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January 7, 2025

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Utilities Seek Rehearing of Order 1920-A’s Accommodations for States

Transmission owners filed requests for rehearing of Order 1920-A with FERC over the holiday break, saying the commission went too far in giving state regulators a role over cost allocation (RM21-17). 

“This decision compels utilities to include, in compliance filings, cost allocation proposals they may neither sponsor nor support as well as consult with relevant state entities in specific circumstances,” Edison Electric Institute said in its filing. “In addition to the legal infirmities, these are not necessary to achieve the commission’s stated goal of meaningful state involvement, a goal EEI supports.” 

EEI said it is seeking rehearing on limited issues “to ensure the statutory rights of transmission providers are not eroded and that Order 1920 is legally durable.” 

Order 1920 required transmission planners to let state regulators in their footprint work on a cost allocation scheme, but Order 1920-A went further in requiring transmission planners to file that even if they disagree with what the states come up with. 

“The commission declares that it will not be required to adopt the transmission provider’s proposal on compliance, ‘even if that proposal complies with the final rule’s requirements,’” EEI said. “Rather, the commission states that it need only select a replacement rate that complies with the final rule and that is adequately supported in the record.” 

EEI also opposes Order 1920-A’s requirement that transmission providers consult with state regulators when they want to change cost allocation methods in the future after they already have complied with the rule. 

The investor-owned utility trade group argued that by requiring transmission planners to file state-backed cost allocation methods under the Federal Power Act’s Section 206, Order 1920-A encroaches on their Section 205 rights as public utilities. The requirement to consult on future changes also encroaches on utilities’ rights under Section 205, EEI said. 

EEI said the decision in Atlantic City Electric Co. v. FERC from 2002 effectively bars FERC from forcing utilities to file states’ cost allocation methods, or consulting with them on future changes. 

“By requiring the public utilities to file the relevant state entities’ proposals, the commission is requiring those public utilities to cede their statutory rights to make filings under the FPA to the relevant state entities and to provide those entities with statutory rights that Congress did not intend them to have,” EEI said. 

The authority to establish a replacement rate does not authorize FERC to provide state regulators with statutory authority reserved solely for public utilities, nor does it authorize FERC to require public utilities to cede those rights to state regulators, it added. 

WIRES Group also filed a request for rehearing on the more state-friendly changes in Order 1920-A, saying the changes exceed FERC’s authority. 

“The commission has no ratemaking or rate setting authority under FPA section 205,” WIRES said. “Section 205 simply vests the commission with the power to review such rates as made by public utilities and to modify them upon a finding of unlawfulness. The power to initiate rate changes rests with the public utility alone, and the commission cannot limit or prohibit public utilities from filing changes in the first instance.” 

The intent of the law was to let public utilities act quickly without obstacles. Courts have recognized that a public utility’s Section 205 filing rights cannot be restricted by requiring negotiations or consultations. 

The National Rural Electric Cooperative Association filed rehearing on the issue but takes a different angle in noting that state regulators often do not oversee its members or public power utilities. 

“Under the laws of many states, the democratically elected boards of directors of electric cooperatives establish the cooperative’s rates independently of a state utility commission,” NRECA said. 

Unlike its investor-owned counterparts, NRECA would not oppose states’ greater roles, but the definition of “relevant state entities” needs to be expanded. Co-ops are mostly regulated by elected boards of directors. 

“The commission should clarify or modify the Order No. 1920‑A to require that all electric consumers in a state are comparably represented,” NRECA said. “Arbitrarily excluding, or allowing a planning region to exclude, the representatives of some electric consumers from the more robust process created by Order No. 1920‑A is clearly unreasonable, and the commission provides no reasonable justification for it given the stated purpose of Order No. 1920‑A’s modifications to the Final Rule.” 

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NV Energy’s Greenlink West Poised for Progress in 2025

With approvals falling into place for NV Energy’s Greenlink West project, construction of the 472-mile transmission line is expected to ramp up in 2025. 

The Public Utilities Commission of Nevada (PUCN) on Dec. 20 approved a construction permit for Greenlink West, a 525-kV line that will run along the west side of the state from the Las Vegas region to Yerington in Northern Nevada. The project also includes three 345-kV lines from Yerington to the Reno/Sparks area. 

And on Dec. 31, the PUCN approved a construction permit for a related project: a 10-mile, 345-kV line between the Comstock Meadows and West Tracy substations in Northern Nevada. 

In its application, NV Energy said the Comstock Meadows to West Tracy line must be in service before Greenlink West is finished. The new line will prevent an overload of 120-kV lines when a Greenlink component — a 345-kV line from Fort Churchill to Comstock Meadows — is completed. 

In addition, NV Energy said the line is needed “based on the total load growth in the Tahoe Reno Industrial Center.” The TRI Center is home to Tesla Gigafactory 1, Google, data center company Switch and other businesses. 

NV Energy’s Greenlink Nevada project consists of Greenlink West along with Greenlink North, a planned 235-mile east-west line across the north side of the state. The two Greenlink lines will connect with NV Energy’s existing One Nevada Line, a north-south line along the eastern side of the state, forming a transmission triangle around Nevada. 

Greenlink is seen as a way to improve reliability and promote development of renewable resources in the state. 

The Bureau of Land Management issued a record of decision approving Greenlink West in September. (See BLM OKs NV Energy’s Greenlink West Line.) 

Greenlink West construction is expected to start in the first quarter of 2025 with a targeted in-service date of May 2027.  

For Greenlink North, a comment period for the draft environmental impact statement (EIS) ended Dec. 11. BLM has set target dates of April 11 for publishing the final EIS and July 31 for issuing a record of decision on the project. 

NV Energy expects Greenlink North to be in service by December 2028. 

In 2024, NV Energy bought land next to its Fort Churchill Power Plant near Yerington to build the Walker River substation. The Greenlink West and North lines will meet at Fort Churchill, and NV Energy calls the Walker River substation the “hub” of the Greenlink project. Clearance and grading of the site began in September, NV Energy said on its website. The utility expects the substation to be completed in 2025. 

‘Continued Approval’ Sought

In a separate action Dec. 20, the PUCN declined NV Energy’s request for “continued approval” of the Greenlink project and approval of a $4.128 billion cost estimate, which doesn’t include one of the project’s 345-kV segments.  

Greenlink’s projected cost has ballooned since a cost estimate of $2.484 billion in 2020. NV Energy has blamed inflation, environmental mitigation and other factors for the increase. (See NV Energy IRP Describes $1.76B Cost Jump for Greenlink Projects.) 

The request for “continued approval” was made as part of the utility’s integrated resource plan filed in May. 

In an order approving parts of the IRP, the commission noted it had already approved all the components of the Greenlink project. There’s nothing in Nevada statute that requires “continued approval” of a project that’s being developed, the commission said in its order. 

“‘Continued approval’ implies a presumption of prudence,” the commission said in its order. “The commission does not find it reasonable or in the public interest to grant a request that equates to a prudency approval for unvetted costs.” 

Instead, the Greenlink costs will undergo a prudency review during a general rate case, the commission said. 

The commission did grant NV Energy’s request for critical facility designation for Greenlink West, a designation that was previously granted for Greenlink North. 

Greenlink is needed to protect reliability, is critical to the development of renewable energy resources and will allow energy transfers between northern and southern Nevada, the commission said. 

But the commission said the utility’s request for a construction work in progress (CWIP) incentive should be addressed in a general rate case rather than in the IRP. 

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ERCOT Finds Little Interest in MRAs for San Antonio Units

ERCOT’s request for must-run alternatives (MRAs) for cost-effective solutions to the congestion problems in San Antonio did not receive any responses by a Dec. 30 deadline, putting the solicitation in serious doubt. 

The Texas grid operator said Dec. 31 that given the absence of questions about its request for proposals, it will not post answers or further amendments to the solicitation or other related documents by the Jan. 8 deadline. It will issue a market notice on that date if it determines an amended request is necessary. 

A previous solicitation for an MRA to the Braunig units resulted in one response: a 200-MW, multihour energy storage resource. 

ERCOT is seeking a more cost-effective option than entering into an agreement to use the mobile generators CenterPoint Energy has offered or committing CPS Energy’s Braunig Units 1 and 2 under a reliability-must-run (RMR) contract. (See “ERCOT to Pursue Braunig MRAs,” Texas PUC Shelves PCM Design Over Lack of Benefits.) 

Staff are pursuing an RMR contract, ERCOT’s first since 2016, with Braunig’s largest gas resource, Unit 3. The resource has a 412-MW maximum summer rating. Units 1 and 2 have a combined summer rating of 392 MW. 

CPS, San Antonio’s municipal utility, told ERCOT last year that it planned to retire the three gas units, which date back to the 1960s, in March 2025. However, the grid operator said the plant’s units were needed for reliability. (See ERCOT Evaluating RMR, MRA Options for CPS Plant.) 

ERCOT says the RMR units will be important in addressing the South Texas export interconnection reliability operating limits (IROLs) staff established last year. Staff’s analysis revealed that under certain conditions, such as when high system demand coincides with an outage of a major transmission line or one or more generation units, lines that deliver power from South Texas into San Antonio could be overloaded and possibly lead to cascading outages. 

ERCOT has been in discussions with CPS, CenterPoint and Life Cycle Power over moving 15 large generators and their 450 MW of capacity from Houston to distribution sites in the San Antonio area. The generators, which range between 27 and 32 MW, would provide a less expensive alternative to the $56 million that CPS says it will take to overhaul and continue running Braunig’s other two units. 

PUC Opens Application for Completion Bonuses

The Texas Public Utility Commission began accepting applications on Jan. 1 for completion bonuses of dispatchable, or thermal, energy under the Texas Energy Fund (TEF). 

The fund’s Completion Bonus Grant Program provides performance-based grants to qualifying projects for the construction of new dispatchable generating facilities in ERCOT or the addition of new dispatchable units at existing facilities in the grid operator’s territory. Qualifying projects will add at least 100 MW of new dispatchable generation capacity to the ERCOT grid, the PUC said. 

The TEF’s In-ERCOT Generation Loan Program has received 18 applications for 9.72 GW of potential new generation seeking $5.34 billion in loans. The Texas legislature has allocated $5 billion to the fund. 

The fund was established by state law and approved by voters in 2023. It offers a low-interest (3%) loan and grant program of up to $7.2 billion for dispatchable generation, alongside three other separate programs. 

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EDAM Won’t Eliminate WEIM-only Option, CAISO CEO Says

CAISO’s launch of the Extended Day-Ahead Market (EDAM) will not spell the end of a Western real-time-only offering from the ISO, according to CEO Elliot Mainzer. 

“Participation in the EDAM is voluntary, allowing an entity participating in the Western Energy Imbalance Market (WEIM) to extend its participation to EDAM, to remain only in the WEIM, or to exit one or both markets for any reason,” Mainzer wrote in a Dec. 23 letter addressed to the Bonneville Power Administration.  

“While participation in EDAM necessarily requires that an entity also participate in the WEIM, we remain fully committed to maintaining support for the WEIM indefinitely,” he wrote. 

Mainzer’s letter comes in response to a statement BPA Administrator John Hairston made in his own Dec. 13 letter to Seattle City Light CEO Dawn Lindell, which defended the federal power agency’s continued preference for joining SPP’s Markets+ despite the findings of a BPA-commissioned study showing the agency would realize greater financial benefits from participating in EDAM. (See BPA Touts Markets+ in Response to Seattle City Light Opposition.) 

The production cost study by Environmental and Energy Economics (E3) examined a variety of market scenarios, including a “business as usual” case in which Western entities continue to trade day-ahead electricity in the bilateral market while remaining in their existing real-time markets (either the WEIM or SPP’s Western Energy Imbalance Service) — a scenario in which BPA would realize an estimated $138 million in annual benefits.  

But Hairston’s letter to Lindell noted that BPA expects the existing benefits of the real-time WEIM — in which BPA is a participant — to “erode” as many of its members begin to participate in either of the organized day-ahead markets. 

“As EIM entities move to the Extended Day-Ahead Market (EDAM) proposed by … CAISO, there is no guarantee WEIM will continue to be offered as a standalone program, which is a risk to the potential benefits and long-term viability of a WEIM-only scenario for Bonneville,” Hairston wrote. 

Mainzer’s letter looks to be intended to counter that assertion. 

“We fully expect that some balancing authorities in the West will choose to remain in WEIM without joining EDAM,” he wrote,” he wrote. “These entities would continue to submit base schedules in WEIM as they do today and would be optimized across the entire real-time market footprint, including both entities participating only in WEIM and those participating in EDAM after it launches.” 

The Dec. 19 letter also provided a platform to Mainzer to contrast CAISO’s “incremental” approach to market participation with that of Markets+, which will require its members to participate in both a real-time and day-ahead market and join the Western Power Pool’s Western Resource Adequacy Program (WRAP).  

BPA and most of its “preference” customer base of publicly owned utilities have pointed to the WRAP requirement as a key factor in their assessments favoring Markets+.   

But Mainzer said CAISO has designed its markets in part to factor in the “diversity” of the West and allow its participants to make the decisions that work best for them and their customers.” 

“For example, just as we do not require entities to migrate from WEIM to EDAM, there is also no mandate for market participants to join a particular resource planning or resource adequacy program. Instead, the Western energy markets have been specifically designed to accommodate the decisions of our partners that work best for their unique circumstances.” 

Mainzer’s letter marks the first time CAISO has weighed in formally on BPA’s day-ahead market decision process since the agency initiated the effort in July 2023. BPA staff expect to issue a draft market decision in March followed by a final decision in June. 

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PJM MRC/MC Briefs: Dec. 18, 2024

MARKETS AND RELIABILITY COMMITTEE

Stakeholders Endorse Changes to Accounting of Demand Response in Load Forecasts

VALLEY FORGE, Pa. — The Markets and Reliability Committee endorsed by acclamation a quick fix proposal to account for errors in the availability of load management when calculating the unrestricted peak loads component of the load forecast. (See “First Read on Quick Fix for Revising Load Drop Estimate Inputs,” PJM MRC/MC Briefs: Nov. 21, 2024.) 

PJM’s Andrew Gledhill explained that when PJM incorporates hourly load data in the forecast, it produces estimated load drops that intend to determine what load would have been if not for load management deployments. In some instances, however, emergency conditions may be initiated at times when consumers participating in DR programs already have reduced demand. 

He gave the example of the December 2022 Winter Storm Elliott, which saw several blocks of performance assessment intervals (PAIs) declared around Christmas — including during night-time hours — when industrial and commercial DR customers were operating at reduced capacity independent of grid conditions. (See PJM Recounts Emergency Conditions, Actions in Elliott Report.) 

The revisions to Manual 19: Load Forecasting and Analysis, modify two paragraphs to grant PJM flexibility in identifying when the standard load drop estimates may be inaccurate and to apply alternatives. The language also would clarify how the estimates are used in producing the annual forecasts. 

Several stakeholders argued the language was overly broad and more detail would be needed on what methodologies PJM would use and transparency for stakeholders on when they are invoked. Gledhill said there is no one-size-fits-all and PJM prefers to keep its options open-ended. 

Calpine’s David “Scarp” Scarpignato and Gabel’s Rebecca Stadelmeyer offered amendments to the language that would direct PJM to present stakeholders with information should it use the discretion the revisions would offer. Gledhill accepted such an amendment.

Vote on Site Control Requirements Deferred

Stakeholders voted to delay action on revisions to Manual 14H: New Service Requests Cycle Process, which would codify PJM’s interpretation of the site control rules for planned resources in the interconnection queue. Several developers have called PJM’s interpretation overly strict and argued it would require them to retain unnecessary land. (See “Stakeholders Endorse Quick-fix Revisions to Site Control Manual Requirements,” PJM PC/TEAC Briefs: Dec. 3, 2024.) 

EDF Renewables Director of Transmission Policy Emma Nix said delaying would allow manual revisions to be informed by a complaint filed by the American Clean Power Association, Solar Energy Industries Association and Advanced Energy United, which argues PJM’s interpretation of the site control rules in the tariff do not conform to its language and would present unnecessary development costs (EL25-22). Nix motioned to have the item removed from the MRC’s consent agenda. 

PJM’s Jason Shoemaker said the application window for Transition Cycle 2 closed Dec. 17 and staff seeks to implement the language quickly to provide developers with clarity on the rules. He added that the vote would not be an end to the RTO’s ongoing conversations with developers on site control requirements. 

“These developers need to have some understanding of how their projects are going to be moved through the process,” he said. “We’d like to see the vote go forward today because it does impact our developers today.” 

The revisions would allow parcels to be removed from a project so long as it continues to meet the minimum acreage and energy output listed in the project application. Land could be added to a project at Decision Point 1 so long as either it is adjacent to the site, or evidence of easements is provided. If the energy output is reduced, the land requirements also correspondingly would go down. 

The revisions would seek to clarify language stating there are no specific site control evidentiary requirements associated with Decision Point 2 to specify that “site control must be maintained throughout the cycle process.” A note also would be added stating that parcels can be added similarly to DP1, with the caveat that a one-year term would be imposed from the end of Phase 2 of the relevant study cycle. 

No additions would be permitted at the final Decision Point 3, but reductions would be allowed so long as the acreage-per-megawatt and evidentiary requirements continue to be met. Once a generator interconnection agreement is signed, any site control changes would require a necessary study agreement (NSA) to determine permissibility. 

The revisions also would correct Exhibit 10 in the manual, which inadvertently used a diagram from another exhibit when describing how generators interconnect to existing transmission substations.

Discussions on CETL Shifted to ELCC Task Force

The committee endorsed a change to an issue charge to charge the newly formed Effective Load Carrying Capability Senior Task Force (ELCC STF) with addressing a “disconnect” between PJM’s winter-focused accreditation and the use of summer peaks when calculating zonal capacity emergency transfer limits (CETL). (See “Stakeholders Endorse LS Power Issue Charge on CETL,” PJM PC/TEAC Briefs: Nov. 6, 2024.) 

Endorsed by the Planning Committee on Nov. 6, the issue charge originally assigned the work to the PC. But ELCC STF Chair Michele Greening said PJM staff found there is a lot of synergy between the CETL discussions and the other two topics the task force is addressing, both on substance and timelines. 

The task force also is in the early phases of working on issue charges addressing the transparency of the ELCC model and how it is used to determine resource accreditation. Both were approved by the MRC during its Oct. 30 meeting. 

The revisions to the CETL issue charge also extended the work timeline to target a FERC filing in May 2025, rather than the first quarter of 2024. 

First Read on Extended Notification Requirement for Deactivating Generation, Changes to Compensation

PJM’s Chantal Hendrzak presented a first read on proposed changes to PJM’s rules for deactivating resources, extending the notification they must provide PJM before they can go offline, increasing the amount of data that is posted publicly and revamping the compensation for units that enter reliability-must-run (RMR) agreements. (See PJM Stakeholders Delay Vote on Generator Deactivation Rules.) 

The tariff revisions would require generation owners to provide 12 months’ notice ahead of their desired deactivation date, in addition to the existing must-offer exception deadlines on units that would not participate in the capacity market. PJM would publish publicly the estimated RMR revenue allocation zonal rate for zones that would be affected by an RMR agreement; postings also would be expanded to include Independent Market Monitor determinations on market power, deactivation response letters and RMR agreement notifications. 

The $2 million cap on project investments that can be included in the deactivation avoidable cost rate (DACR) would be eliminated and the scaling element of the yearly adder on investments would be shifted to a static 10%. A provision that replaces the DACR with the daily deficiency rate if the DACR and multiplier are greater than the deficiency rate also would be removed. 

The proposal is one of three the Deactivation Enhancement Senior Task Force (DESTF) voted on in October, carrying 69% support and winning out over a second PJM-sponsored package with fewer changes to compensation and a proposal from the Monitor that would have limited RMR agreements to five years and required stakeholder notification of agreements at least a year in advance.

Several Manual Revisions Endorsed

PJM’s Ryan Nice presented a slate of revisions to Manual 1: Control Center and Data Exchange Requirements, expanding its backup and emergency communication modes, as well as changes drafted through the document’s periodic review. The committee is set to vote on endorsement at its Jan. 23 meeting.  

He said the AltSCADA communication process allows inter-control center communications (ICCP) links to be transmitted between PJM and transmission owners using simple spreadsheet files in the event that default SCADA software is offline, such as through a cyberattack. The changes also include an expansion of the RTO’s read-only mode that prevents ICCP data from being edited during planned maintenance windows where the risk of incorrect data being submitted is increased. 

The periodic review changes include updating definitions to be clearer and more consistent with other manuals. 

PJM’s Liem Hoang presented a set of revisions to Manual 38: Operations Planning, to include information about the Operational Planning Analysis used in the Day-ahead Market and specify that CEII access is necessary to review the analysis. The language is set to be considered by the Operating Committee on Jan. 9 and the MRC on Jan. 23, with immediate implementation if approved.  

PJM’s Susan Kenney presented a set of revisions to Manuals 27 and 29 to remove outdated references, make grammatical corrections and add a description of how the non-zone network load responsibility is assigned to network customers in Manual 27. The MRC is set to vote on the changes Jan. 23. 

MEMBERS COMMITTEE

Sector Representatives and MC Vice Chair Elected

The Members Committee voted to elect representatives to serve on the Finance Committee for its 2025 term, sector whips and named Steve Kirk of NextEra Energy Marketing to serve as MC vice chair. American Municipal Power’s Lynn Horning will be chair of the committee. 

The new sector representatives on the Finance Committee will be: Susan Bruce, of the PJM Industrial Customers Coalition, representing end use customers; Jeff Whitehead, of Eastern Generation, representing generation owners; Steve Kirk, representing other suppliers; and Laura Yovanovich, of PPL Utilities, representing transmission owners. 

The sector whips for 2025 will be: 

    • John Rohrbach, of the Southern Maryland Electric Cooperative (SMECO), for the electric distributor sector. 
    • Greg Poulos, of the Consumer Advocates of the PJM States (CAPS), for the end use customer sector. 
    • David “Scarp” Scarpignato, of Calpine, for the generation owner sector. 
    • Sean Chang, of Shell Energy North America, for the other supplier sector. 
    • Jim Davis, of Virginia Electric & Power Co., for the transmission owner sector. 

PJM Presents Manual Language Detailing Process After FERC Rejection of Stakeholder Packages

PJM presented a first read on a proposal to revise Manual 34: PJM Stakeholder Process to establish a standardized path for PJM to follow when FERC rejects a stakeholder-endorsed proposal. The language is set to be voted on during the committee’s Jan. 23 meeting, with AMP and the Delaware Division of the Public Advocate intending to move and second the motion. 

Acting on its own accord or stakeholder request, PJM could hold a presentation within 90 days of the order on the commission’s rejection and recommend how to proceed. The proceeding discussion would include all possible stakeholder options, such as restarting the stakeholder process, identifying changes that could be made, new proposals or any other decision decided the senior standing committee agrees on. 

Greening said the manual is currently silent on how PJM and stakeholders should proceed after the commission rejects a proposal, leading to instances where there was disagreement on next steps. One such instance followed FERC denying a proposal to implement multi-schedule modeling by using a formula to select energy market offers to be entered into the Market Clearing Engine. The original proposal was rejected by the commission in March, and PJM opted to bring the alternative that received the second-highest vote count for endorsement. (See “Monitor, PJM Present Processes to Enable Multi-schedule Modeling,” PJM MRC/MC Briefs: June 27, 2024.) 

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Feds Sue PacifiCorp over 2020 Oregon Wildfire

The Department of Justice alleges that PacifiCorp’s failure to maintain its power line equipment caused the 2020 Archie Creek Fire that burned over 131,000 acres and resulted in hundreds of millions of dollars in damages to government property, according to a lawsuit filed in the U.S. District Court for Oregon on Dec. 19.

The government claims PacifiCorp did not take proper safety precautions to mitigate wildfire risks in violation of a license granted to the company by FERC, which allows the utility to operate power lines on federal land.

The U.S. Attorney’s Office seeks costs and damages associated with the fire.

The Archie Creek Fire burned for nearly eight weeks between Sept. 8, 2020, and Oct. 31, 2020. The fire consumed approximately 131,000 acres, including over 67,000 acres of federal land. The complaint does not specify how much the fire cost the government but notes costs amounted “to hundreds of millions of dollars,” according to the suit.

“During the approximately six weeks it burned, the Archie Creek Fire caused significant damage to federally owned and managed forest lands, timber, natural resources, wildlife habitat, trails, roads, bridges, campgrounds, and other infrastructure,” the government contends. “The United States incurred substantial suppression costs, reforestation and restoration costs, stabilization costs, and suffered devastating infrastructure and other damages, including without limitation ruined wildlife habitat, natural resource destruction and timber loss.”

PacifiCorp spokesperson Simon Gutierrez told RTO Insider in an email that the utility has cooperated with the government to resolve claims associated with the Archie Creek Fire.

“It is unfortunate the U.S. government decided to file a lawsuit in federal district court, however PacifiCorp will continue to work with the U.S. government to find reasonable resolution of this matter,” Gutierrez wrote.

Specifically, the suit claims PacifiCorp failed to take necessary precautions despite warnings issued by the National Weather Service about elevated fire risk dangers. The Archie Creek Fire ignited after an aluminum Ampact wedge connector melted. The government alleges the same type of connector was behind previous fires along transmission line equipment owned by PacifiCorp.

Shortly after the fire started, PacifiCorp reenergized a distribution line in a rural residential area while a tree was leaning on the line. The tree became engulfed in flames, and the fire quickly spread and merged into the Archie Creek Fire, according to the suit.

The complaint also details allegations from the Oregon Public Utilities Commission and FERC, claiming PacifiCorp “committed upwards of 250 vegetation clearance violations annually” in the years leading up to the Archie Creek Fire.

Similarly, following an investigation launched after a 2012 Utah fire, FERC claimed at least 45% of PacifiCorp’s transmission lines “were so poorly maintained or obsolete that they should not have carried any electrical current,” according to the suit. (See PacifiCorp Faces $42 Million Penalty for Line Misratings.)

The U.S. Attorney’s Office for the District of Oregon declined to comment.

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NY Well Positioned to Push Forward on Climate Goals Under Trump

President-elect Donald Trump has been an outspoken opponent of renewable energy, calling the sector “a scam” on the campaign trail and pledging to halt offshore wind energy projects.

“We are going to make sure that that ends on Day 1,” Trump said in a May speech according to the Associated Press. “I’m going to write it out in an executive order. It’s going to end on Day 1.”

A hostile administration could threaten New York’s clean energy targets under the 2019 Climate Leadership and Community Protection Act, which requires that 70% of the state’s electricity come from renewable sources by 2030. A report published by state agencies in July forecasts that New York will fall short of its goal if steps are not taken. (See NY Expects to Miss 2030 Renewable Energy Target.)

Despite this, renewable energy industry analysts, representatives and environmental advocates say the state is in a better position than many others to make progress on its renewable energy goals.

“When we’re talking about a realistic Trump presidency, the impacts to New York are really minimal,” said Lizzie Bonahoom of Aurora Energy Research.

Bonahoom clarified that “realistic” means Trump himself will not be able to claw back the provisions of the Inflation Reduction Act and repeal federal tax credits for renewables and batteries.

IRA Clawbacks and Tariffs

Amy Turner, director of the Cities Climate Law Initiative at the Columbia University Law School’s Sabin Center, broadly agrees.

The vast majority of IRA funding has already been allocated and contracted out. IRA tax credits cannot be repealed by executive action alone. Congress would need to pass targeted repeals of the law’s provisions, and with such tight partisan margins, it could not afford Republican defectors. Much of the IRA’s funding went directly to Republican-led states and congressional districts.

Even if the administration successfully repealed those tax credits, as the Heritage Foundation’s “Project 2025” has outlined, the impact would still be mitigated by the state’s renewable portfolio.

“Wind and solar are proliferating partially due to tax credits but in bigger part due to capital costs coming down,” Bonahoom said.

She said that while it is unlikely that Trump would find enough congressional support to fully repeal the IRA’s renewable tax credits, he might try to staff the IRS with people who might make the tax credits burdensome to claim by increasing administrative burden on claimants. This could increase capital costs for the sector.

The IRA’s “Buy American” provisions also had the effect of driving U.S. renewable supply chains onshore. While not everything can be produced domestically, the supply chain is a lot less weak than it used to be. Marguerite Wells, president of the Alliance for Clean Energy New York, explained that this shift, in the event of Trump-imposed trade tariffs, would reward members of the renewable industry who had moved their manufacturing back to the U.S. faster.

“If you impose a tariff with the IRA in place … that would shunt people over to the people who had been investing in local industrial capacity,” Wells said, “which was kind of the point of the IRA.”

CLCPA and Local Authority

Wells said that there was widespread sentiment in the industry that New York was still a great place to be in the renewables business.

“The CLCPA still stands, and it’s clear that from the way that state legislators were returned to office after what they’ve been doing and advocating in terms of clean energy, it’s what New Yorkers still want,” Wells said. “I think that still holds. That dictates my general hopefulness for renewables in New York.”

Even after the election, Wells said that there is an attitude of adapting and building as many renewables as possible. She said that Gov. Kathy Hochul’s recent reconsideration of congestion pricing in New York City was a hopeful signal of her willingness to take a stand on climate issues, even if they might be controversial.

“We don’t know if it’s a harbinger for more, but at least it’s a step in the right direction,” Wells said.

State Assemblymember Alex Bores (D), who represents part of Manhattan, said that he was focused on trying to get New York out of its own way when it comes to building renewables.

“A lot of red states have much quicker permitting,” Bores said. “So even if we want to do a lot of projects and get renewables online … it sometimes takes too long, and that’s not the fault of any federal administration.”

Bores said that the state needs to focus on spending the money it already allocated to renewable energy and grid upgrades, expedite permitting and unbind state entities like the New York Power Authority. He pointed to an old law that up until 2023 prevented NYPA from developing more renewable generation.

“We need to keep our own side of the street clean, make sure we are doing everything possible … and make sure we’re also not getting in our own way,” Bores said. “Because I don’t think we’re going to have the help we need from the federal government, to put it mildly.”

A large part of why New York is in a good position to continue pushing on renewables is because of the CLCPA, which was passed during the first Trump administration, said Chris Casey, an attorney for the Natural Resources Defense Council. “The strategy around decarbonizing New York’s economy is really one that’s based on traditional notions of state authority.”

Casey said states have a disproportionate level of control over the generating resources that come online and their ability to grant permits and create incentives. Those powers are only magnified when you have a single-state ISO.

“FERC has largely been supportive of allowing states to go the directions they want, and we really have opportunities to create synergies between the ISO’s markets and state policy,” Casey said. “The problems aren’t as big or intractable when you have a state with clear energy policies and an RTO with the same footprint.”

He pointed to the state’s Coordinated Grid Planning Process and the execution of Public Policy Transmission Needs as evidence of NYISO and New York working together. That’s enhanced by a cooperative federal government, but it isn’t stopped by an uncooperative one.

Casey pointed out that at the federal level, most of the IRA money had already been contracted out and that New York had not really been dependent on that money for developing most of its renewable energy portfolio.

Some of the IRA funding that has already been contracted to the state for building heat electrification is already pushing it toward some of its targets through the New York State Research and Development Authority’s incentive programs.

“Programs like NYSERDA’s are providing substantial incentives to American families, driving consumer adoption of energy-efficient systems like heat pumps,” said Max Veggeberg, CEO and founder of Tetra, a home energy services company. “This momentum would be difficult to dismantle. In fact, the new administration’s support for nuclear energy could further lower energy costs, ironically making the adoption of heat pumps an even more attractive option for New York homeowners.”

Offshore Wind

Offshore wind is a major element of New York’s energy goals and is uniquely under the purview of federal agencies. Trump has vowed to halt offshore wind development on the campaign trail. But it’s not clear how much the federal government can stop.

“We see business as usual,” said Nick Guariglia, spokesperson for the New York Offshore Wind Alliance. Guariglia explained that two projects, Sunrise Wind and Empire Wind 1, were nearing completion and were unlikely to face stoppage because they are already under construction, which means they have made it through much of the federal permitting process.

Offshore wind projects take a long time with or without a cooperative administration. Empire Wind’s lease was sold to Statoil Wind US in 2016, during the first Trump administration. The final construction plan was not approved until February 2024. Even though many projects are not as far along as having a final construction plan, they do have lease agreements, which give the developments more legal weight.

But beyond that, the offshore wind energy is broadly aligned with Trump’s stated goal of energy development and “energy independence” and “energy dominance.”

“We want to make America energy independent, and the only way to do that is to make energy right here,” Guariglia said.

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CEC Ups Data Center Demand Forecast After PG&E Revisions

The California Energy Commission has updated its energy demand forecast for data centers after receiving revised figures from Pacific Gas and Electric about data center growth.

PG&E submitted data center information to the CEC in September. But an update the utility provided this month “shows substantially more requested capacity since their [September] submission,” according to a Dec. 23 presentation to the CEC’s Demand Analysis Working Group.

Compared to projections discussed by the working group in November, PG&E’s peak data center demand in 2040 has increased by about 600 MW, to roughly 2,300 MW, under a “mid” demand scenario.

The forecast hasn’t been finalized, and the CEC is still accepting comments.

The CEC is wrapping up its 2024 California Energy Demand Forecast, of which data center demand is one component. The commission is expected to adopt the forecast at its Jan. 21 business meeting.

Once completed, the forecast is used in statewide energy planning, such as CAISO’s transmission planning process and the California Public Utilities Commission’s resource adequacy and integrated resource planning.

Heidi Javanbakht, program manager in the CEC’s Demand Analysis Branch, said CEC staff have been talking to leadership at CAISO and the California Public Utilities Commission about implications of data center demand growth.

“Planning for this potential magnitude of load growth … in the Bay Area over the next five to six years is going to require really close coordination between the agencies and the utilities,” Javanbakht said.

She also said “it’s a priority across the agencies and the ISO” to support the data center industry.

Revised Forecast Methods

In addition to incorporating new data from PG&E, the CEC’s updated data center demand forecast uses a different methodology compared with the previous forecast.

Previously, the CEC assumed all proposed data center projects would be completed. The rationale was that if one project fell through, another one would likely come along to replace it.

“However, considering the number of new applications reported by PG&E, we decided to revise the previous methodology and assume that not all projects will be completed,” said Jenny Chen, supervisor in CEC’s sector modeling unit.

Under the new methodology, which applies to PG&E and Southern California Edison (SCE), the likelihood of a data center project being completed is judged based on where it is in the planning process. The likelihood of completion is higher if engineering studies for the project are in progress or completed; lower if there’s an active application but no engineering studies; and even lower in the case of an inquiry without an application.

The change also helps address concerns that data center developers may be contacting more than one utility about a single project, which could lead to double counting.

With the new methodology, PG&E’s projected peak data center demand decreased from 2024 to 2027 compared with the CEC’s projections from November. But from 2028 to 2040, peak demand was up compared with the previous projections in both a “mid” and “high” demand scenario.

For SCE, projected data center peak demand is lower in most years with the new methodology. In 2040, peak demand is projected at just under 500 MW for the “mid” scenario, a drop of about 394 MW compared with the forecast using the previous methodology.

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SPP Briefs: Week of Dec. 16, 2024

DALLAS — SPP’s Resource and Energy Adequacy Leadership (REAL) Team closed out the year by taking two actions related to the long-term planning reserve margin (PRM). 

The team Dec. 18 unanimously approved a long-term policy paper intended as a guide for SPP staff as they continue to develop policy and additional work plans on the subject. The paper outlines the framework for establishing long-term planning horizon PRM requirements to minimize revisions to the requirements with adequate advance notice leading up to the applicable operating season. 

Team members debated whether the paper captures all the risk factors, with some urging a conversation around the possible variances that could occur. 

Natasha Henderson, SPP’s director of system planning, said she received offline feedback that the paper presents a buffer of sorts, to which she responded, “No.” 

“We are really looking at two different types of risks when we move from the long-term planning horizon to the real time in operations,” she said. “What happens if we set something five years out and things change between our assumptions and resource mix and the interaction of the resource mix and load. If something changes that meets the one-day-in-10 [reliability] standard that we were planning to, we may not have actually been planning to that. That’s the nature of risk.” 

She said other comments centered on what the right practice may be, instead of just arbitrarily increasing the PRM. 

“All that the paper is saying is that we need to understand what that risk is,” Henderson said. “The mitigations of that risk would happen later, after a lot of discussion that would include the discussion of affordability.” 

The grid operator recently won FERC approval of a 36% PRM for the winter season, effective 2026/27. It has a 16% margin for the summer season, effective 2026. (See FERC Approves SPP’s Winter RA Requirement.) 

The proposed policy paper includes edits from the Kansas Corporation Commission’s Andrew French, who described another grid operator’s process of setting the PRM as wildly inconsistent. 

“To increase planning certainty, there should be appropriate consideration of risk in setting long-term PRM requirements, so that the need for subsequent adjustments to those established requirements is minimized,” he wrote. “However, all stakeholders should recognize longer-term planning intrinsically involves more uncertainty. SPP can provide best estimates of long-term resource needs, giving [load-responsible entities] more planning information, but LREs share the obligation to plan for the future.”

The REAL Team also endorsed the Supply Adequacy Work Group’s recommendation of 2029 PRM values set at 38% for the summer and 17% for the summer. The SAWG based its recommendations on the 2024 submitted forecasts for the resource and load mix, which used SPP’s 2023 loss-of-load expectations study. 

Changes in proposed load (increased) and the resource mix (thermal increased, wind resources dropped) resulted in different PRMs for the 2029 study year. However, the RTO’s staff said they could support SAWG’s recommendation because it can evaluate 2030 in the 2025 LOLE study and set a 2030 PRM based on the long-term policy paper. 

Nickell Looks Forward as CEO

The REAL meeting came the day after SPP announced Lanny Nickell would become the grid operator’s CEO in April. That gave the team’s lead, South Dakota Public Utilities Commission Chair Kristie Fiegen, an opportunity to invite Nickell to make his first public comments to stakeholders. (See related story, SPP Names COO Nickell to Replace Sugg as CEO.) 

“One of the favorite things about my experience at SPP, and I’ve been here 27 and a half years, has been working with stakeholders. It’s just what I enjoy doing,” he said.  

Nickell added that he cares “deeply” about SPP and its success, lumping employees, members and their customers together. 

“We’ve got a lot of work ahead of us. We’ve got some very real challenges,” he said. “This is the right committee working with the SAWG, working with [state regulators] resolving those challenges, because that’s where the majority of our challenges are. I’m excited to be able to continue to work with you all to figure those things out, and I think we’re going to be successful, and I’m excited about the future.” 

Markets+ Strengthens Participant Engagement

The Interim Markets+ Independent Panel (IMIP), composed of three independent SPP board members, approved two measures Dec. 19 to provide greater cooperation between the IMIP and western state regulators and establish a policy for appeals to the RTO’s board. 

The IMIP signed off on a joint resolution formalizing an agreement with the Markets+ State Committee (MSC) to participate in each other’s meetings, with allocated time on their corresponding agendas, and to host joint in-person and/or virtual meetings to address any issues during the development and operation of Markets+. 

The MSC, a group of regulators from 13 states in the West and the Great Plains, raised the need for ongoing engagement in late 2023. The Markets+ Participant Executive Committee (MPEC) eventually handed it to the Markets+ Interim Governance Task Force (MIGTF). 

“This was kind of dumped in their lap, and they didn’t know what to do with it,” said MSC Chair Nick Myers, with the Arizona Corporation Commission. 

It took a 30-minute conversation between Myers and IMIP Chair Steve Wright to iron out the resolution. 

“This hopefully resolves any concerns that are out there about how we will work together going forward,” Wright said. 

The IMIP also approved a policy brought forward by the MIGTF and MPEC to address interactions between the Markets+ Independent Panel (MIP) and the SPP board. The policy includes a process under which the IMIP and MIP can submit appeals to the board.  

The MIP will replace the IMIP by the time Markets+ is up and running, currently targeted for early 2027. It will be allowed to appeal decisions on the same issue multiple times to the board. 

ACC’s Myers: FERC Order Close

FERC is close to filing its response to SPP’s filing to the commission’s finding that the RTO’s Markets+ tariff submittal is deficient, Myers told the MSC on Dec. 20. 

Myers, part of a recent Western Interstate Energy Board delegation to FERC’s offices in D.C., said that after discussions with staff, he’s hopeful the commission will rule on the tariff in January. SPP submitted its response to FERC’s deficiency finding in September, asking for a response by Nov. 20. (See SPP Dispels Concerns over Markets+ Deficiency Letter.) 

“I impressed upon them that the MSC really didn’t have too much opposition to that tariff, which is the reason why we didn’t necessarily file comments,” Myers said. “They were very receptive of that and thought it was great that the states were in agreement with the tariff overall. I did get … that it’s a top priority and that they’re kind of in the final stages of it.” 

Potential Competitive Upgrades

Two recently approved 345-kV transmission projects potentially meet the requirements for competitive upgrades, SPP said Dec. 16.  

The projects in question — Belfield-Maurine-New Underwood-Laramie River, from the Dakotas into Wyoming, and Elm Creek-Tobias in Nebraska — also include upgrades that don’t qualify as competitive because they interconnect to existing noncompetitive facilities. Those upgrades will receive notifications to construct with conditions (NTC-C). 

The noncompetitive upgrades will require refined cost estimates that will affect the projects’ overall status. Under SPP’s tariff, an entire project could be re-evaluated if the noncompetitive refined cost estimate is out of bandwidth and is not considered fully approved for construction. 

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Texas PUC Shelves PCM Design Over Lack of Benefits

The Texas Public Utility Commission has shelved the market design it once favored, agreeing with staff’s recommendation that the performance credit mechanism (PCM) results in “minimal” additional resource adequacy value.

In a memo filed before the PUC’s Dec. 19 open meeting, commission chair Thomas Gleeson said he concluded the PCM, “as currently designed,” wouldn’t provide “the reliability benefits needed in the ERCOT market.” He said it would be “appropriate” to reconsider the PCM in the future,” but that the commission’s “collective resources are best directed toward implementing other market design initiatives” (55000).

“The outcome is what it is,” Gleeson said during the open meeting after gaining agreement from his fellow commissioners. “But the work was tremendous, the analysis was tremendous, and that got us to the decision that we needed to make.”

“There are variables that are in the PCM, there’s things that we can come back if later needed to learn from … and definitely something that is not thrown away, just put on the shelf,” commissioner Courtney Hjaltman said. “[Let’s] see what other things are in the market, and we can come back and learn from those things.”

The commission in August directed ERCOT and the Independent Market Monitor to complete updated assessments of the PCM’s cost to and its effects on the market. Staff reviewed those assessments before making their recommendation.

The PCM was designed to incent more gas generation by awarding thermal generators credits based on their performance during a determined number of scarcity hours. Those credits would be bought by load-serving entities, based on their load during those same hours, or exchanged by LSEs and generators in a voluntary forward market. (See Texas PUC Submits Reliability Plan to Legislature.)

However, ERCOT’s assessment, conducted with the Energy and Environmental Economics (E3) consulting firm, found that the market would hit a $1 billion gross cost cap imposed in 2023 by the Texas Legislature every year and add only about 800 MW of dispatchable generation. It said the cap “significantly limits the effectiveness of the PCM.”

The IMM said the “novel” design would provide a new source of revenue for generators that would increase ERCOT’s capacity margin and the costs to customers but reduce shortage revenues. Eventually, the higher capacity margins would reduce the frequency of shortage pricing, with the net costs falling to $350 million to $725 million annually.

“Good riddance,” energy consultant and former PUC and FERC staffer Alison Silverstein said. She agreed with the PUC’s decision to wait on real-time co-optimization and better battery rules, targeted for implementation in December 2025, and other measures before revisiting the PCM.

The grid operator also is working on a standalone dispatchable reliability reserve service (DRRS), a non-spinning reserve service subtype as a result of a new law, and analyzing ancillary service demand curves.

“If you’re going to mess with the market, the juice should be worth the squeeze,” Silverstein told RTO Insider. “The limits on PCM make it unlikely to be an effective gas plant subsidy, so why bother?”

Doug Lewin, Stoic Energy’s founder and principal, also agreed with the PUC’s decision.

“Capacity market constructs do too little, if anything, for reliability for their massive cost,” he said. “I hope now the commission, ERCOT and stakeholders can focus on more important things and stop wasting time arguing about capacity market design.”

ERCOT spokesperson Christy Penders said in an email that while the PCM didn’t provide enough benefits to move forward for the time being, “We continue to work with stakeholders on market solutions to enhance the reliability of the Texas power grid.”

ERCOT to Pursue Braunig MRAs

ERCOT General Counsel Chad Seely told commissioners that staff expects to execute a reliability must-run agreement with San Antonio’s CPS Energy within weeks for its Braunig Unit 3 gas resource. The grid operator says the capacity is needed to address transmission reliability until several South Texas projects are completed by summer 2027. (See ERCOT Board of Directors Briefs: Dec. 2-3, 2024.)

Seely said staff are continuing discussions with CPS, CenterPoint Energy and Life Cycle Power over moving 15 large generators and their 450 MW of capacity from Houston to distribution sites in the San Antonio area. The generators, which range in size between 27 and 32 MW, would provide a less expensive alternative to the $56 million CPS says it will take to overhaul and continue running Braunig’s other two units.

The San Antonio municipality told ERCOT earlier this year it intended to retire all three 1960-era units in March 2025.

“We think technically, this is a very feasible option and will provide a better, reliable solution than moving forward with an RMR agreement for Units 1 and 2,” Seely said.

In the interest of time, ERCOT issued a request Dec. 20 seeking one or more must-run alternatives to the potential solution being negotiated.

CenterPoint Executive Vice President Jason Ryan told the PUC that if the generators are moved to San Antonio before the summer, its Houston-area customers won’t be charged for the units, and the utility won’t receive any revenue or profit from them.

“This whole time, it’s been our priority to make sure that we can bring to the table a Texas solution … and at the same time [we’re] providing that Texas-based solution, making sure that our customers see a rate reduction as a result.”

CenterPoint leased the generators for $800 million in 2021 following that year’s winter storm that nearly collapsed the ERCOT grid. The large generators turned out to be anything but mobile and when they went unused in Hurricane Beryl’s aftermath, CenterPoint came under fierce political and customer criticism.

ERCOT’s Kristi Hobbs, vice president of system planning and weatherization, said the ISO’s twice-yearly Capacity, Demand and Reserves report’s December release will be delayed into 2025 “to ensure we get it right.” A recent protocol change (NPRR1219) extends the seasonal CDR reporting to all four seasons and adds unavailable switchable generation resource capacity.

In other action, the PUC:

    • Adopted new requirements for utilities in ERCOT that lease and deploy mobile generation facilities. The rule is a result of the 87th Texas Legislature’s House Bill 2483 (53404).
    • Approved staff’s review of ERCOT’s ancillary services (AS) that was conducted with the grid operator’s staff and the Independent Market Monitor. The review found that ERCOT’s current set of AS and the future DRRS are enough to comply with NERC requirements and recommended only minor changes (55845).
    • Again tabled Entergy Texas’ proposed system resiliency plan that would implement six resiliency measures over a three-year period at a cost of $335 million. At issue is Entergy’s request for conditional approval of $198 million of projects that would become part of the plan if the utility receives grants under the Texas Energy Fund’s Outside ERCOT Grant Program (56735).
    • Rejected a joint petition by two retail advocacy groups requesting ECRS be designated as an ancillary service incurring charges beyond a retailers’ control for existing contracts executed on or before June 9, 2023 (55959).
    • Approved the final draft of its biennial agency report to the Texas Legislature. The report must be submitted by Jan. 15 (56335).

Commissioner Lori Cobos adjourned the meeting, her last as a PUC member. Cobos, the last of the three commissioners appointed in 2021 to replace the three previous incumbents following that February’s disastrous winter storm, announced her retirement in November. (See Texas PUC’s Cobos to Leave Commission.)

Cobos battled her emotions as she thanked fellow commissioners, the PUC staff and the state’s political leadership, calling her appointment the “honor of a lifetime.” Her audience included former FERC and PUC chair Pat Wood.

“I am tremendously grateful for this opportunity to have served on the PUC,” Cobos said.

Alluding to Cobos’ focus on building transmission, Hjaltman said, “We’re going to hopefully do you proud with everything and your legacy of transmission and get those projects done for you.”

Gleeson revisited his comments from Jimmy Glotfelty’s departure Dec. 12 and thanked Cobos for “all the work you did on my Permian Basin reliability project.”