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April 27, 2025

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Consumer Groups Invoke DOJ Stance in Stalled Complaint on ROFRs in MISO Planning

A collective of consumer groups has invoked a recent letter from the U.S. Department of Justice to get FERC to act on its three-year-old complaint against MISO for deferring to state right of first refusal laws in regional planning.

The complaint — from the Industrial Energy Consumers of America, the Coalition of MISO Transmission Customers and others — asks FERC to force MISO to brush off state ROFRs when planning transmission (EL22-78). FERC has yet to address it. (See Consumer Collective Again Asks FERC to Strike ROFR Laws from MISO Planning.)

In mid-April, Paul Cicio of Industrial Energy Consumers of America entered a letter into the record from the DOJ to Iowa State Sen. Jesse Green (R), urging the Iowa Legislature to rethink a reintroduction of the state’s ROFR law that was overturned in 2023. (See Iowa ROFR Law Overturned, Throwing Multiple MISO LRTP Projects into Uncertainty.)

Iowa legislators in early 2025 reintroduced an Iowa ROFR bill in the Senate (SB 1113).

The collection of consumer groups challenging MISO’s regard for ROFRs in planning has said Iowa provides a case study in the delay and litigation that ROFR laws introduced. It argues MISO should be able to disregard them.

The March letter from Assistant Attorney General Abigail Slater calls competition a “core organizing principle of the American economy” and said ROFRs’ bypass of competitive bidding disadvantages firms “that could offer lower prices, greater innovation and superior terms to Iowa’s utility customers.”

Slater reminded the Iowa Legislature that President Donald Trump declared a National Energy Emergency in early 2025 and that the DOJ has filed briefs in other cases that challenge the constitutionality of state ROFR laws.

“The bill turns a ‘preference for further investment in Iowa transmission infrastructure by electric transmission owners’ into a legal grant that shields incumbents from competition,” the letter said. “In some cases, incumbent operators will be best positioned to deliver high quality, cost-effective infrastructure projects quickly. But even in such circumstances the threat of competitive pressure from potential rivals will incentivize better outcomes like lower prices for consumers and more robust and innovative project designs. In other cases, non-incumbent firms may offer lower costs, and better project designs, and they should be allowed to compete on the basis of the better value they offer.”

MISO: Complaint Still Has No Legs

MISO, as it has for years, continues to oppose the complaint. In an early April response, it said the consumer alliance’s attempt to cut the state ROFR exemption from its tariff is a collateral attack on MISO’s accepted compliance under FERC’s Order 1000.

MISO in 2022 assigned several projects from its first, $10.4-billion long-range transmission plan (LRTP) portfolio to incumbent transmission owners in Iowa based on the valid state ROFR in place in Iowa at the time. The RTO pointed out that it wasn’t until early December 2023 that the Iowa District Court overturned the ROFR on a remand from the Iowa Supreme Court.

“MISO has been clear that, following the Iowa District Court’s decision on the merits, the Iowa ROFR law was no longer applicable, on a prospective basis,” the RTO said. It ended up using its variance analysis to examine project assignments in Iowa for the subsequent, $21.9 billion LRTP portfolio. MISO ultimately left that round of projects also to its incumbents, concluding the district court’s order did not change project assignments nor direct that projects be reclassified into competitive facilities. MISO also said the district court specifically said it was not a party to the court’s action.

“Far from indicating that the state ROFR exemption is unjust and unreasonable or otherwise unworkable, the tariff process worked in the Iowa case despite its complicated litigation posture and the attendant uncertainty,” MISO argued. “Further, to the extent the consumer alliance suggests that MISO must apply ROFR determinations retroactively for the state ROFR exemption to be just and reasonable, such a position lacks merit. The filed rate doctrine and the rule against retroactive ratemaking are clear that MISO cannot revisit such determinations without a binding legal directive from the commission, subject to the applicable FPA process.”

MISO acknowledged Indiana’s ROFR also is the target of fluid and complex litigation. (See 7th Circuit Lifts Injunction on Indiana ROFR, Remands LS Power’s Case.) The RTO said, so far, the ROFR has been in effect throughout the development of the second LRTP portfolio, and as such, it again assigned the lines to the incumbent transmission owners. It said it again would draw on a variance analysis to confirm project assignments in Indiana, if needed.

“MISO does not know what conclusion the federal courts ultimately will reach with respect to the constitutionality of the Indiana ROFR law. As the 7th Circuit recognized, there are many different unknowns at this time. … If the Indiana ROFR law is determined to be unconstitutional, MISO will give a prospective effect to any such determination, consistent with the filed rate doctrine and any directives from the commission,” MISO said.

The grid operator pushed back against the consumer alliance’s claims that MISO “default[s] to incumbent project assignment regardless of questions regarding the constitutionality of state laws.” It said it was simply applying its tariff as written.

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Oregon House Passes Bill to Shift Energy Costs onto Data Centers

The Oregon House of Representatives has approved a bill that would require data center developers to shoulder a larger share of their own energy costs in an effort to mitigate risk to smaller consumers. 

House Bill 3546, or the POWER Act, passed in a 41-16 vote on April 22. It empowers the Oregon Public Utility Commission to create a separate customer category for large energy users, such as data centers, and requires those users to pay a proportionate share of their infrastructure and energy costs. 

The legislation now moves to the state Senate. 

Rep. Pam Marsh (D), one of the bill’s chief sponsors, said the “explosion of huge technology facilities has upended” the traditional idea of distributing energy demand costs equally among consumers. 

“Since 2019, data center growth in [the Portland General Electric] territory has been equivalent to an increase of 400,000 residential customers, but residential demand has actually grown by only 63,000 people, or 24,000 customer accounts,” according to Marsh. “Without intervention, the cost created by the disproportionate demand of big energy users will be borne by residential and small business consumers who are already struggling.” 

The bill defines a large energy use facility as one that uses more than 20 MW. The law would apply only to Oregon’s investor-owned utilities. 

Additionally, under the bill, data centers must sign contracts for at least 10 years with energy companies to protect energy infrastructure investments. The contract requires the data center operators to pay for a minimum amount of energy based on the center’s expected energy usage during the contract period, and “[m]ay include a charge for excess demand that is in addition to the tariff schedule,” according to the bill. 

“If a utility is going to make investments to serve a large user, we need some assurances that those investments do not become a stranded asset that is essentially shifted to other ratepayers,” Marsh said. 

The bill also requires the Oregon PUC to provide the legislature with reports detailing trends in load requirements. 

Kandi Young, a spokesperson for the PUC, told RTO Insider that the commission “appreciates the legislature’s recognition of the challenges new large loads can present to utilities and their customers. The PUC already is working to help ensure that other electricity customers do not inappropriately pay for the costs to serve these large users of electricity and will work with stakeholders from all perspectives to implement additional policy direction on this issue should the bill be signed into law.” 

Pacific Power spokesperson Simon Gutierrez said the utility, a subsidiary of PacifiCorp, “supports HB 3546 as a meaningful framework to ensure continued economic growth with fairness for all customers.” 

“While the existing regulatory framework is established to protect customers and align the costs of energy infrastructure with the customers benefiting from these investments, the scale, pace and uncertainty surrounding this potential load growth [require] additional regulatory updates to protect all customers while creating a path for large customers to expand their businesses,” he said. 

Organizations like the Northwest Energy Coalition, BlueGreen Alliance and Sierra Club have supported the bill. 

‘Disparate Rate Treatment’

The bill also faced opposition. Republican Rep. Bobby Levy called it a “regulatory overreach.” 

Data centers are “legally operating businesses already regulated under existing PUC authority, and they provide critical infrastructure, jobs [and] economic development, especially in rural areas,” Levy said. “Under this bill, they would face entirely separate tariff schedules, new reporting burdens and regulatory uncertainty, not because they’ve done anything wrong but because they’ve grown and used power efficiently.” 

Writing in opposition to the bill in March, the Data Center Coalition, a membership association, said it “supports the underlying intent of HB 3546, and the data center industry is committed to paying its full cost of service.” 

But “no customer, industry or class should be singled out for differential or disparate rate treatment unless that approach is backed by verifiable cost-based reasoning,” DCC wrote. “Data centers are but one large end user of electric utilities and part of a larger portfolio of end users driving increased electricity demand. Any rate design that focuses on a single end use, without showing a measurable difference in service requirements or cost responsibility, risks creating unjustified distinctions among similar customers.” 

Shannon Kellogg, vice president of public policy at Amazon Web Services, which has been operating data centers in Eastern Oregon since 2011, provided neutral testimony, writing that “a significant bottleneck to bringing new carbon-free energy projects online is the interconnection process to the grid.” 

“To unlock these projects, it is important for transmission infrastructure and regional energy systems to modernize and expand quickly, and we are working closely with lawmakers and regulators to accelerate these changes,” Kellogg wrote. 

The proposed legislation comes as data center growth in Oregon has increased rapidly. The amount of data centers seeking service “is unprecedented,” according to an Oregon Citizens’ Utility Board presentation. 

In December 2024, WECC predicted that annual demand in the Western Interconnection would grow from 942 TWh in 2025 to 1,134 TWh in 2034. That 20.4% increase is more than four times the 4.5% growth rate from 2013 to 2022 and double the 9.6% growth forecast in 2022 resource plans. (See West to See ‘Staggering’ Load Growth, WECC Report Says.) 

Similarly, the Pacific Northwest Utilities Conference Committee’s Northwest regional forecast for 2024 found that electricity demand would increase from about 23,700 average MW in 2024 to about 31,100 aMW in 2033, an increase of more than 30% in the next 10 years. 

In February, Washington Gov. Bob Ferguson directed three state agencies, electric utilities and other groups to collaborate in developing a report recommending policies for addressing with data center energy use. (See Wash. Governor Orders Study to Explore Data Center Impact.) 

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Texas RE Speaker Emphasizes Human Role in Security

Devin Ferris, the Texas Reliability Entity’s manager of critical infrastructure protection compliance monitoring, did not mince words in his briefing on cyber readiness at the regional entity’s Spring Standards, Security and Reliability Workshop on April 23.

“It’s important to understand what we’re up against. The threat landscape is changing; the speed at which it is changing, the volume the sophistication of those threats, is ever-increasing,” Ferris said. “Attackers are using [generative artificial intelligence], and that’s changing the game on certain things. These attackers are able to gain initial access quickly, weaponize whatever they’re doing, exploit it, and be out of there and cover their tracks.”

Despite his invocation of AI and other new technologies, Ferris emphasized that one of the biggest risks entities face is an old one: human error. But, he continued, this danger also represents an opportunity.

“You hear a lot in the security world [that] people are the weakest link in security,” Ferris said. “That could be true, but I truly believe if you shift your mindset on that, you could turn it on its head. You can create a culture of security, and they are going to be the strongest link in that.”

The theme of Ferris’ presentation was the risks posed by low-impact grid cyber systems, which NERC defines as systems not considered a significant risk to grid security. He told attendees that while some might assume these systems are low priority, Texas RE and the ERO in general have devoted considerable attention to them in recent years because “there’s a lot of growth in that space,” particularly with the rapid spread of internet-connected inverter-based resources “that are more than likely going to be low-impact.”

In his presentation, Ferris aimed to help utilities prepare for compliance audits of CIP-003-8 (Cybersecurity – security management controls). The standard requires entities to have “consistent and sustainable security management controls that establish responsibility and accountability to protect [high-, medium- and low-impact] cyber systems against compromise that could lead to misoperation or instability in the” grid.

Rather than give the bulk of his time to compliance, Ferris said he wanted listeners to think more about risks, saying that “if you mitigate these risks, you can effectively still … achieve compliance. It’s going to be a byproduct of that.”

For example, he noted that CIP-003-8 requires entities to permit only “necessary” inbound and outbound electronic access. With many new IBR facilities relying on remote connections, this requirement creates a challenge for utility staff.

“One of the risks that you have is if you haven’t identified what’s necessary, and you’re proactively looking to see if access is still needed on a periodic basis, you may not be able to address it, and so the compliance and risk overlap,” Ferris said. “And when you do these reviews, if you’re documenting what the justification … or your business need is, it’s going to help you make sure that only necessary rules are in place and that you still need them as access changes and you implement new technologies, or there’s different threats you’re trying to mitigate.”

He then returned to the theme of human error, noting that phishing and social engineering frequently are used by attackers to gain a foothold in a target system. Without knowledgeable, educated staff, he warned, utilities remain vulnerable to such attacks, especially with their systems increasingly dependent on remote connections.

Ferris said that multifactor authentication (MFA) can be an effective way to mitigate the phishing and social engineering risks, but he urged listeners to remember that “some are better than others.” An MFA approach that uses a hardware key may be more effective than one that depends on text messages or an app.

Human attention remains the most important factor, Ferris said, as much for physical security as for cybersecurity. Whether it involves periodic checks of cyber access permissions or walk-downs of fences and other physical infrastructure, utilities must maintain awareness of who is allowed into their systems and why.

“The key to all of this, to remain compliant and be reliable and address those risks, is, are you controlling the access? Because that’s what the standard says you have to be able to control,” Ferris said.

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NextEra Energy Continues to Rack up Renewables Deals

NextEra Energy posted solid first-quarter financials and said its renewables portfolio continued to grow even as President Donald Trump began implementing pro-fossil fuel policies.

CEO John Ketchum said during an April 23 conference call that wind, solar and storage are indispensable now as the U.S. expects to need a lot more megawatts because renewables can be brought online much faster than natural gas generation and much, much faster than nuclear.

He called renewables “a critical bridge” to a future when other technologies can be brought online at scale.

Until fairly recently, many people were calling natural gas the “bridge fuel” to a decarbonized future. But natural gas has problems, said Ketchum, whose company is an all-of-the-above energy provider operating renewable, nuclear and natural gas generation.

The cost to build a gas plant has tripled in just a few years, and Trump’s tariffs will drive the cost higher, he said. Meanwhile, companies building LNG export terminals, factories and data centers have lured away the skilled workers who would build gas plants, and gas turbine manufacturers are booked up with yearslong wait times on new units.

“Gas is such a long-term solution,” Ketchum told analysts on the conference call. “We’ve gone up from four and a half years to build a combined cycle unit to six or longer.”

This state of affairs, he said, calls for energy realism — understanding the high demand and embracing all solutions — and calls for energy pragmatism — recognizing that some solutions are not ready today and accepting the tradeoffs this implies.

“Renewables and battery storage are the lowest-cost form of power generation and capacity,” Ketchum said, “and we can build these projects and get new electrons on the grid in 12 to 18 months.”

The U.S. is expected to need more than 450 GW of new generation by 2030, he said, and only 75 GW of that is expected to be natural gas fired. Canceling every planned coal retirement would yield only about 40 GW more. Meaningful increases in nuclear generation are 10 years away at best and likely to be much more expensive than gas when they arrive, he added.

In this scenario, NextEra expects to thrive, despite renewables suddenly falling into presidential disfavor.

In the first quarter, subsidiary NextEra Energy Resources originated 3.2 GW of new renewables and storage and scored its largest-ever quarter for solar and solar-plus-storage origination, bringing its project backlog to 28 GW.

Meanwhile, subsidiary Florida Power & Light placed 894 MW of new solar generation into service, bringing its owned-and-operated solar portfolio to more than 7.9 GW — the most of any U.S. utility.

“We continue to see a lot of appetite for renewables,” Ketchum said.

And what of the actual and threatened tariffs that are causing such consternation in so many sectors of the economy? NextEra began to get ready for this years ago. Because it is so large and its competitors are mostly small, it had the leverage and buying power to shift tariff risks onto suppliers in most of its contracts, Ketchum said. NextEra forecasts only $150 million in tariff exposure through 2028 on $75 billion in projected capital expenditures, he said, and may be able to negotiate that exposure down as low as $0.

It also shifted to U.S.-made components, where possible.

“We didn’t just wake up on Nov. 6 and say, ‘Oh my God, what do we do about our supply chain?’” Ketchum said. “We’ve been thinking about this for years, and so we put the right things in place.”

NextEra reported first-quarter revenue of $6.25 billion, up from $5.73 billion a year earlier, and GAAP net income of $833 million ($0.40/share), down from $2.27 billion ($1.10/share).

Adjusted (non-GAAP) earnings were $2.04 billion ($0.99/share), up from $1.87 billion ($0.91/share).

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All-electric Rebuild After L.A. Fires Could be Better than Dual-fuel, Report Finds

Los Angeles leaders should consider rebuilding the more than 20,000 structures destroyed by the January 2025 wildfires as all-electric rather than as dual-fuel despite the potential higher life cycle costs of all-electric buildings, a new report finds. 

After the fires, which burned for much of January, L.A. Mayor Karen Bass issued an executive order that temporarily waived the city’s all-electric building code requirement for rebuilding projects in fire areas, the report by the U.C. Berkeley Center for Law, Energy and the Environment says.  

Typically, an all-electric new single-family home can be $7,500 to $8,200 cheaper to build than a dual-fuel home, while installing a gas line to a new home can cost between $500 and $2,000, according to the report.

But in the neighborhoods burned by the fires — specifically the Pacific Palisades and Altadena — much of the existing natural gas underground piping was undamaged. This negates savings typically found on new construction sites where natural gas infrastructure must be built from scratch.  

Along with reusing existing gas piping, rebuilding homes as dual-fuel homes could be cheaper due to bills: Natural gas bills in L.A. currently are lower than electricity bills for most residents, the report says.  

“Given the possibility of high electricity costs into the future, the most cost-effective option over the building life cycle may be a dual-fuel rebuild, but this scenario is uncertain and necessarily affected by the context of the climate transition in California,” the report says. 

In the long run, all-electric homes could end up as a better investment for a homeowner if more buildings in the region switch to electric-only service. In such a future, there would be fewer ratepayers to share the burden of gas recovery costs, thereby increasing the cost of gas bills.   

All-electric buildings also provide other benefits to homeowners, such as improved indoor air quality, the report says. Natural gas contains volatile organic chemicals (VOCs) that are associated with numerous adverse health impacts and generate indoor air pollution even when appliances, such as stoves, are turned off. Switching from a gas stove to electric induction can reduce indoor nitrogen dioxide air pollution by over 50%, the report says. 

As for speed, all-electric construction tends to be faster than dual-fuel construction: Many rebuilt homes will need to issue separate gas and electric service requests, creating potential coordination issues. Additionally, electricity service will be restored to all homes and businesses regardless of the recovery approach, the report says. 

Policymakers should support streamlining all-electric construction and facilitating electricity affordability, while educating consumers about the cost effectiveness, speed, safety and sustainability of all-electric infrastructure, the report says. 

Last month, Mayor Bass issued an executive order directing city departments to streamline pathways for all-electric and fire-resistant construction.  

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Maine PUC Seeking Feedback on Transmission, Generation Procurement

The Maine Public Utilities Commission is seeking feedback and indications of interest for a procurement of generation and transmission capacity to connect at least 1,200 MW of clean energy in Northern Maine to ISO-NE.

State law requires the PUC to seek long-term contracts for generation in Aroostook County and for a new transmission line to connect it to ISO-NE. The sparsely populated county has significant clean energy potential owing to its high wind speeds, but Northern Maine is not directly connected to the ISO-NE system, instead connecting to the Eastern Interconnection through New Brunswick, Canada.

Policymakers and developers in the region have long seen the region as a potential source of cheap power. ISO-NE and the New England States Committee on Electricity (NESCOE) have focused the first Longer-Term Transmission Planning (LTTP) procurement on facilitating the interconnection of 1,200 MW of onshore wind and alleviating transmission constraints in the southern part of the state. (See ISO-NE Releases Longer-term Transmission Planning RFP.)

The PUC has said it aims for its procurement to be complementary to the LTTP procurement, which is being run by ISO-NE. In the request for information issued in early April, the PUC asked for feedback on how to best coordinate and sequence its solicitation with the LTTP process (DPU 2024-00099).

The RFI highlights some unique challenges and questions associated with coordinating the two procurements. ISO-NE’s request for proposals features a Sept. 30 submission deadline, and the RTO does not expect to select a project until fall 2026. There also is no guarantee that a project will emerge from this RFP, as NESCOE has the right to terminate the process even if a proposal is selected by the RTO.

If Maine waits until the conclusion of the LTTP process to proceed with its own procurement, this likely would push its process back for more than a year.

The state also must grapple with the challenges of simultaneously procuring generation and transmission. The PUC asked for input on the interdependencies between these two aspects of its procurement, as well as on potential “advantages or disadvantages to allowing or prohibiting combined or linked transmission and generation project proposals.”

The PUC is seeking feedback on potential contact adjustments and flexibility for generation projects to account for risks of transmission delays. The PUC also asked for input on long-term contract length, inflation adjustment mechanisms, mitigating permitting risks, the availability of federal funding and tax credits, and the potential impact of federal policy, tariffs and federal permitting requirements.

The RFI also includes questions about partnering with other states for the procurement, as the statute specifically directs the state to seek partnerships with other states and utilities. Massachusetts previously agreed to buy up to 40% of the generation and transmission capacity from an earlier iteration of this solicitation, but the Maine PUC terminated this procurement after LS Power said it could no longer meet its fixed price due to delays associated with negotiating contracts in Massachusetts (DPU 2021-00369).

In October 2024, the U.S. Department of Energy under President Joe Biden agreed to serve as the anchor off-taker for an Avangrid proposal to build transmission into Northern Maine, awarding the project up to $425 million to help de-risk the project. (See Long Road Still Ahead for Aroostook Transmission Project.)

At the time, Avangrid said it expected the PUC to announce winning bids at some point in 2025. This timeline now seems highly unlikely, and federal policy changes may pose a significant threat to the funding.

The PUC is requesting feedback from stakeholders by June 2, with supplemental comments due at the end of September. It also asked developers to submit indication of interest forms by June 2, which should include “a brief description of the project or projects they would develop” and “a description of how the project(s) would be impacted by different possible outcomes of the ISO-NE regional solicitation.”

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SPP MPEC Members Celebrate Markets+ Funding Order

DENVER — FERC’s approval of SPP’s Markets+ funding agreement and its recovery mechanism came as interested participants in the Western centralized day-ahead market were meeting with the snow-capped Rockies as a backdrop. 

They cheered when they were notified of FERC’s decision during their April 22 Markets+ Participant Executive Committee (MPEC) meeting. Then they went back to work. (See FERC Approves SPP’s Funding Plans for Markets+.) 

“We’re in go time,” MPEC Chair Laura Trolese, with The Energy Authority, told RTO Insider. 

“Getting the FERC approval was super exciting. We got FERC approval both on the Markets+ funding agreement but also the final order on the last items last week,” she said, alluding to the commission’s April 17 approval of SPP’s final compliance filing for Markets+. (See FERC OKs Final SPP Markets+ Compliance Filing.) 

“We needed those two things to move forward with implementation activities and timeline,” Trolese added. 

Joe Taylor, Xcel/PSCo | © RTO Insider

Joe Taylor, with Xcel Energy subsidiary Public Service Company of Colorado (PSCo), said his company was pleased with the approval, which he said was not unexpected. PSCo filed a request in February with the Colorado Public Utilities Commission to join Markets+ and recover costs from its funding agreement. (See PSCo Seeks to Join SPP’s Markets+.) 

“We made our filing assuming that [SPP’s request] was going to be approved, and it was,” Taylor said. “It was an expectation that the funding agreement would be approved, because then we can go forward and participate and execute that agreement.” 

SPP’s Carrie Simpson, who broke the news to MPEC, recognizes that Markets+ development faces a long and winding road ahead. 

“It’s just another important milestone. We’re grateful for it, and it will set us up for Phase 2,” she told RTO Insider. 

FERC issued two orders in approving SPP’s proposed funding mechanism: 

    • The first accepted SPP’s proposed $150 million Phase 2 funding agreement as a rate schedule under the Markets+ tariff, effective March 24 (ER25-1372).
    • The second granted SPP’s request to issue debt securities to cover the agreement and fund the market’s implementation over three years until its go-live date, effective April 21 (ES25-33).

SPP has set the go-live date as Oct. 1, 2027. 

In its Feb. 21 filings, the grid operator told FERC the funding agreement will ensure those participants that benefit from the market will fund its development and share in overhead costs. 

SPP said the funding agreement is a freely negotiated contract between the RTO and each of the eight entities that have agreed to participate in Phase 2 and provide collateral to SPP’s lender equal to the amount of their obligations: Arizona Public Service, Bonneville Power Administration, Chelan County (Wash.) Public Utility District (PUD), City of Tacoma, Grant County (Wash.) PUD, Powerex, Salt River Project and Tucson Electric Power. 

The funding agreement requires the entities to provide the collateral backstop to SPP’s lender in supporting the financing the RTO will use to develop Markets+’ systems, processes and operations during implementation. The collateral is equal to the amount of the entities’ Phase 2 obligations. 

SPP says the cost to repay the financing will be incorporated into Markets+ rates and will relieve participants from the burden of providing “large sums of money to directly fund Phase 2.” SPP is splitting the phase into two stages, with participants required at first to provide collateral equal to two-thirds of their Phase 2 obligation. The first stage expires six months after the initial funding threshold has been met, at which point participants must provide collateral equal to their full Phase 2 obligation. 

As a federal agency, BPA — the major industry player in the Pacific Northwest — can’t post collateral to back up its commitment. BPA instead will provide a letter of assurances from its COO that explains its authority to enter into the agreement and statutory obligation to pay part or all of its Phase 2 obligation, whichever is effective at the time.  

5 Steps of Funding

The funding agreement is composed of five stages: 

    • When the funding threshold is met by entities that are or represent at least two contiguous balancing authorities and not less than 200,000 GWh of 2023 net energy for load execute the funding agreement. That was met Feb. 13 when funding agreements first were signed. (See SPP Secures Funding to Begin Markets+ Phase 2.)
    • When financing conditions are met with the financing’s regulatory approval and when SPP executes the loan agreement.
    • When participants provide collateral to back financing determined by their Phase 2 obligation in the form of cash or a letter of credit. The obligation is the participant’s pro rata share of Markets+’s total cost less its Phase 1 and post-Phase 1 payments. (Funding participants withdrawing from the agreement must pay their Phase 2 obligation to SPP, protecting the remaining participants from the withdrawal.)
    • When SPP obtains funds drawn from the loan or received under the funding agreement to acquire, create and/or modify the systems and processes required to implement Markets+.
    • When financing costs are repaid after go-live. Phase 2’s implementation costs will be incorporated into market rates charged to participants through a tariff schedule. SPP will repay the financing as the costs are recovered and the lender authorizes the release of excess collateral on an annual basis. The funding agreement will terminate when SPP notifies participants that the financing has been fully repaid, including all principal, interest and fees.

FERC found the funding agreement will provide a framework for SPP to begin the market’s development phase. It said the funding participants’ provision of collateral and Phase 2 cost-recovery ensures that only Markets+ beneficiaries — and not SPP RTO members — are responsible for the development costs. 

The commission declined to direct SPP to provide a commitment that its RTO members will not be responsible for the financing costs. “SPP has already provided sufficient commitment that this will be the case,” FERC said. 

“In addition, the funding agreement itself does not implicate SPP RTO members in the event of a default or withdrawal of a funding participant,” the commission added. 

FERC rejected several concerns raised by public interest organizations (PIOs) around BPA’s connection to the agreement. The groups, which include Northwest Energy Coalition, Idaho Conservation League and Public Citizen, said the agreement effectively would obligate Bonneville to participate in Markets+ ahead of issuing its formal record of its participation decision (ROD) on its day-ahead market participation because it would be on the hook for providing up to $40 million in implementation costs to SPP even before releasing the ROD. They contended that either SPP’s filing had mischaracterized BPA’s commitment to Markets+ or the agency had been engaging in a “sham” process regarding its day-ahead market decision. 

“We disagree with PIOs that the funding agreement requires Bonneville (or any other funding participants) to participate in Markets+,” FERC wrote. “As PIOs acknowledge, the funding agreement requires a funding participant to pay its Phase 2 obligations in the event it decides to withdraw from the funding agreement; however, the funding agreement does not obligate any funding participant to proceed with Markets+ participation.” 

The commission found in its second order that while SPP didn’t meet FERC’s interest-coverage ratio threshold, the grid operator cited other factors that gave it a “sufficient alternative basis” to determine the RTO had “reasonable prospects for being able to service the proposed new debt securities.” FERC said the Markets+ tariff, approved this year, will provide for the recovery of all of the proposed indebtedness’ financing costs. 

“Furthermore, we note that SPP has secured commitments from the funding participants, which guarantees that SPP will be able to repay its debt obligations related to Markets+,” the commission wrote. It added that SPP’s plans to recover the implementation’s costs will not make its RTO members responsible for the market’s costs. 

FERC set the loan’s interest rate not to exceed the total of a one-month secured overnight funding rate and a spread determined by the amount of cash collateral obtained from the funding participants. 

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N.J. BPU Backs Wind, Solar Adjustments Amid Dissent

New Jersey’s Board of Public Utilities backed measures to keep on track one of its three remaining offshore wind (OSW) projects and retool a large-scale solar incentive program, triggering two dissenting votes in a rare break in the board’s usual unanimity.

The two opposing votes highlighted the stresses within the board as it seeks to boost the state’s energy capacity to meet an expected future electricity generation shortfall and prepare ratepayers for a related rate hike of 17 to 20% on June 1.

The board voted 3-1 on April 23 to grant a deadline extension requested by Attentive Energy that would stay the enforcement of two obligations resulting from the board’s approval in January 2024 of the 1,342 MW OSW project. Without the stay, the developer would have had to pay a security commitment of about $16.7 million and a fee of $3.75 million that originally was due Jan. 24, 2025. (See NJ Awards Two Offshore Wind Projects.) The requirements now will be on hold until Jan. 24, 2026.

In an unrelated vote, the board also voted to modify the state Competitive Solar Incentive (CSI) program that awards incentives to so-called “grid scale” projects, those with a capacity greater than 5 kW. In a 3-1 vote, the board agreed to open the next solicitation — the state’s third under the CSI program — on May 4, 2025, with a goal of procuring 300 MW of solar generation capacity and 160 MWh of energy storage paired with solar.

In response to the last solicitation, in which two of the five project categories went unfilled, the board voted to broaden the permitted projects in the next solicitation to include those on open land in industrial and commercial complexes.

The board also agreed to set a different price cap — or limit — to the incentive level for each of the five categories of projects. The caps are designed to “balance the developers’ ability to seek a vital incentive with effective ratepayer protections,” according to a BPU staffer who explained the changes.

Board Dissent

In a rare display of opposition, Commissioner Zenon Christodoulou said he could not support the measure and attacked the process through which it was made.

While he didn’t specify the exact problems that triggered his concern, Christodoulou said he believes that “free market capitalism and creative innovations are the best ways to develop and improve products and services.

“Constraining mature industries by keeping them tethered and dependent on external subsidies ignores the full capacity of human ingenuity, market forces and competition,” he said. “And it passes that financial burden on to others: in this case, ratepayers.”

He acknowledged that “dissenting opinions are not common and quite often and unfortunately discouraged” on the board and said board discussions had “revealed a very shielded managerial process.”

“I have made my opinions known on many occasions over the last year and a half,” he said. “And I continue to observe that outside opinions, including mine and others, are dismissed and marginalized.

“This flawed internal process worries me deeply,” he said. “The lack of transparency, two-way communications and the palpable aversion to outside inputs troubles me.”

In response, BPU President Christine Guhl-Sadovy said that “not every outcome is going to be unanimous.”

“Agreeing to disagree is OK,” she said. “What we do know about solar and competitive solar and large-scale solar is that it helps to bring costs down for ratepayers by providing the necessary generation that we need, which you know, at this time is even more important than ever.”

She added that large-scale solar provides a “price suppression implication, and that’s really important for customers.”

The board also voted to open a new solicitation on April 30 of the state Community Solar Energy Program, offering 250 MW of capacity, with a closing date of May 13. The board order cut the incentive, from $90/MWh in the last round, to $80/MWh.

That 11% cut “represents a reasonable balance between the need to accelerate solar deployment in New Jersey without excessive immediate change and the need to keep costs manageable for ratepayers,” the board order said.

Mitigation Strategy

The votes come as the BPU completes a new state Energy Master Plan, a draft of which predicts a 66% increase in electricity demand by 2050. PJM has said the state, like others, faces a future generation imbalance that involves the rapid pace of fossil fuel plant closures, the far slower development of new generating sources and an expected demand surge propelled by electric vehicles and data centers.

State officials say the expected shortfall helped push up bid prices in the state’s Basic Generation Service auction, contributing to the upcoming 17 to 20% consumer rate hike.

Seeking a way to help ratepayers mitigate the increase, the board voted unanimously to enact a campaign to encourage ratepayers to reduce their energy use and to solicit proposals from the state’s utilities on how to achieve that.

“We understand that the timeline to turn around these proposals is short,” but the goal is to reduce ratepayer costs, said Guhl-Sadovy.

‘Pivot’ Needed

New Jersey planned to meet a portion of its future electricity demand with offshore wind. But the state’s three OSW projects struggled even before President Trump’s sweeping executive order on Jan. 20 temporarily froze the nation’s OSW projects.

New Jersey’s most advanced project, Atlantic Shores, received construction and operations plan approval from the federal Bureau of Ocean Energy Management in October, but the U.S. Environmental Protection Agency on March 14 placed a hold on the project. The state’s third project, the 2,400-MW Leading Light Wind, received a deadline extension from the BPU in September to give the developer time to find an economically viable turbine. (See EPA Puts Hold on Atlantic Shores OSW Permit.)

The upheaval in the sector began when developer Ørsted abandoned its Ocean Wind project in October 2023, citing cost and supply chain problems. (See New Jersey BPU Approves Invenergy Offshore Wind Delay.)

Commissioner Michael Bange, before voting against the order to extend the Attentive Energy deadline, said the board had done “everything it could to make offshore wind happen.” Yet a new approach is needed given that “the current federal administration is not in favor of it, and has done everything to stop it,” he said.

“We need to pivot and focus on storage, solar, energy efficiency and other ideas that can help reduce energy prices,” he said. “Even if offshore wind was possible in the future, we would have to start the bid process over, due to [the] tariff war in place, uncertainty of future pricing, supply chain issues and investment monies to support it.”

Christodoulou said he shares some of those concerns. But he said he would vote for the measure anyway, based on assurances from BPU staff that approving the deadline would not cost the state anything or set a precedent for the project or others in the future, and would keep the project viable.

“I’m hopeful, but not entirely optimistic, that this can get done at some future date,” he said.

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ACORE Report Explains How to Get Advanced Transmission in Regional Plans

If FERC Order 1920 is implemented correctly, it could expand the role of grid-enhancing technologies (GETs) and high-performance conductors (HPCs) to help meet surging power demand in the near term, according to a report prepared by the Brattle Group for the American Council on Renewable Energy.

Demand forecasts have grown significantly since FERC started the rulemaking process that produced Order 1920, report lead author and Brattle Principal Bruce Tsuchida said on an April 22 webinar. That comes on top of the underlying need to replace aging transmission, which the report estimated would cost $10 billion annually over the next decade.

“If you’re a state right now, and you’re looking at the wave of infrastructure that’s coming down the pipe to meet load growth, you probably are wondering, ‘how much is this going to cost me?’ And maybe, ‘how could I shave off some of that cost? How can I save some money?’” GQS New Energy Strategies Principal Liz Salerno said. “And advanced transmission technologies come right to the rescue here.”

GETs and HPCs are mature, proven technologies, and the report’s analysis found they can provide all seven benefits required for consideration under Order 1920, Tsuchida said in a statement.

“Transmission providers can use a holistic evaluation method when assessing various benefits and comparing potential transmission solutions,” he added. “These technologies will likely shine through as a lower-cost option to ensuring reliable, affordable power for ratepayers.”

Many utilities have not adopted advanced transmission technologies (ATTs) because they are unfamiliar with them, and their investment incentives are not aligned well with the technologies, Tsuchida said.

“There’s also the fact that a lot of the cost associated with transmission — for example, if there’s an outage, or if there’s congestion, or if there’s more investment needed — that is passed through to the end-use customers, while the transmission service providers may not necessarily feel that immediately,” he said.

Transmission needs are growing rapidly, so much so that the pace of traditional transmission development cannot keep pace. Traditional wire projects can take five to 10 years to develop and often are hindered by regulatory delays, the complexity of interregional coordination, cost allocation and permitting, the paper says.

“Because of the three characteristics discussed above (lower cost and speedier installation, complementarity to existing equipment, and portability and reversibility), ATTs can provide cost-effective solutions in a shorter schedule than relying solely on the traditional wires-based solutions,” the report says. “Additionally, the fragmented nature of transmission planning and cost allocation often stalls large projects; HPCs, through reconductoring, can reduce the scope of new upgrades, while GETs can offer incremental upgrades that align with the scenario-based, collaborative approach emphasized in Order 1920.”

ATTs need to be used in short- and long-term planning, with the report saying that splitting the various solutions into those two time frames (or even more granular ones) will allow planners to address challenges that span immediate needs and flexible goals.

GETs can provide near-term relief to transmission congestion and improve grid efficiency without the delays of traditional transmission investment. Both GETs and HPCs can help modernize the grid, integrate new technologies, and prepare for future demand and renewable growth in a cost-effective way, the report says.

Order 1920 requires grid planners to consider seven benefits of new transmission, two of which are temporary, such as lowering congestion from outages, and the mitigation of extreme weather events and unexpected system conditions. Assessing their benefits will require planners to consider shorter time frames than normal, the paper says.

“Associated with the new temporal scenarios to analyze, transmission providers will need to develop methodologies on how to consider benefits (and costs) over varying timelines,” the report says. “For example, evaluating a potential solution could require analyses over multiple timelines to capture the benefits and associated trade-offs among benefits (a solution could impact several benefits) over different timelines.”

Compliance with Order 1920 is proceeding at different paces in some regions, with FERC having granted some extensions. In PJM, Maryland Public Service Commissioner Michael T. Richard said on the webinar the RTO is working with states and stakeholders on complying with the new rule.

“I do think we need to make sure this is not going to be just status quo; a new kind of [Regional Transmission Expansion Plan] that is just extended,” Richard said. “And in fact, it is going to be a planning opportunity with the states at the center. The core of the plan for the future needs to be how the states envision their resources … and then we can work to make sure that we all have the same goal: keep the lights on.”

While compliance is proceeding, GQS Principal and former FERC Chair Richard Glick (who launched the rulemaking process that led to Orders 1920 and 2023) said in a statement that those efforts will take time.

“In the meantime, action is needed to address more immediate threats to reliability and affordability,” Glick said. “This report shows that GETs and HPCs offer a near-term capacity solution while grid operators continue to plan the regional transmission lines needed to meet future challenges.”

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MISO: New Software Effective, Faster than Previous Queue Study Process

MISO has concluded that Pearl Street’s SUGAR automation software is an effective alternative to the power flow simulations it used to conduct to identify network upgrades for generation projects in the queue.  

MISO released an analysis comparing the software’s ability to pinpoint upgrade needs for new generation entering the system with MISO’s previous analyses on the 2021 cycle of generation proposals. The RTO said SUGAR performed at a 99.23% match rate with “minimal deviations” when searching for thermal constraints, a 100% match rate with some extra identified constraints when looking for flowgate limits and a 99.03% match rate when spotting voltage issues with “justified” minor violations.  

Ahead of the analysis, MISO said SUGAR would have to identify at least 98% of constraints uncovered through its legacy analyses to be considered a success. MISO said across all three comparisons — thermal, flowgate and voltage — SUGAR results aligned with MISO studies 99.2% of the time.  

MISO is using Pearl Street’s SUGAR (Suite of Unified Grid Analyses with Renewables) software to screen generation projects and perform the first phase of studies in the queue. It’s betting the tech startup’s assistance with conducting studies can dramatically accelerate its yearslong queue processing. Austin, Texas-based software company Enverus acquired Pearl Street in March. 

The RTO plans to start the first phase of studies on the 2023 batch of project proposals in July. It won’t begin analyzing 2025 entrants until the end of the year. MISO hopes to have all projects in those cycles striking interconnection agreements over 2026, with the still-in-progress 2022 cycle proceeding in the second quarter, 2023 in the third quarter and 2025 by the end of 2026. (See MISO Unveils Later Timeline for Queue Processing Restart.)  

MISO skipped acceptance of a 2024 queue class altogether. Throughout 2024, it delayed kickoff of studies on the 123 GW of projects that entered the queue in 2023 while Pearl Street assisted with modeling. 

MISO study region queue caps and project submittals as of April 2025. The East ITC study region has exceeded its queue cap. | MISO

The RTO hasn’t processed a new queue cycle in more than a year, saying it needs to introduce study automation and implement a megawatt cap to make processing requests less daunting. (See MISO to Skip 2024 Queue Cycle While it Automates Study Process with Tech Startup.) 

MISO found that SUGAR completed the first phase of interconnection studies faster while estimating similar costs for network upgrades. MISO said while it spent 686 days to ultimately estimate $13.36 billion in upgrades for the 2021 queue cycle of projects, SUGAR estimated $13.25 billion for the same batch of projects within 10 days.  

MISO staff at an April 22 Interconnection Process Working Group said SUGAR provided a good match for the RTO’s longer-form interconnection studies.  

“These results confirm that SUGAR can be utilized in MISO’s [first definitive planning phase (DPP)] studies with minimal impact to stakeholders while also providing significantly increased speed in conducting MISO DPP Phase 1 studies,” MISO wrote in its analysis.   

MISO said SUGAR results are in “excellent agreement” with MISO’s previous study process regarding flowgate project assignments. When hunting voltage constraints, MISO said SUGAR landed on 102 of the 103 constraints it previously identified while reporting six more that didn’t turn up in MISO studies. MISO said the additional constraints SUGAR called out are “deemed acceptable within the bounds of engineering judgment.”  

MISO also said SUGAR noted 259 of the 261 thermal constraints MISO previously reported. The RTO said it expected small deviations in the output of different powerflow tools.   

Meanwhile, one MISO region already has surpassed MISO’s newly enacted 50% of peak load annual interconnection queue cap. (See FERC Approves Annual Megawatt Cap for MISO Interconnection Queue.)  

The East ITC study region, which contains Michigan’s Zone 7, exceeded the cap at 29 submittals at 10.52 GW. Any other projects that hoped to enter under the 2025 cycle now must queue up for the 2026 cycle.  

MISO has been allowing projects to line up for 2025 queue processing since last year. Its cap for the 2025 queue cycle is nearly 78 GW. So far, MISO has recorded 154 project submissions at 41.64 GW.  

At the April 22 meeting, John Liskey, of the Citizens Utility Board of Michigan, said the resources that entered before the East region’s cap was exceeded contain a large amount of gas capacity, which could violate Michigan’s renewable energy standard of 50% by 2030 and 60% by 2035.