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November 5, 2024

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ERCOT Technical Advisory Committee Briefs: Feb. 14, 2024

ERCOT stakeholders last week agreed with staff’s position to continue tabling a rule change that would address reliability concerns with inverter-based resources (IBRs) while both sides work on settlement discussions in an attempt to compromise. 

The Technical Advisory Committee had agreed to move up its February meeting by a week to send a timely endorsement to ERCOT’s Board of Directors before the latter’s Feb. 27 meeting.  

That the rescheduled meeting fell on Valentine’s Day was not lost on its participants. A bowl of “metaphorical” candy, printed with acronyms specific to the discussion, was set out for members.  

TAC celebrated Valentine’s Day with special candy. | Caitlin Smith via X

“My only question is, [who] do I send the bill to for the bouquet of flowers I had to buy my wife for being here today?” Engie North America’s Bob Helton jokingly asked. 

Eric Goff, speaking for the joint commentators negotiating with ERCOT staff, said those he represented were not opposed to keeping the nodal operating guide revision request (NOGRR245) on the table. 

“We believe that we’re getting through productive dialogue with ERCOT,” he said. “There are some outstanding issues that will take some time to resolve, but I’m feeling cautiously hopeful … that we will be able to give something for the March TAC [meeting].” 

ERCOT’s Stephen Solis agreed and apologized for not meeting the timeline. 

“We’re not quite there yet,” he said. “We cleared up some misunderstanding, I think, and there are some core issues that we’re still working on where we stand apart and trying to find perhaps more creative ways of addressing that.” 

The grid operator says the prevalence of IBRs on ERCOT’s system has increased the likelihood of potential instability issues, such as the recent Odessa disturbances. They say the issues are only going to increase along with the continued growth of solar and wind resources. (See NERC Repeats IBR Warnings After Second Odessa Event.) 

ERCOT says the NOGRR would improve the clarity and specificity of IBRs’ voltage ride-through requirements. The measure would align the grid operator’s rules with NERC reliability guidelines and the most relevant parts of the Institute of Electrical and Electronics Engineers standard for IBRs interconnecting with the grid. (See ERCOT Technical Advisory Committee Briefs: Jan. 24, 2024.) 

Vistra’s Katie Rich is serving as an independent arbiter during the settlement discussions, which Goff said could take either of two directions. 

“One, we have a common agreement on language, which would be great. The other is ERCOT would file comments, we would file responsive comments, and Katie would tell us the difference between the two,” he said. “We’ll see which one we get to.” 

TAC will meet twice before the board’s April 23 meeting. 

NPRR1186 Goes to Board

TAC did not take up a protocol change (NPRR1186) regulating energy storage resources (ESRs) that was remanded back to ERCOT last month by the Public Utility Commission. (See Texas PUC Sends ESR Change back to ERCOT.) 

The grid operator’s staff said that as the PUC’s directive ”seems straightforward,” they recommended the Board of Directors adopt the commission’s recommendations “without formally requesting additional input from the [TAC] or other stakeholder bodies.” 

“The board’s authority to decide this question without soliciting stakeholder feedback is consistent with the governing statute,” staff said, noting stakeholders always can submit a comment on the NPRR for the board’s consideration. 

The rule change sets a one-hour state of charge (SOC) for ESRs participating in two ancillary services (ERCOT contingency reserve service and non-spinning reserve). It also includes penalties of up to $25,000 per violation. 

The PUC’s remand included “suggested modifications” to remove the SOC compliance requirements and other minor clarifications. 

ERCOT also is asking the board to provide direction on NPRR1209, a directive from the directors, as NPRR1186 ran into trouble and has been tabled. The change would consider an SOC insufficiency by any ESR carrying an ancillary service resource responsibility to be a “failed quantity” that would result in a clawback of AS revenues. 

Both measures are seen as stopgaps until ERCOT deploys real-time co-optimization, targeted for the latter half of 2026. 

The ISO had 3.3 GW of ESRs on its system in June. It expects to have 9.5 GW of ESRs energized by October. 

TAC: More Info on Budget

Staff’s two-slide presentation on the budgeted system administration fee’s forecasted adequacy for 2025 — “currently forecast to be adequate” and requiring no changes — led to a request from TAC for more background. 

“It wouldn’t hurt to have maybe a few slides that actually show us the actual budget itself and kind of where we’re trending and what we’re spending the money on,” Reliant Energy Retail Services’ Bill Barnes said. “Some background: ‘Well, why is it adequate?’” 

At TAC’s request during the 2016-2017 budget process, ERCOT provides stakeholders advance notice of any future administrative fee rate increases. The board in December approved the fee and the ISO’s budget for 2024-25 after the PUC trimmed both; the admin fee was cut from 71 cents/MWh to 63 cents/MWh, up from the previous 55.5 cents/MWh. (See “Revised Budget Passes,” ERCOT Board of Directors Briefs: Dec. 19, 2023.) 

Controller Richard Schaal promised “a couple” of extra slides to provide more information. 

8 Revisions on Combined Ballot

TAC’s unanimously approved combined ballot of voting items endorsed Rich as chair of the Reliability and Operations Subcommittee. Rich stepped aside temporarily in January after a job change. 

The combo ballot also included four NPRRs, a NOGRR and a load planning guide revision request (LPGRR), and two changes to the settlement metering operating guide (SMOGRRs) that, if approved by the board, would: 

    • NPRR1193: Change the ERCOT-polled settlement (EPS) design-proposal form’s referenced location when it moves from the other binding document (OBD) list into the SMOG. 
    • NPRR1199: Revise the protocols to add definitions related to the Lone Star Infrastructure Protection Act (LIPA), a 2021 law that prohibits Texas businesses and governments from contracting with entities owned or controlled by individuals from China, Russia, North Korea or Iran if the contracting relates to “critical infrastructure.” The measure also adds language reflecting ERCOT’s statutory authorization to immediately suspend or terminate a market participant’s registration or access if the ISO has a reasonable suspicion that the entity meets any of the LIPA’s criteria, among other revisions. 
    • NPRR1210: Change the frequency of the next-start resource and the load-carrying tests from every five years to every four calendar years. 
    • NPRR1213: Amend requirements for distribution generation resources (DGRs) and distribution energy storage resources (DESRs) seeking qualification to provide ERCOT Contingency Reserve Service (ECRS). The NPRR also modifies requirements for ancillary service self-arrangement and ancillary service trades for DGRs and DESRs that provide non-spinning reserve on circuits subject to load shed. 
    • LPGRR074: Align specific term language in the profile decision tree “definitions” worksheet with profile segment language that was added to the “segment assignment” worksheet with the Public Utility Commission’s 2022 approval of LPGRR069. 
    • NOGRR261: Incorporate the OBD “Procedure for Calculating Responsive Reserve (RRS) Limits for Individual Resources” into the nodal operating guide. 
    • SMOGRR027: Move the EPS metering design proposal from the OBD list into the SMOG, standardizing the approval process, and amend the design proposal form to require more information identifying any and all distribution service providers that have the right to serve a project. 
    • SMOGRR030: Move the EPS metering facility temporary exemption request application form from the OBD list into the SMOG to standardize the approval process. 
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FERC Approves Vistra Purchase of Energy Harbor, Requires Divestment

FERC on Feb. 16 approved Vistra Energy’s deal to buy Energy Harbor, which it wants largely for its four nuclear plants and retail business, for $3 billion plus paying off $430 million of debt (EC23-74). The commission required divestment of two of Vistra’s fossil plants in PJM. 

Vistra plans to launch a new subsidiary combining its clean energy generation and retail business called “Vistra Vision” of which 15% will be owned by Energy Harbor shareholders, while spinning off its natural gas and coal units into a separate subsidiary called “Vistra Tradition.” 

Energy Harbor is the competitive generation and retail business spun off from FirstEnergy several years ago. It owns three nuclear plants: Beaver Valley Power Station at 1,969 MW, the Davis-Besse Plant at 962 MW and the Perry Nuclear Power Plant at 1,302 MW.  

Energy Harbor also owns some fossil plants, and Vistra already owns generation in PJM. The merging firms argued their impact on competition should be measured against the whole RTO, while PJM’s Independent Market Monitor, the U.S. Department of Justice’s Antitrust Division and the Ohio Consumers Counsel all argued FERC needed to consider smaller submarkets. 

Both Energy Harbor and Vistra own generation in the American Transmission System Inc. (ATSI) zone, so Vistra agreed to sell off its 369-MW Richland natural gas peaking plant and its 16-MW Stryker oil plant to end concerns over an excess of power in that submarket of PJM. 

The sale of those plants “obviates the need” for FERC to determine any submarkets relevant to the transaction so it focused on its impact on PJM as a whole, the order said. 

“After the proposed transaction closes and after completing the divestiture of Richland-Stryker, the Davis-Besse and Perry generating units, currently owned by Energy Harbor, will comprise the only units owned by Vistra in the ATSI transmission zone,” FERC said. “Furthermore, as discussed below, Vistra must sell Richland-Stryker to a buyer that will not fail the horizontal competitive analysis screens, including the delivered price test, for the PJM market or any relevant submarket, post-transaction.” 

FERC was not convinced the deal would impact any other submarkets, saying they failed to show any consistent price separation caused by transmission constraints that would indicate a submarket under commission precedent. The commission found the deal would not impact the whole of PJM either, and declined to adopt behavioral requirements suggested by the Monitor. 

“The PJM IMM relies on perceived existing limitations in PJM’s market power mitigation as the basis for proposing additional behavioral mitigation,” the order said. “These arguments are directed at the effectiveness of the PJM markets and mitigation measures as a general matter.” 

FERC declined to deal with such general issues in this merger case, saying it is not the appropriate venue for that. 

The IMM also used a different analysis than what FERC employs in merger reviews to argue the combined firm would have market power in PJM, especially in local markets. DOJ’s Antitrust Division also wanted FERC to use a “supply curve” analysis to review the deal. 

“The commission’s regulations do not require a supply curve analysis, and applicants have provided a horizontal market power analysis, including three delivered price tests, consistent with our requirements,” FERC said. “Moreover, the divestiture commitment appears to alleviate DOJ Antitrust Division’s specific concern about the proposed transaction given that the divestiture of Richland-Stryker eliminates Vistra’s ‘ability’ to engage in strategic withholding using that facility.” 

The OCC and the Northeast Ohio Energy Council argued FERC should examine the deal’s impact on Ohio’s retail energy market as it will combine two of its largest firms. While FERC lacks explicit authority over the retail power market, the Ohio PUC is unable to review the merger and its impacts on the market, the two said. 

The federal regulator’s policy is to review the impact on retail competition whenever a state regulator asks it to. Because the PUC made no such request, FERC declined to examine the deal’s retail market impacts. 

The Ohio Energy Advocate, which was set up to represent the interest of the state’s energy consumers at FERC and before other federal regulators, did file a request to review the impact on retail markets, but the commission said it does not count as a state regulator. 

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SPP MSC Approves ‘Duty of Candor’ Tariff Language

State regulators in SPP’s Markets+ footprint have approved tariff language designed to address a “gap” in the accuracy of information to be shared with the Market Monitor under FERC’s duty-of-candor requirements.  

Weeks of discussion between regulators, SPP’s Market Monitoring Unit, and SPP and western utility legal staff resulted in the Markets+ State Commission’s endorsement of a paragraph during its regular monthly conference call Feb. 16. 

Nebraska abstained from the vote. 

The proposed tariff language would require market participants to “exercise due diligence and good utility practice” in providing material information when responding to the MMU’s written request for data and information. The MMU would provide a “reasonable amount of time” for utilities to deliver the requested information, depending on the amount of information.  

If the market participant determines there is an error in its response, it would have to “promptly” notify the MMU and work to correct the mistake. 

Questioned as to why the language is necessary, Keith Collins, vice president of market monitoring at SPP, said the MMU has encountered several instances within the RTO’s current footprint of entities either ignoring the monitor’s request or submitting incorrect action.  

“This does happen, unfortunately,” he said, noting the MMU based several hypothetical examples shared during deliberations over the language on those circumstances.  

“We feel that this particular language will solve that gap that we’ve identified with those examples,” Collins added. 

“Given what we’ve seen in the West, I just think there’s some real scar tissue about market manipulation,” said MSC Chair Eric Blank, who also chairs the Colorado Public Utilities Commission. “This is just common-sense protection that it seems the lawyers for SPP and for the market participants have agreed to.” 

Western commissioners brought the issue up during the Markets+ Participant Executive Committee meeting in January, requesting a clear definition of the participant obligation gap. (See “MMU, MSC to Collaborate,” SPP Markets+ Participants Executive Committee Briefs: Jan. 23-24, 2024.) 

A 2022 FERC Notice of Proposed Rulemaking related to “duty of candor” would require all entities communicating with the commission or other organizations — e.g., the MMU — about FERC matters to provide “accurate and factual information” (RM22-20). (See FERC NOPRs Would Require ‘Candor,’ Improved Accounting for Renewables.) 

The language will be brought forward for stakeholder approval during MPEC’s virtual meeting Feb. 20. 

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ConEd to Invest $20B in Tx and Climate Resiliency Through 2028

Consolidated Edison last week reported its plan to invest nearly $20 billion over the next four years in transmission infrastructure as part of its Reliable Clean City initiative and to mitigate climate vulnerabilities. 

The New York-based utility, which serves parts of New Jersey via Orange & Rockland (O&R) Utilities, made significant strides in the past year with the Clean City project, completing several sections and receiving state authorization for further upgrades to the six-mile-long Queens-based underground transmission line. It also was approved to start its $810 million Brooklyn-based interconnection hub for offshore wind power. (See $1.2B Con Edison Clean Energy Upgrade Approved.) 

“Clean energy is the future of our industry, and we are making strategic investments to build a grid capable of carrying that clean energy and protecting our infrastructure from climate change while maintaining our world-class reliability,” said ConEd CEO Tim Cawley in a statement.  

ConEd’s subsidiaries, Consolidated Edison Co. of New York (CECONY) and O&R, submitted plans to the state’s Public Service Commission (PSC) to invest $1.3 billion over five years to prepare for climate change (22-E-0222). They also proposed investments of about $2.82 billion in heat pump programs (18-M-0084) and obtained approval to increase their electric vehicle implementation budgets to nearly $450 million (18-E-0138). 

Con Edison’s corporate structure and ratings | Con Edison

The subsidiaries submitted utility thermal energy network pilot proposals totaling $289 million but await PSC approval (22-M-0429). 

ConEd plans to fund these investments by issuing $3.25 billion of long-term debt in 2024 and an additional $1 billion in 2025, with $6 billion more in long-term debt expected through 2026 and 2028 at CECONY and O&R. 

“Con Edison closed the year with no long-term debt at the parent company, due to the strategic sale of our former subsidiary, the Clean Energy Businesses,” said ConEd CFO Robert Hoglund. 

ConEd sold off CEB, consisting of 3,300 MW of renewable energy projects, to RWE Renewables America in 2022 for $6.8 billion and continues to realize financial benefits. In its 10-K filing, the utility reported a nearly 41% increase in annual net income, which rose to just under $2.52 billion ($7.25/share) in 2023 from $1.66 billion ($4.68) in 2022. (See Con Ed Yearly Earnings Continue to Rise.) 

Adjusting for the CEB sale, and other financial hypotheticals, ConEd’s annual earnings saw a more modest 9.6% increase, rising to $1.76 billion ($5.07/share) in 2023 from $1.62 billion ($4.57/share) in 2022. 

ConEd forecasts its 2024 adjusted earnings per share to be between $5.20 and $5.40 and expects an average annual increase in peak demand for electricity and gas over the next five years to be 2.7% and 1%, respectively. It also anticipates a 6.4% annual rate base growth through 2028. 

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We Energies Secures FERC Permission to Switch Coal Interconnection with Gas Plant

FERC on Feb. 15 allowed We Energies a MISO tariff waiver, making it simpler for the utility to trade gas for coal at its Oak Creek campus in Wisconsin. 

The commission granted We Energies a one-time waiver of MISO’s generator interconnection procedure requirements so it can link up a new gas-fired generator at a different voltage to replace its Oak Creek coal plant under a replacement generating facility request (ER24-646).  

We Energies plans to retire two of its 60-year-old Oak Creek coal units in May and the remaining two units by December 2025. It intends to replace the capacity with a $1.4 billion, 1.1-GW natural gas power plant and LNG storage facility to be completed in 2028.  

Oak Creek is connected to ATC’s 230-kV transmission facilities. ATC plans to transition its system surrounding Oak Creek to 345-kV and 138-kV only and eliminate its 230-kV facilities by 2027, hence the new gas plant requiring an interconnection at a different voltage than the existing coal plant. We Energies said it had to request the waiver due to factors outside of its control. 

ATC supported We Energies’ waiver request and said it would be the most cost-effective and efficient means of dealing with the issue. We Energies said if it wasn’t granted the waiver, it would have been forced to either install facilities to interconnect with ATC’s current 230-kV facilities and then replace them soon after with 138-kV- or 345-kV-compatible facilities, or “submit a new interconnection request for a project that would otherwise qualify for MISO’s generating facility replacement process due to no fault of its own.” 

Oak Creek’s generator interconnection agreement struck in 2000 did not specify a voltage level for the coal plant’s interconnection service. 

FERC said We Energies acted in good faith and that the waiver addresses a concrete problem with no detrimental consequences. 

We Energies executives have said the Oak Creek gas plant would serve as a backup power source when renewable energy output dwindles. Nonprofit Clean Wisconsin has argued any new natural gas additions go against We Energies’ goal of achieving an 80% reduction in carbon emissions from 2005 levels by 2030 and 100% carbon-neutral energy by 2050. 

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PJM MRC Preview: Feb. 22, 2024

Below is a summary of the agenda items scheduled to be brought to a vote at the PJM Markets and Reliability Committee meeting Feb. 22. Each item is listed by agenda number, description and projected time of discussion, followed by a summary of the issue and links to prior coverage in RTO Insider. 

RTO Insider will be covering the discussions and votes. See next week’s newsletter for a full report. 

Markets and Reliability Committee

Consent Agenda (9:05-9:10)

B. Endorse proposed revisions to Manual 3A: Energy Management System (EMS) Model Updates and Quality Assurance with the goal of aligning to NERC’s Bulk Electric System (BES) definition. (See “Other Committee Business,” PJM OC Briefs: Feb. 8, 2024.)

C. Endorse conforming revisions to Manual 11: Energy and Ancillary Services Market Operations to implement the real-time temporary exception process FERC approved in EL21-78. (See “Real-time Temporary Exceptions Manual Revisions Proposed,” PJM MIC Briefs: Jan. 10, 2024.)

D. Endorse proposed revisions to Manual 38: Operations Planning resulting from its periodic review. (See “Other Committee Business,” PJM OC Briefs: Feb. 8, 2024.)

E. Endorse proposed revisions to Manual 40: Training and Certification Requirements resulting from its periodic review.

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FERC Rejects Rehearing Request for Mystic Agreement Disclosures

FERC has rejected a rehearing request from a group of New England public power utilities seeking the disclosure of additional information related to the Mystic cost-of-service agreement between Constellation and ISO-NE (ER18-1639-026). 

In October, FERC initially ruled against the public power groups’ request for additional disclosures of information, focused on the agreement’s supply arrangement with the nearby Everett LNG import facility. (See FERC Rules Against Additional Mystic Agreement Disclosures.)  

The public power organizations argued in their November rehearing request that FERC improperly denied outside entities the ability to review and challenge data related to the Mystic Generating Station’s revenues and the management of Everett as a part of the Mystic agreement. Both Everett and Mystic are owned by Constellation. 

The coalition wrote that FERC’s denial of the request for more transparency “pulls an impenetrable veil over information that the ISO-NE customers … require in order to verify the justness and reasonableness of the charges imposed on them and their customers.” 

In its Feb. 15 response to the rehearing request, FERC stood by its decision to deny additional public disclosures.  

“We continue to find the Mystic Agreement’s arrangement is just and reasonable and appropriately provides sufficient assurance that the inputs to the Mystic Agreement filed rate are accurate,” FERC wrote. 

The commission emphasized its prior finding that ISO-NE’s auditing rights in the agreement “are sufficient to ensure accuracy and transparency while preserving the confidentiality of commercially sensitive information and avoiding security risk.” 

ISO-NE and Constellation signed the Mystic agreement in 2018 over concerns that Mystic’s impending retirement would introduce significant resource adequacy risks to the regions. The cost-of-service agreement to retain Mystic began in June 2022 and will expire at the end of May 2024. 

As Mystic is the main customer of LNG from Everett, its looming retirement has triggered an ongoing effort to retain Everett after Mystic’s retirement. The two largest gas utilities in Massachusetts recently announced agreements with Everett to keep the LNG import facility operating for six more years, subject to the approval of the Massachusetts Department of Public Utilities. (See Constellation Reaches Agreements to Keep Everett LNG Terminal Open.) 

ISO-NE has not been involved in the negotiations to keep Everett open beyond the end of the Mystic agreement. The station is on track to retire at the end of the agreement in the spring.  

The costs associated with the cost-of-service agreement have been substantial; ISO-NE estimated that it cost ratepayers more than $600 million in the first 18 months of the agreement. More than $200 million of this cost came solely from January and February of 2023, driven by the spike in global LNG prices.   

Everett’s primary operational conditions for these months were listed as tank management, which includes self-scheduling to run and burning off excess fuel to make room for prescheduled LNG shipments. 

“While we remain sympathetic to customers’ concerns regarding the high costs of the provision of fuel security by the Mystic units, we believe we have struck the right balance,” FERC wrote in its rehearing response. “We are not persuaded that providing the additional information … is necessary to verify Mystic’s costs and ensure that the Mystic agreement’s filed rate is accurately implemented.” 

The public power entities also challenged FERC’s ruling with the D.C. Circuit Court of Appeals in early February, writing that “the commission’s decision to prevent customers from verifying the justness and reasonableness of the charges imposed on them through the cost-of-service agreement is not supported by substantial evidence or reasoned decision making, as required by the Federal Power Act.” 

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GSA, DOD to Power Federal Facilities with 2.7M MWh of Clean Energy

The Biden administration wants to buy more than 2.7 million MWh of carbon-free electricity (CFE) per year to power hundreds of federal and military facilities across the 13 states served by PJM, according to a request for information jointly issued by the General Services Administration and Department of Defense on Feb. 9. 

The RFI also sets out an ambitious timetable for the procurement, which it describes as “one of the federal government’s largest-ever clean electricity purchases.” The official request for proposals could go out in May, with awardees announced in September and the first clean electrons going online by the end of the year.  

In line with President Joe Biden’s 2021 executive order establishing a 100% clean energy goal for federal facilities by 2030, GSA and DOD are looking to make half of the CFE procurement matched hour for hour with demand on a 24/7 basis.  

With over 300,000 buildings, the U.S. government is the nation’s largest energy consumer and “a steady customer prepared to make long-term investments,” GSA Administrator Robin Carnahan said in the RFI press announcement. “We’re using the government’s buying power to spur demand for clean, carbon pollution-free electricity, and we’re partnering with industry to drive toward the triple win of good jobs, lower costs for taxpayers and a healthier planet for future generations.” 

Brendan Owens, assistant secretary of defense for energy, installations and environment, stressed the link between clean energy and national security, and DOD’s leadership in “greening federal government operations.”  

“Today’s announcement will help facilitate grid transformation to address the climate crisis and to provide clean, reliable and affordable electricity that ensures mission resilience for DOD operations,” Owens said. 

The RFI specifies that the government is looking to procure the CFE through retail electricity contracts rather than traditional power purchase agreements. Contracts could be for up to 10 years, with fixed per-kWh prices.  

Critically, the government is only interested in retail contracts for “bundled CFE,” which means “the original associated energy attributes have not been separately sold, transferred or retired,” according to the RFI. Renewable energy certificates (RECs) are the most used measure of clean energy attributes, with each REC certifying that 1 MWh of new wind or solar energy has been put on the grid.  

“Unbundled” RECs or similar energy attribute certificates (EACs) can be sold separately from the power that produced them. Solar installers may sell them to bring down the costs of an installation, and utilities or other companies often buy them to meet state-level clean energy mandates, passing on the cost to customers through increased rates. 

In other words, the Biden administration wants to make sure that the EACs for any clean electricity used to power federal facilities will not be sold for profit or used as a substitute for putting additional, clean energy on the grid.  

The RFI specifically asks that retail electricity suppliers be able to track and document that that any bundled CFE does not include EACs that have previously been counted for a state renewable portfolio standard. Companies are also expected to be able to track and report how much of the CFE provided is matched hour for hour with demand.  

1 Million MWh for BGE

The RFI does not list the federal or military facilities to be powered with CFE or their locations, but it does provide some hints. 

GSA intends to include 650 accounts in the solicitation, with contracts possibly awarded in phases. 

The RFI also provides a list of the megawatt-hours the government will need in the service territories of each of the investor-owned utilities in the PJM states. Baltimore Gas and Electric leads the list with 1,031,740 MWh. The massive military base at Fort Meade is part of the utility’s service territory. 

Commonwealth Edison comes second, with 403,774 MWh, while 201,297 MWh will be needed for Pepco’s service territory, which includes the high concentration of federal buildings in Washington, D.C.  

All three utilities are owned by Exelon Corp., which also owns Delmarva Power (1,381 MWh) and Atlantic City Electric (2,273 MWh). How will Exelon and other utilities handle the additional clean power this procurement could produce? 

In a statement emailed to RTO Insider, Exelon said it has been “modernizing our [transmission and distribution] assets over the last decade, allowing us to continue delivering safe, reliable, affordable energy to our customers even with a growing share of renewable and distributed energy resources.” 

Exelon’s long-range plan calls for $31 billion in investments “to strengthen our infrastructure — both physical and IT — to prepare our assets for an influx of renewable energy sources. … When these sources are built — we will be ready to deliver the energy.” 

GSA does recognize that the size and scope of the procurement may mean it will have to be rolled out in phases, and the agency may not be able to get all the clean energy it wants at the time contracts are awarded. The RFI notes that “GSA is considering including minimum CFE requirements describing how much bundled CFE can be delivered and when.” 

In such cases, “it is anticipated that contractors will be required to provide traditional retail electricity supply to meet [GSA’s] requirements,” the RFI says. 

A key question is how much new clean electric power will be needed to meet the government’s procurement targets. The RFI specifically says any clean power that has come online since Oct. 1, 2021, could be awarded a contract. 

In addition, beginning in July, PJM began its new “first-ready, first-served” interconnection process aimed at clearing a backlog of 260,000 MW from its interconnection queue.  

According to a year-end post on the RTO’s website, it estimates it will be able to clear 300 projects totaling 26,000 MW for interconnection this year. However, the overlap between the PJM queue and the federal procurement could be minimal as the RFI differentiates the bundled CFE it wants to purchase from “grid-supplied” CFE. 

The comment period on the RFI will run through March 18. GSA is holding an “industry day” Feb. 20 to talk about the RFI with retail electricity suppliers and other stakeholders. For more information, email CFESupport@GSA.gov. 

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LADWP Poised to Join CAISO Day-ahead Market After Board OK

CAISO notched another victory in the competition to bring organized markets to the West on Feb. 13 when the Los Angeles Department of Water and Power’s oversight board authorized the utility to prepare to join the ISO’s Extended Day-Ahead Market. 

LADWP has yet to issue a formal announcement on a market decision and did not respond to a request for comment in time for publication of this article. But the resolution advanced by utility officials and approved by the Board of Water and Power Commissioners on Feb. 13 allows LADWP “to proceed with necessary activities, agreement preparations, and other related EDAM work that will be brought back to the board in the future for approval.” 

“We think this is a good move forward,” Fred Pickel, LADWP’s ratepayer advocate, said ahead of the vote. “While the benefits exceed costs, it won’t have as big of an impact as participating in [CAISO’s] EIM, probably, but the information that all parties will get by participating in a formal market of this type will likely enhance everybody’s understanding of both short-run and long-run impacts and needs.” 

LADWP would be the third entity to commit to the EDAM following commitments by six-state utility PacifiCorp and the Balancing Authority of Northern California, a joint powers authority that manages system operations for the Sacramento Municipal Utility District and five other publicly owned utilities. (See BANC Moving to Join CAISO’s EDAM.)   

The largest municipal utility in the U.S., LADWP has been participating in CAISO’s real-time Western Energy Imbalance Market (WEIM) since April 2021. EDAM will expand the capability of the WEIM by including trading of day-ahead energy, which requires increased coordination among participants. As it works to attract members, the ISO faces strong competition from SPP’s Markets+ day-ahead offering, which has generated especially strong interest in the Northwest.  

The commissioners offered no comments before approving the request, which LADWP officials, including General Manager Martin Adams, submitted in a Feb. 5 letter and accompanying resolution. 

“EDAM builds on the success of WEIM, providing additional benefits to its participants while increasing regional coordination, supporting policy goals of the state of California and meeting demand more efficiently,” the letter said. 

LADWP estimates EDAM will increase its net revenues by $20 million to $59 million a year, with most gains “expected to result from savings in adjusted production costs and enhanced EDAM transmission-related congestion transfers,” the officials said in the letter. LADWP realized nearly $149 million gross benefits from its participation in WEIM in 2023, according to CAISO. 

The utility expects to incur about $14.7 million in setup costs to join EDAM, including system upgrades, training and ISO onboarding fees. It also estimates $21.1 million in annual costs for ongoing participation in the market, mostly stemming from administrative fees. 

“Overall, EDAM presents a strong net annual financial opportunity while helping LADWP better integrate additional renewable generation, thereby minimizing curtailments and greenhouse gas emissions in its service territory and the Western region,” the letter said. 

Extensive Reach

While LADWP’s service territory is limited to the city of Los Angeles, its reach extends far into other parts of the West. The utility owns and operates more than 3,600 miles of transmission lines spanning five states, including half the capacity on the 3,100-MW Pacific DC Intertie linking the L.A. metro area with the Bonneville Power Administration’s area in the Pacific Northwest. 

LADWP’s other interstate transmission assets include 60% of the contract capacity rights on the Southern Transmission System line connecting Southern California with the Intermountain Power Project (IPP) in Utah, a 36% ownership stake in the Mead-Adelanto Transmission Project connected to Nevada, and co-ownership of the Navajo-McCullough Transmission Line between the now-retired Navajo Generating Station in Arizona and the McCullough substation in Nevada. 

The utility also controls about 8,000 MW of generating capacity, including the 1,900-MW coal-fired IPP, 15% of the output from the 2,080-MW Hoover Dam in Nevada, and 5.7% of output from the 3,300-MW Palo Verde nuclear generating station in Arizona. 

IPP is slated for conversion to an 840-MW natural gas-fired plant in 2025, including turbines capable of burning a fuel mixture containing 30% hydrogen. Last year, LADWP was authorized to convert its Scattergood Generating Station, the largest gas-fired plant in Los Angeles, to hydrogen. 

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CEC Approves $1.9B for ZEV Infrastructure

The California Energy Commission approved a plan for spending $1.85 billion over the next four years to expand zero-emission vehicle infrastructure across the state. 

The bulk of the money — $1.15 billion — will go toward infrastructure for medium- and heavy-duty ZEVs. That includes $130 million for zero-emission infrastructure at ports. The funding is for battery-electric charging as well as hydrogen fueling. 

For light-duty vehicles, the plan includes $658 million for ZEV infrastructure.  

The commission approved the investment plan for the Clean Transportation Program during its Feb. 14 business meeting. 

At least half of the money in the investment plan will be used to benefit disadvantaged communities. 

“We need to make sure that this is zero-emission refueling infrastructure for everybody,” said Commissioner Patty Monahan, the CEC’s lead commissioner for transportation. 

ZEV infrastructure is needed for residents of multifamily dwellings, rural areas, and dense places “that are suffering disproportionately from air pollution,” Monahan said in a statement after the vote. 

Monahan also noted that funding figures could change based on the state budget. (See Newsom Budget Would Trim Calif. Climate Spending.) 

“As we all know, this is a tough budget year,” she said during the commission’s meeting. 

Funding Sources

Funding in the investment plan comes from three sources: the state general fund; the Greenhouse Gas Reduction Fund (GGRF), which gets money from the cap-and-trade program; and the Clean Transportation Program, which is funded through a surcharge on California vehicle registration. 

For example, the plan allocates $230 million in GGRF money over four years for zero-emission drayage truck infrastructure. Electric school bus infrastructure will receive $125 million in each of the next three years from the general fund. 

The investment plan divides funding into general categories, with details of the programs to be worked out through the CEC’s solicitation process.  

In addition to funding for light-, medium- and heavy-duty ZEV infrastructure, the plan allocates $46 million for “emerging opportunities” in areas such as aviation, marine vessels and rail. And $5 million will go toward workforce training. 

The plan’s emphasis on infrastructure for medium- and heavy-duty ZEVs is due to the outsized impact conventional trucks have on air quality, the CEC said. 

Trucks account for roughly 2% of the 31 million vehicles registered in California. But they’re responsible for about 23% of on-road greenhouse emissions, as well as large shares of nitrogen oxides and particulate matter from the transportation sector. 

“For these reasons, medium- and heavy-duty vehicles represent a significant opportunity to reduce GHG and criteria emissions while focusing on a small number of vehicles,” the investment plan states. 

EV Charging Needs

California will require all new cars sold in the state to be zero emission by 2035. The state’s Advanced Clean Trucks and Advanced Clean Fleets regulations set timelines for transitioning medium- and heavy-duty trucks to zero emission. 

The CEC released a report in August projecting that the state will need about 1 million public or “shared private” chargers in 2030 to support 7.1 million plug-in electric cars. By 2035, the numbers are expected to grow to 2.1 million public or shared chargers needed for 15.2 million light-duty plug-in EVs. 

Currently, California has close to 94,000 public and shared private chargers, in addition to private chargers at homes and other locations. The CEC said in a release that funding in the new investment plan will result in about 40,000 new chargers across the state. 

Funding from other programs also will boost ZEV infrastructure. For example, the state is expecting to receive $384 million in federal funding through the National Electric Vehicle Infrastructure (NEVI) program. 

“Combined with previous investment plans, funding from the federal government, utilities and other programs, the state expects to reach 250,000 chargers in the next few years,” the CEC said.