would start at $250 on July 1 and rise by $10 every year until it reaches $290 on July 1, 2028. The fee would be paid when the vehicle is initially registered and when it is renewed. 

Environmental groups said they have no problem with a fee on EV buyers but that the proposed level was way above what would be fair. 

Speaking for ChargEVC, which seeks to advance the EV market through the development of sustainable programs and policies, Gabel Associates’ Eve Gabel-Frank said the fee would be “punitive” and the “highest fee in the country.” 

She said that under the bill, an owner of the hybrid Toyota Prius Prime would pay $97 in gas taxes a year, while an owner of the Honda CR-V, a small SUV, would pay $127. 

“So paying a $250 fee is way higher. They’d actually be paying double” what an owner of an efficient, gas-powered vehicle pays, Gabel-Frank said, suggesting the committee cut the fee to $75. 

EV advocates argue that New Jersey’s proposed $250 registration fee for EVs would be more than the gas taxes gas-powered cars pay. | ChargeEVC

But Eric DeGesero, speaking for the Fuel Merchants Association of New Jersey, said the fee should actually be higher. He said the average vehicle uses 569 gallons of gas a year, which generates about $245 from the state gas tax of 43 cents per gallon. 

“The fee should be rounded up to $300, set there immediately and adjusted annually,” he said. 

‘Pay Their Fair Share’

Business groups and unions broadly supported the bill, saying the resulting capital investments would create jobs and stimulate economic development in the state. 

Steven Gardner, director of the New Jersey Laborers Employers Cooperation and Education Trust, said transportation is essential to the state, and as it transitions to EVs, it needs to look at new ways of raising revenue. He noted that in a sign of the shift, Gov. Phil Murphy’s administration in November adopted the Advanced Clean Cars II rules, which require zero-emission vehicles to account for all vehicles sold by 2035. 

“This legislation begins to include the fee on zero-emission vehicles to ensure they begin to pay their fair share for the roads they also drive on,” he said. “Without a trust fund making consistent investments, none of us could get to our jobs, our children’s schools, the shore or any of our state parks. New Jersey’s entire economy is wholly dependent on having a first-class transportation network.” 

Voting 7-4 in favor of the bill, largely along party lines, committee members focused their comments mainly on the gas tax and need for infrastructure investment and how to achieve it, paying little heed to the EV fee issue. A similar bill in the Senate has not advanced. 

Aside from the EV fee, the bill would enable the fund to raise revenue by gradually increasing the target income from 2025 to 2029 and setting the gas tax rate at a level to meet that target. The income target would start at $2.032 billion in 2025 and rise by about 16% to $2.36 billion in 2029.The revenue raised would go into a general capital reserves fund to support capital projects, but the bill also specifies that it can’t be used to pay debt service on bonds. 

‘False Narrative’

Opposing the bill, Gabel-Frank sought to correct what she said is a “really common false narrative” — and one put forward by DeGesero — that EVs are heavier because of their batteries than a gas-powered vehicle. 

In that argument, the weight of the EVs would cause more road damage, which would need to be repaired with transportation investment funds. 

“We did a review of studies,” Gabel-Frank said. “We found that road damage is not caused by passenger vehicles. It’s caused by vehicles that are over 26,000 pounds” — heavy-duty trucks. 

Doug O’Malley, director of Environment New Jersey, said the fee — along with Murphy’s recent proposal to remove the exemption for EV buyers from paying the state’s 6.25% sales tax — would hurt the consumer uptake of ZEVs. 

Jim Appleton, president of the New Jersey Coalition of Automotive Retailers, said his members are “all in on EVs,” but the fee would “make it more difficult for dealers to turn EV-curious consumers into EV owners.” 

“No one disputes the idea that EV drivers must pay their fair share to maintain roads and bridges,” he said. But “New Jersey cannot achieve higher EV adoption without generous cash-on-the-hood incentives and sales tax incentives.” 

“We have conflicting policies at play here. If we’re going to ask EV drivers to pay into the Transportation Trust Fund — and we should — we shouldn’t make them pay for it all upfront in the showroom,” Appleton said. “What we’ve got to do is try to come up with a way that avoids EV buyers having to come up with that extra $1,000 at the point of purchase.” 

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Can US Maintain Record Solar, Clean Power Growth?

The U.S. could nearly quadruple solar capacity in the next 10 years, from the 177 GW installed at the end of 2023 to 673 GW by 2034, with solar providing the largest share of the nation’s electricity generation by 2040, according to a report released March 6 by the Solar Energy Industries Association and Wood Mackenzie.

But such exponential growth could depend on the right mix of policy and market conditions, SEIA and WoodMac caution in the report. In a “bull” scenario ― with few supply chain or interconnection constraints, and stable financing and access to tax credits ― an additional 85 GW of solar could be installed by 2034, the report estimates. But a less solar-friendly “bear” scenario could cut new capacity over the next decade by nearly 120 GW.

solar

By 2030, the U.S. could be installing 50 GW of residential, commercial and utility-scale solar per year. | Wood Mackenzie

The result, the report says, is that “there could be a 200-GW swing in solar installations over the next decade. … The challenges that currently limit growth in this industry ― particularly transmission and interconnection limitations ― will only become more heightened over time. Addressing these limitations is key to meeting both decarbonization goals and growing power demand.”

The more immediate effects of those limitations are detailed in a second report, the American Clean Power Association’s (ACP) 2023 Annual Market Report, released March 7. Over the past three years, delays on solar, wind and storage projects have put more than 60 GW of clean power capacity on hold, the report says.

On the upside, the pipeline of clean power projects is healthy, with close to 71 GW of projects under construction by the end of 2023 and close to 100 GW in advanced development, meaning they have a firm equipment order and a power purchase or offtake agreement or other utility contract.

“The clean power pipeline experienced a 26% year-over-year growth from 135,221 MW at the end of 2022,” the ACP report says.

The two reports provide slightly different but complementary perspectives on the banner year clean power, especially solar, had in 2023. (All figures in the SEIA-WoodMac report are DC; the ACP report does not specify DC or AC.)

    • Tracking only utility-scale projects over 1 MW, the ACP report says 33.8 GW of clean power — solar, wind and storage — came online in 2023. SEIA and WoodMac count 32.4 GW of residential, commercial and utility-scale solar projects combined. Both reports have solar at 58% of new power generation added to the U.S. grid.
    • Both reports also put Texas in the No. 1 spot for new solar and clean power. On solar only, Texas and No. 2 California are neck and neck: 6,533 MW vs. 6,171 MW, respectively. But, counting solar, wind and storage, Texas leaves California in the dust: 9,931 MW to 5,590 MW.
    • According to ACP, Texas and California together put more new clean power on the grid last year than the next 19 states combined.
    • The ACP report also underlines the mainstreaming of clean power, with maps showing that every state in the union has some clean power. Wind energy provides more than 20% of electricity in 12 states, and solar delivers more than 10% of electricity in nine. The only state on both lists is Maine.
    • More clean power than natural gas has been added to the grid every year since 2014, but natural gas also had a banner year in 2023, with 8,999 MW of new capacity coming online, a 27% increase over 2022, according to ACP.

The NEM 3.0 Effect

While both reports see solar as the dominant form of generation going forward, SEIA and WoodMac see some clouds on the horizon. Record installations notwithstanding, solar in general has been affected by higher interest rates and supply chain, interconnection and workforce challenges.

The residential solar market installed a record-breaking 6.8 GW in 2023, but a downturn is expected this year, primarily because of California’s introduction of much lower compensation rates for the power rooftop solar owners put back on the grid.

solar

ACP reports more than 170 GW of solar, wind and storage projects either under construction or in advanced development. | American Clean Power Association

The new compensation plan — referred to as Net Energy Metering 3.0 — goes into effect in April and is especially disadvantageous for homeowners who only install solar panels, rather than solar and storage. Residential installations in California remained high through the first three quarters of 2023, as installers worked through a backlog of orders that would qualify for the previous, higher compensation, NEM 2.0.

But residential installations in the Golden State dropped 35% in the fourth quarter, and WoodMac says both high interest rates and the transition to NEM 3.0 will drive a 13% decrease in new residential capacity across the country this year. The California market could contract 40%.

Commercial solar could also feel a pinch from NEM 3.0, although a backlog of installations in California has been keeping figures high. This sector includes distributed projects with industrial, commercial, agricultural, school, government or nonprofit customers, and put 1,851 MW of new power on the grid in 2023, a 19% increase over 2022.

The report sees a dip coming in 2025 through 2027, again from NEM 3.0, but also from added costs related to the Inflation Reduction Act. To qualify for the law’s full 30% investment tax credit, commercial projects over 1 MW will have to pay prevailing wages and work with registered apprenticeship programs.

The extent of the impact here will depend on the final rules of the ITC, expected later this year.

The utility-scale solar sector ended 2023 on a record-breaking high note with 10.5 GW installed in the fourth quarter. But President Joe Biden’s two-year moratorium on tariffs on solar cells and panels from Cambodia, Malayasia, Thailand and Vietnam ends in June, which could result in higher prices and tighter supply chains.

WoodMac also notes that “high interest rates, tighter financing condition and interconnection uncertainty slowed contract negotiations,” which resulted in the utility-scale project pipeline falling to a record low of 83 GW.

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NEPOOL PC Backs ISO-NE Tariff Revisions for Order 2023 Compliance

The NEPOOL Participants Committee on March 7 unanimously approved ISO-NE’s package of tariff revisions to comply with FERC Order 2023. 

ISO-NE expects to submit the compliance filing April 1, two days before the deadline set by FERC in its efforts to unclog interconnection queues that have bogged down nationwide. 

The vote follows months of deliberations that included a Feb. 15 NEPOOL Transmission Committee meeting at which an initial proposal, as well as six proposed amendments to it, failed to gain the two-thirds support needed for approval. (See ISO-NE Order 2023 Compliance Proposal Fails to Pass NEPOOL TC.) 

ISO-NE incorporated several elements of the amendments into the final package, which was approved with only two abstentions. 

The RTO summarized the post-Feb. 15 changes to the package in a March 1 memo to the committee: 

    • An interconnection customer may specify in its interconnection request for capacity network resource (CNR) interconnection service that the requested service be downgraded to network resource interconnection service under certain conditions. 
    • After the completion of a cluster study (not including the transitional cluster study), if the RTO determines that a cluster restudy is required (because of the withdrawal of other projects), the developer of a remaining project may request a specific one-time decrease in the size of the generating facility or elective transmission upgrade for the restudy. 

For customers with assigned queue positions as of 30 calendar days after April 1, but for which system impact studies are projected to be completed between May 1 and June 30, the RTO will still tender transitional cluster study agreements. However, if the SIS is complete and accepted by the customer by July 1, the request will no longer proceed to the transitional cluster study. Instead, the customer will be tendered an interconnection agreement pursuant to the applicable provisions in the respective interconnection procedures. 

    • Where a request successfully participates in the transitional CNR group study and then later obtains a capacity supply obligation in the Forward Capacity Market, the rules governing any termination of the CNR capability will be governed by the relevant FCM rules. 

“Importantly, each of these additions can be incorporated without adding to the overall time frames or decreasing the efficiency of the new process,” ISO-NE said. 

When FERC issued Order 2023 last July, the potential capacity of projects waiting in interconnection queues exceeded 2 TW, more than the amount of generation already online nationwide. It seeks to streamline the interconnection process for transmission providers, provide greater timing and cost certainty to interconnection customers and prevent discrimination against the wave of renewables being proposed nationwide. (See FERC Updates Interconnection Queue Process with Order 2023.)

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NV Energy OK’d for Coal Plant Conversion, Solar+Storage Project

Nevada regulators approved NV Energy’s plan to convert its last coal-fired power plant to natural gas, while also allowing the company to move forward with a $1.5 billion, 400-MW solar-plus-storage project. 

Approval of the solar-plus-storage project, known as Sierra Solar, may allow the utility to reduce an open position that’s been described as one of the largest in the West. NV Energy is developing the project, which would be about 15 miles northeast of Fernley in northern Nevada. 

But whether Sierra Solar will be built remains to be seen. 

In an order approved March 1, the Public Utilities Commission of Nevada (PUCN) set conditions on Sierra Solar including payment of damages to ratepayers if the project is delayed or doesn’t perform as expected. 

The order admonished NV Energy for arguing that it needed to move forward quickly with the project, then balking at conditions. It quoted NV Energy’s response when asked about a maximum project cost: “If the commission … feels like it has to have an upper limit on costs, we’ll assess if we think it’s reasonable and whether we can move forward with the project or not.” 

“The commission is persuaded that there is a resource adequacy need necessitating consideration of the Sierra Solar project now and is troubled by the suggestion that this need may be ignored unless NV Energy gets the terms that it desires for the Sierra Solar project,” the commission wrote in its order. 

In a news release after the commission’s vote, NV Energy said it “is diligently reviewing the conditions the commission placed upon the project.” 

Planning Process Questioned

NV Energy proposed the Sierra Solar project through the fifth amendment to its 2021 Integrated Resource Plan. The amendment also proposed the conversion of the North Valmy Generating Station, NV Energy’s last coal-fired plant, to run on natural gas through 2049. 

PUCN largely approved the amendment, despite objections of stakeholders who said the projects should go through a more comprehensive evaluation as part of the utility’s 2024 IRP that will be filed this year. 

Instead, the utility has resorted to “crisis planning” through multiple amendments to the IRP, said Emily Walsh, clean energy policy adviser at Western Resource Advocates. Walsh noted that the cost of projects proposed in the fifth amendment far exceeded that of projects in the 2021 IRP. 

“They’ve really been gaming the IRP process,” Walsh told RTO Insider. 

In addition to approving Sierra Solar and the North Valmy conversion, the commission authorized a 2049 retirement date for two gas-fired units at the Tracy power plant, which had been scheduled for closure in 2031. 

But the commission declined to approve an asset purchase agreement for future development of the 149-MW Crescent Valley solar-plus-storage project about 50 miles from the Valmy plant. Because the project is at an early stage, the utility can bring the proposal back as part of its 2024 IRP, the commission said. 

Open Position

One of the drivers behind NV Energy’s proposals was to reduce its open position — resource needs that are met through short-term market purchases rather than by utility-owned resources or long-term contracts. 

In a survey of 13 Western utilities, NV Energy’s projected open position in 2025 was 1,092 MW, second only to that of PacifiCorp’s 1,637 MW, according to testimony filed with PUCN on behalf of the utility. As a percentage of peak demand, NV Energy’s open position was 13%, ranking sixth out of the 13 utilities. 

Proposals in NV Energy’s IRP amendment would reduce its open position to 820 MW in 2026, representing 10% of peak demand. 

The commission’s order also addressed NV Energy’s participation in the Western Resource Adequacy Program, directing the utility to postpone its financially binding season from winter 2026/27 to winter 2027/28.  

“NV Energy’s [forecast] open position for the summer of 2027, with or without commission approval for the requests in this docket, would subject NV Energy to substantial penalties that could be passed on to ratepayers,” the commission wrote. 

Valmy Solution

In its 2021 IRP, NV Energy planned to replace capacity from the coal-fired North Valmy Generating Station with the Iron Point and Hot Pot solar-plus-storage projects. The utility plans to end coal combustion at Valmy by the end of 2025. 

But supply chain issues derailed the solar projects, according to the utility, which then proposed a 200-MW battery storage project as a partial solution for the Valmy retirement. The commission rejected the proposal, asking NV Energy to come back with a complete solution for Valmy. (See NV Energy Rejected on Plan to Replace Coal Plant with Storage.) 

In its March 1 order, the commission approved the plan to convert Valmy to natural gas but granted only $50 million of the $83 million NV Energy wanted for the project. 

The $50 million is NV Energy’s actual costs for the project, the commission said, while the remaining $33 million is “just a placeholder amount associated with upgrades that may be needed at some point in the future.” 

NV Energy plans to split the cost of the Valmy conversion with Idaho Power, which is 50% owner of the plant. 

NV Energy acknowledged that it initially didn’t consider a gas conversion for Valmy. But a new transmission study found that an area called the Carlin Trend needs voltage support from a firm dispatchable resource. 

The commission said the Carlin Trend constraint is “a real condition.” In addition, “without Valmy, there is a high probability Nevada would have experienced rolling blackouts three out of the last four years,” the commission stated in its order. 

Once NV Energy’s Greenlink West transmission line is completed, the Valmy plant may be able to run less often, the commission noted. 

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NY Moves Methodically to Create New Class of Utility

ALBANY, N.Y. — The networked heating systems New York wants to test on a pilot scale hold promise for the environment and society but are taking time to design. 

A March 6 conference brought together many of the people advocating for thermal energy networks (TENs), one of the tools the state is considering to reduce its carbon footprint. 

Buildings account for a third of New York’s carbon dioxide emissions, and TENs hold the promise of reducing that by using less energy and using it more efficiently.  

The Public Service Commission in 2022 ordered the seven largest investor-owned utilities to propose pilot projects that point the way for a permanent regulatory structure for utility TENs. 

Eighteen months later, the order has accomplished its initial goal — yielding a greatly varied set of proposals that could broadly inform future efforts — but the proposals are still at the first of several stages of PSC review. (See NY Utility Thermal Energy Network Pilot Program Simmers.) 

And the potential framework for what would be an entirely new class of utility in New York only recently has been released in draft form. 

The title of the summit — “Scale Up! Decarbonizing NY’s Neighborhoods” — accurately conveyed its mood: The room was full of supporters. 

The Building Decarbonization Coalition was one of the organizers, and its New York director, Lisa Dix, called the state’s first-in-the-nation utility TENs enabling legislation “one of the most important efforts to date to usher in the clean energy transition for buildings at scale in this state.” 

Simple and Complicated

Some potential tools of the clean energy transition — long-term battery storage, small modular nuclear reactors, economical but clean hydrogen generation — would require technological or engineering leaps to be usable.  

TENs are straightforward by comparison: Move heat from where it is unwanted to where it is needed within a group of buildings via fluid in pipes. Less energy is used, less is wasted. 

A project might be more or less complicated, depending on whether it includes details such as geothermal bores and heat pumps, or if there is a motherlode of wasted heat nearby, such as a data center.  

But the technology for accomplishing these tasks is known and mature. And as Jared Rodriguez of Emergent Urban Concepts pointed out, municipalities have decades of experience moving water from place to place through pipes. “It’s not rocket science.” 

The more daunting tasks in New York are shaping up to be organizational: 

    • getting enough property owners on board in a neighborhood. 
    • siting the infrastructure. 
    • deciding who pays for it. 
    • building it strategically so natural gas infrastructure can be retired or at least not expanded. 
    • transitioning gas workers to thermal jobs. 
    • maintaining union representation. 
    • ensuring economic and environmental benefits for disadvantaged communities. 
    • creating a new class of state regulated utility. 
    • making the entire process fit into the larger picture of the clean energy transition.

This is why the state is starting with pilot projects, and why development of those pilot projects is proceeding methodically. 

Department of Public Service Chief of Staff Jessica Waldorf said: “It has taken us centuries to build the systems that we have in place, and we cannot make a wholesale shift of our energy systems and the way that customers choose to use them in an instant. 

“Advancing projects like these at scale in existing communities as part of neighborhood-level decarbonization efforts is a new frontier, and one that will require partnership of many different stakeholders, like all of you in this room, to effectuate.” 

She said, however, that progress to date makes her confident of progress to come: 

“Make no mistake — the transition to cleaner sources of energy has been taking place for decades, where we have witnessed transitions away from dirtier sources of energy, like coal or oil in the power sector, to movements in our building sector to make our buildings significantly more energy efficient and in greatly reducing emissions for our transportation sector.” 

Varied Perspectives

Jessica Azulay, executive director of the Alliance for a Green Economy, said TENs are just one tool in the clean energy transition. 

Their value is that they help bring about a managed transition, in which everyone in a defined area can switch away from gas. The alternative path to building decarbonization is individual homeowners installing heat pumps, which is an unmanaged transition, and leaves the residents unable to afford heat pumps shouldering an increasing share of the cost of the gas infrastructure. 

“Obviously this is not an either-or; our transition is going to be multifaceted, but I think we’re going to be much better off if we use thermal energy networks as a major tool in our toolbox,” Azulay said. 

She noted the rate of heat pump adoption in New York would have to increase tenfold for the state to reach its building decarbonization milestones through heat pumps alone. 

Indu, the director of energy at the nearby University at Albany, described the situation at her campus, which essentially is a small city with a population that sometimes exceeds 20,000 in a diverse collection of 100-plus buildings spread across 500 acres. 

It’s an ideal place for TENs, and in fact there are two TENs in operation, but they are fossil powered and only about 70 to 80% efficient. A $30 million upgrade was included in the 2023-24 budget to change this, and better achieve the promise of TENs. 

A new high-efficiency electric centrifugal and heat recovery chiller connected to a new geothermal well field, new hot water system and new piping will reduce campus gas use 15%. 

“So, this idea of saying OK, seasonal thermal storage, moving it around, I don’t want to be burning gas or oil to create heat and I have this heat already,” Indu said. “All I have to do is store it and move it from one place to another. When you start thinking about it like that, [instead of] the 70 to 80% efficiency system, you’re talking 350 to 700% efficient systems.” 

It’s a win-win-win for the campus, community and planet, she added, and the efficiency is such that the operating budget will not increase. 

Vikas Anand, Danfoss vice president of climate solutions North America, keyed on the opportunities presented by efficiency. He cited the famous chart compiled by Lawrence Livermore National Laboratory showing more than half of U.S. energy consumption evaporating in the form of waste heat. 

A graphic representation of the estimated quantities of energy wasted in the United States. | Lawrence Livermore National Laboratory

“So, the opportunity for us to manage waste heat is so immense, that we can meet our climate goals as a country, I will say, very easily,” Anand said. 

The question was raised about how large commercial properties fit in these systems. 

“Most residential consumers don’t voluntarily pay for green,” Trent Berry of Reshape Infrastructure Strategies said. “That is more prevalent in the commercial sector because they’re competing for tenants” that have net-zero goals. Other factors making TENs attractive to commercial building owners include energy standards for new buildings and local regulations requiring energy efficiency or decarbonization. 

New York is the second-most unionized state, and officials include labor-friendly provisions in many of their initiatives. But where does the next generation of union members come from?  

John Murphy of the New York State Pipe Trades Association said it’s important the transition be framed as a path to the future rather than the end of an era for certain trades. People need to see a future they can plan a career around. 

“I think what’s most important is that when we have a certainty of work, we know that there’s a pipeline of work ahead. It allows building trades unions to recruit from the community, to be able to train the workforce — can’t happen without that work certainty,” Murphy said. 

“I can tell you, even for the workers and the members in my industry, when they say, ‘Where is our transition,’ we need to show them this is the path, this is the future, and it’s nothing to be afraid of, you can work here.” 

Eric Walker of WE ACT for Environmental Justice sought to focus on the many New Yorkers using energy they can’t afford, to the detriment of their health: 

New York

Eric Walker, energy justice senior policy manager at WE ACT for Environmental Justice | © RTO Insider LLC

“How are we going to think about these … technocratic solutions as ways to meet basic needs for people who are often not even discussed in the conversation around what our energy and economic development agendas are in the state? 

“I think of thermal networks really as one of many approaches to meeting a series of basic needs,” Walker said. “We have a really serious problem around energy affordability, and energy security across multiple types of buildings and demographics within the state. There are 3½ million [low- to moderate-income] households in the state that essentially qualify for some form of energy assistance. 

“And that is that’s really kind of scary, with about $1.7 billion of utility arrears that remain outstanding. And that to me signals a real need to invest in the kinds of interventions at the system level that provide the energy trilemma … sustainability, security and affordability.” 

Which leads once again to the question of who pays for it all. 

Much of the expected benefit of decarbonization would be societal and much of it would play out unevenly over years or decades in the form of avoided costs. 

The bill for the transition, by contrast, is concrete and inevitable. The only uncertainty is how much of it will fall directly on individual ratepayers and how much of it will be embedded in other things, such as taxes, fees and consumer costs. 

Walker said however the bill is allocated, it is worth the cost. 

“What we have is an environment where first cost is scaring people without any sort of contextualization for what the actual overall benefit is to every ratepayer in the system, every building owner in the system, to every community across the state,” he said. “If we do nothing, the costs only get bigger; if we do something, the net cost is much better than the first cost. It’s all about investment. … There’s no dollar that we spend at a societal level that doesn’t benefit us in some way.” 

The Timeline

Dix said later that the utility TENs pilot program is progressing well — even quickly by the standards of the regulatory world — but a lot of questions about its details are unanswered and some of the questions haven’t even been asked. 

Other details are moving targets, such as whether the state will remove the requirement that gas utilities connect new customers to gas lines for free if they are within 100 feet of the line. That’s on the table in budget negotiations. 

New York

Lisa Dix, New York director of the Building Decarbonization Coalition | © RTO Insider LLC

Dix said she appreciates the two-pronged approach. The theory behind the utility TENs bill was to get pilots moving forward, she said, “because we needed to learn from them, because we really are creating new utility models, an integration of the electric and gas utilities, maybe water. We’re creating all kinds of new customer engagement plans; we’re creating different ownership mechanisms.” Once the projects get going, the regulatory process is “going to be a year or two to get those rules all final and ready to go.” 

One thing that gives Dix hope is that the Utility Thermal Energy Network and Jobs Act, the impetus for the pilot projects and the forthcoming TENs regulatory structure, received near-unanimous legislative approval in 2022. Moreover, it wasn’t embedded in a budget package, the back-door route by which many contentious measures become law in New York state. 

“This was a very long effort where we worked together to focus on the solutions that unite us rather than divide us,” she said. 

The Public Service Commission set Case No. 22-M-0429 in motion in September 2022 with an order that the state’s seven largest investor-owned utilities propose one to five pilot TENs projects. 

By September 2023, they had submitted 14 widely varied proposals with a price tag of up to $435 million. 

At their meeting that month, the PSC judged those proposals good first efforts but insufficient in detail, and it issued an order providing guidance on how best to refine the proposals. 

In February 2024, the Department of Public Service published its proposal for initial utility TENs rules and invited public comment. The latest technical conference — on potential performance metrics — is scheduled for March 19. 

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FERC Watchers Weigh in as Transmission Rule Approaches Finish Line

All indications are that FERC is working to complete its transmission planning and cost allocation rulemaking in the next few months, with public statements from commissioners saying it’s a priority and those familiar with the agency placing bets on which month’s open meeting a final rule will be announced (RM21-17). 

With three nominees awaiting confirmation for the two open seats and that of Commissioner Allison Clements, whose term expires in June, sources said in recent interviews it might be best for FERC to act on the Notice of Proposed Rulemaking (NOPR) before its composition changes. (See Phillips: FERC to Issue Transmission Rule in ‘Very Near Future’.) 

“I think Commissioner Clements very much wants to be part of this,” former FERC Chair Jon Wellinghoff said. “So, I’m sure she’s doing everything she can to work with staff and work with the other two commissioners, to move this forward as quickly as possible.” 

The rulemaking could face a delay if it is not completed before the composition of the commission changes, said WIRES Executive Director Larry Gasteiger, a former FERC staffer. 

“This is an extremely complicated rulemaking effort that the commission is doing,” Gasteiger said. “And just for [the new members] to get up to speed on it, in order to knowledgeably vote on it, is inevitably going to take a couple of months minimum. That will be added time on the timeline for getting the rule out.” 

Another issue is uncertainty around November’s elections, with the House, Senate and White House up for grabs.  

Republicans could use the Congressional Review Act (CRA) to overturn a rule that is filed late in the Biden administration, said former FERC Chair Neil Chatterjee, now a senior adviser at law firm Hogan Lovells. Rejecting a rule requires votes of disapproval by both the House and Senate but can be blocked by the president unless his veto is overridden.  

“I don’t know if it’s constituted as a major rule, but I think the White House and FERC don’t want to take that risk,” Chatterjee said. “And I think that, certainly, there are steps the commission could take, if you had Republican majority control, that would try to change course on some of these rulemakings.” 

The commission currently has two Democrats, Clements and Chair Willie Phillips, and one Republican, Mark Christie. The three candidates nominated by President Biden last month would give Democrats a 3-2 edge. But if Donald Trump retakes the White House, he could replace Phillips, whose term expires in 2026, with a Republican. (See Biden Names 3 Nominees to Give FERC 5 Members Again.)  

Negotiations on the 11th Floor

FERC observers expect the three commissioners’ offices are exchanging ideas on what should be in the final rule — and that can take some time. (See related story, Groups Urge Inclusion of Cost Containment in FERC Tx Planning Rule.) 

Christina Hayes, executive director of Americans for a Clean Energy Grid, was a FERC staffer in 2011, the last time it made major changes to its transmission planning and cost allocation rules with Order 1000. 

“There was something like 40 hours where the commissioners’ advisers were talking and negotiating, before they were able to issue Order 1000,” Hayes said. “That’s something like two months of negotiation among commissioners’ offices on the 11th floor. So, I imagine they’re probably well into that process at this point.” 

The transmission rule came out of an advanced NOPR issued nearly three years ago, so the commissioners have been talking about the issues for some time, said Philip Moeller, executive vice president of regulatory affairs for the Edison Electric Institute. 

“Each commissioner is going to have their own set of priorities,” said Moeller, who was on FERC when it passed Order 1000. “And those are probably going to be negotiated and probably have been negotiated to some extent for at least the last couple of years.” 

To the extent that commissioners support the rule’s overall thrust — that the grid needs to expand to meet future needs —they will be working on compromises because the more consensus there is, the more robust the rule will be in the face of inevitable litigation, Moeller added. 

Impact of Dissents

In 2011, Moeller dissented on Order 745 over its compensation method for demand response (DR). Litigation over the rule wound up at the Supreme Court, which ruled against appeals that claimed FERC had overstepped its jurisdiction. (See Supreme Court Upholds FERC Jurisdiction over DR.) 

“It was kind of fun to have my dissent mentioned there during arguments,” Moeller said. “But I think ultimately the problem with that litigation, specific to 745, was that the main attack was on the jurisdiction. And that was really never an issue for me. For me, it was the level of compensation and how it was done. And unfortunately, the court focused solely on the jurisdiction and ruled that FERC had it.” 

The more complex issue of compensation — Moeller would have preferred a somewhat smaller payment for DR in energy markets — was largely ignored by the courts because litigants focused on jurisdictional questions over how DR is treated in state-regulated retail markets and federally regulated wholesale markets. 

Wellinghoff was the driving force behind Order 745 as chair of FERC at the time. While he did not convince Moeller, he did get a Republican vote from then-Commissioner Marc Spitzer. 

“To the extent those dissents are well written, and those dissents have legitimate reasons for objecting to portions of the order, they act as fodder for the appellant,” Wellinghoff said. “Those are things that they use as arguments in court, so they can be compelling in that way.” 

While partial dissents like Moeller’s on Order 745 are less of a threat to a rulemaking than a full dissent, Wellinghoff said judges will rule based on the legal arguments before them rather than counting votes of the commissioners. 

Cost Allocation

Ultimately, the public will see the outcome of all the behind-the-scenes debates when FERC publishes a final rule. When asked what that should look like, Grid Strategies President Rob Gramlich (another former FERC staffer) pointed to a letter Senate Majority Leader Chuck Schumer (D-N.Y.) wrote to the commission last summer. Schumer said the commission should prescribe the benefits that transmission planners must consider to ensure cost-effective transmission is built and costs are properly allocated. 

“Figuring out how they sort out cost allocation will be important — just to make sure that they stick to the beneficiary-pays approach, which is what the courts have said they need to do, and they don’t end up sticking too much of the costs on any one party or group,” Gramlich said. “And then making sure there’s a process to resolve disagreements.” 

FERC likely will give states chances to come to an agreement on cost allocation before the commission considers stepping in, Gramlich said.  

Asked about Clements’ thoughts on the NOPR, her office provided RTO Insider her response to Schumer. She said the commission aimed to develop a “comprehensive and durable approach” that leads to building the kind of infrastructure that has been underdeveloped in recent years. 

“I agree that cost allocation rules should endeavor to involve states, while at the same time creating incentives for collaboration and against free ridership,” Clements wrote. 

Christie has long argued against states paying for the policies of others. In a recent dissent, he argued that states generally should be held above other “stakeholders,” saying most of them are “rent-seeking special interests.” (See FERC Rejects Complaints from IMM, W. Va. PSC Arguing for Access to PJM Liaison Committee.) 

Figuring out how to balance competing policies — with some states seeking rapid progress toward net-zero emissions by midcentury and others wanting nothing to do with it — is a key issue commissioners are wrestling with, Moeller said. 

“If you see what New Jersey is doing with their offshore wind [transmission], they’re willing to pay for it themselves,” Moeller said. “So, it’s certainly doable under the status quo.” 

Chatterjee said the commission is likely to encourage states to take the lead in determining how public policy project costs are regionally allocated. “The fight will be over what is the dispute resolution mechanism,” he said. 

That is where Christie might wind up issuing at least a partial dissent if Chair Phillips can’t bridge any divides among the three members, he added. It will be hard to get states like Chatterjee’s home of Kentucky that have little interest in the energy transition to agree on a transmission plan with states that actively support the transition, he said. 

“I think for a state like Kentucky, the view would be we didn’t ask for these benefits, so we shouldn’t have to pay for them,” Chatterjee said. “And just because FERC is defining these benefits, that doesn’t mean that our ratepayers should bear the costs.” 

Will a Federal ROFR be Reinstated?

Another point of contention as the transmission rule nears the finish line is what to do about competition. Both Moeller at EEI and Gasteiger at WIRES would like to see the federal right of first refusal (ROFR) at least partly reinstated; it’s one of EEI’s priorities. 

WIRES recently released a report based on examples of 29 major projects around the country, arguing that collaboration is key to building out the transmission grid. The competition pushed by Order 1000 has served to discourage that collaboration, WIRES contends. 

“If you’re competing against your neighbor for the ability or the right to build a project, it doesn’t create the same incentives to share information or to work with them on trying to get a project built,” Gasteiger said. 

Wellinghoff, a champion of transmission competition in Order 1000, argued that pulling back on it now would reward bad behavior by incumbents.  

Order 1000 required transmission providers to remove from their FERC tariffs ROFRs on projects selected in a regional transmission plan for cost allocation. It did not affect the right of incumbent transmission providers to upgrade their local facilities. 

“There just needs to be, perhaps, more oversight,” Wellinghoff said. “There needs to be more consideration that perhaps even these smaller lines need to be competitive. I’m not sure that the exemption that we put in the original Order 1000 is appropriate. I believe that these lines can be bid competitively and developed and constructed competitively and we would come out better for it.” 

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NW Freeze Response Shows WEIM Value, CAISO Report Says

CAISO’s Western Energy Imbalance Market (WEIM) played a crucial role in managing energy flows around the West to help support Northwest utilities during an extreme cold snap in January, according to a new report from the ISO describing its response to the winter weather storm. 

The 80-page report released March 6 represents the latest volley in an ongoing skirmish among Western electricity sector stakeholders over exactly what occurred on the regional grid during the Jan. 12-16 deep freeze.

“The cold-weather event again demonstrated the benefits of the Western Energy Imbalance Market, an interstate electricity market that covers much of the West,” CAISO said in the report. “The market’s diversity of weather and generating resources allows Western regions to aid each other during winter and summer peak demand periods.” 

The event plunged the Northwest into near-record cold and triggered five energy emergency alerts (EEAs), including one critical EEA 3, which requires a utility to prepare for rolling blackouts to protect its system. 

It has provoked a debate in the Northwest over how vital CAISO and its WEIM were in supporting the region during the storm, or if other factors were more important. The dispute has become a stand-in for the contest between CAISO’s Extended Day-Ahead Market (EDAM) and SPP’s Markets+ and the related disagreement over whether the Bonneville Power Administration and other Northwest entities should join a single Western electricity market based on EDAM or continue to help SPP develop its alternative. (See NW Cold Snap Dispute Reflects Divisions over Western Markets.) 

Analyses from the Western Power Pool, the Public Power Council (PPC) — which represents the Northwest’s publicly owned utilities — and others have downplayed CAISO’s role. They’ve pointed to interchange data showing that most of the generation that rescued the Northwest originated in the Rockies and Southwest regions — and not California. That was evidenced by the fact that CAISO itself was a net importer of energy during the five-day weather event. (See WPP: Cold Snap Showed ‘Tipping Point’ for Northwest Reliability.) 

CAISO’s report hits back at that assertion — and other complaints about the ISO’s response — by explaining the mechanisms that directed the movement of electricity across the WEIM over the course of the cold snap.  

The report says the WEIM “economically rebalanced supply across the West to meet increasing demand as real-time conditions evolved over the Martin Luther King Jr. Day weekend.” 

“The market identified least-cost solutions within the wider WEIM footprint, transferring lower-cost electricity from the Southwest into California,” it says. “These transfers allowed exports scheduled in the day-ahead and hour-ahead markets to flow to the Northwest, replacing more expensive generation while managing congestion on key transmission lines.” 

CAISO notes that its hourly exports in the day-ahead and real-time markets “increased significantly” during the event, exceeding 6,000 MW. 

“CAISO became a net exporter over the Martin Luther King Jr. Day weekend for all hours of the day, excluding WEIM transfers,” the report says. 

The ISO said WEIM transfers into the CAISO area were not the result of limited supply within CAISO but rather a function of the “economic displacement and opportunities optimized by the market and bounded by the transmission and transfers availability in the wider footprint.” 

Congestion Response

Several factors were at play during the freeze, which the report notes. They included derates on the Pacific AC (PACI) and DC (PDCI) interties, generation outages and a fault in a fiber optic cable that caused Washington’s Jackson Prairie natural gas storage facility to briefly halt sendout Jan. 13, prompting pipeline operator Williams to declare a force majeure that cut deliveries to interruptible customers, including some power generators. 

The ISO notes that day-ahead prices surged in the Northwest bilateral market, with Mid-Columbia peak prices hitting $934/MWh on Jan. 13 while off-peak spiked to $927/MWh. While prices rose at the West’s other major trading hubs (NP-15 and SP-15 in California and Palo Verde in Arizona), they never exceeded $250/MWh. The power price spikes in the Northwest in part resulted from the region’s high spot natural gas prices, but gas prices also were elevated in California. 

Graph shows how significantly bilateral prices spiked at the Northwest’s Mid-Columbia trading hub during the winter weather event. | CAISO

As Fred Heutte, a senior policy associate with the Northwest Energy Coalition, explained in a recent interview with RTO Insider, the price differentials created a situation in which Northwest load-serving entities looked south for cheaper supply. The CAISO report shows the WEIM did the same.

“First, the WEIM market relied on the most economic supply available which was located in the Southwest; in turn, these import transfers displaced generation in California, which has been priced more expensively given higher gas prices,” the CAISO report said. “Second, there were transmission limitations to afford additional exports or WEIM exports transfers to the Pacific Northwest because Malin [PACI] capacity was already fully scheduled, and no exports could flow on NOB [PDCI].” 

During some intervals, northbound segments of Path 15 in California also experienced congestion, limiting flows into Northern California and the Northwest. 

The CAISO report additionally addresses a complaint by the PPC that congestion revenue rights (CRR) holders in the ISO’s market financially benefited from $125 million in congestion rents collected on interties into the Northwest during the freeze, while owners and capacity rights holders on the northern portions of those lines earned nothing. 

“Before January, participants bought more than 900 MW of CRRs in anticipation of potential northbound congestion on California’s northern boundary,” the ISO’s report says. “None of these rights were held by external load-serving entities, such as Northwest utilities, although they could have obtained the CRRs through the CAISO’s CRR auction or the allocation process that provides CRRs for free to qualifying load-serving entities.” 

The report additionally notes that CAISO is the only Western balancing authority in the West “that manages transmission congestion through electricity prices at specific locations in its day-ahead market.” 

“Congestion in the Northwest can still result in higher prices, but those costs are not as visible to market participants as they are in the CAISO market,” the ISO said. 

In the report, the ISO points out that EDAM “provides additional mechanisms for managing congestion on either side of balancing area borders for participating entities and provides transparency on the distribution of congestion revenues collected through nodal pricing. The EDAM will be able to help Pacific Northwest transmission operators better manage and allocate the costs of congestion on their systems.” 

CAISO said it will discuss the report’s findings during a March 11 public meeting.  

RTO Insider will provide additional coverage of the report after having more time to delve into its analysis. 

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Groups Urge Inclusion of Cost Containment in FERC Tx Planning Rule

A coalition of transmission, utility and consumer advocates on March 6 recommended that FERC incorporate cost management protocols into its final rule on transmission planning and cost allocation (RM21-17). 

The group — which includes the Electricity Consumers Resource Council (ELCON), the Large Public Power Council (LPPC), Americans for a Clean Energy Grid (ACEG), the Clean Energy Buyers Association (CEBA) and the National Association of State Utility Consumer Advocates — hosted a webinar to endorse a proposal requiring that transmission providers incorporate cost-benefit reporting mechanisms throughout their projects’ lifecycles. 

It urged FERC to mandate that providers periodically file cost allocation reports tracking anticipated project costs against initial projections. Under the proposal, if a provider’s publicly filed report reveals that a project’s costs have either exceeded a predefined threshold percentage of its original projected cost or fallen below an approved benefit-cost ratio, a process administered by an RTO or ISO would be initiated to reconsider the project’s cost allocation to prevent consumers from bearing undue financial burdens.  

“Instilling greater transparency and cost discipline in transmission development protects consumers from undue costs and provides assurances that consumers will benefit throughout the life of the project,” ELCON CEO Karen Onaran said in a press release. 

John Di Stasio, president of LPPC, said the proposed provisions would ensure that transmission projects approved through the regional planning processes undergo “a cost-benefit analysis not just at the outset, but [also] throughout the life of construction, because at the end of the day, consumers are the ones who bear the cost of new infrastructure, and we want to make sure there is oversight on their behalf.” 

The group proposes that FERC’s final rule establish a reconsideration threshold at 25% or more above the projected cost allocation. This reconsideration process would allow project sponsors to justify their cost deviations and present mitigation plans, until construction. 

“This rule would require planners to take a long-term look at the changing circumstances and plan for all economic or reliability benefits and adopt some sort of backstop or dispute resolution for cost allocation,” said Christina Hayes, executive director for ACEG. 

“We’re no longer just talking about an energy transition, but we’re talking about a grid expansion,” said Bryn Baker, senior director of CEBA. “And this grid expansion means that we cannot just be talking about adding new generation, but we have to talk about moving the cheapest available electrons to where they’re needed.” 

The commission issued a Notice of Proposed Rulemaking last year to change how transmission planning and cost allocation processes are conducted to help build out the grid in the long term. The docket has received a barrage of comments, reports and appeals from industry groups, politicians and transmission stakeholders urging that FERC’s final rule should allow for regional flexibility; not hinder ongoing innovation; consider factors related to competition, consumers and transparency; and be issued by year-end, among other recommendations. (See FERC Gets Dueling Competition Studies in Transmission NOPR Docket.) 

“Striking a balance between advancing clean energy goals and protecting consumers from unforeseen costs is essential as FERC considers large-scale regional transmission planning,” Di Stasio said. 

During the webinar a reporter asked how the group arrived at the 25% reconsideration threshold and if it could unreasonably slow down project approvals. 

Di Stasio replied that the group has discussed with FERC how “these protocols could create a barrier” but added that “if it’s clear at the outset and there’s ongoing monitoring and recording, it still gives an opportunity for projects to continue” and “[the threshold] shouldn’t necessarily slow anything down and, in fact, gives us greater confidence in whatever gets approved.” 

Hayes added that “this proposal makes sure that we’re very clear-eyed about the costs and benefits as we go through planning and makes sure that, should things go awry, there’s a check in that process.” 

The 25% figure is “not necessarily a line drawn hard in the sand,” Baker concluded. “But the point of the entire exercise is to say if costs have increased that much, let’s just have a quick check.”