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July 2, 2024

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Massachusetts DPU Approves Everett LNG Contracts

The Massachusetts Department of Public Utilities has approved agreements between Constellation Energy and the state’s investor-owned gas utilities to keep the Everett LNG import facility operating through May 2030. 

The Everett Marine Terminal (EMT) is the only facility in the state that can import and directly inject LNG into the gas network, but it has faced an uncertain future, with Constellation’s cost-of-service agreement with ISO-NE expiring at the end of this month. Constellation owns both Everett and the Mystic Generating Station, Everett’s anchor customer, which is set to retire at the same time. 

Following extended negotiations with the state’s gas utilities dating back to 2021, National Grid, Eversource Energy and Unitil filed agreements with Constellation in February to help cover the facility’s fixed costs and provide the utilities the option to purchase LNG as needed. 

The utilities argued that the agreements were necessary for the reliability of the gas network, but they were met with pushback by environmental organizations and state agencies about the cost and climate implications of the agreements. The Conservation Law Foundation (CLF) opposed the agreements, while groups including Enbridge, Tennessee Gas Pipeline and Constellation supported the utilities’ filings. 

Neither the Massachusetts Attorney General’s Office nor the state Department of Energy Resources took an explicit stance on the contracts, but both called for additional transparency and reporting requirements. (See Mass. AGO, DOER Call for Climate Guardrails on Everett LNG Contracts.) 

In its ruling, the DPU found that “without the agreements, each company will not have sufficient natural gas supplies to reliably serve its customers in design-winter scenarios during the term of the agreements, which could jeopardize the health and safety of its customers during the cold winter months.” 

Responding to CLF’s argument that utilities did not adequately consider alternatives, the DPU ruled that “the alternatives to the agreements currently available to each company, including electrification, are insufficient to fully replace supplies from EMT or provide the reliability benefits that EMT offers.” 

The DPU also disagreed with CLF’s contention that the agreements are not compatible with the state’s climate laws. The department noted that Eversource’s and Unitil’s contracts are intended to replace existing gas supply contracts and are therefore in line with the precedent set by previous rulings. 

Meanwhile, National Grid indicated that its contract is needed in part to help meet increasing gas demand from oil-to-gas heating conversions. The department found that this justification is aligned with previous rulings “that the acquisition of incremental natural gas supply to serve new customers that convert from oil heating to natural gas heating is consistent with the” Global Warming Solutions Act. 

However, the DPU wrote that it may need to revisit this precedent following its December 2023 order (20-80-B) creating “a new regulatory framework” to discourage new investments in gas infrastructure. (See Massachusetts Moves to Limit New Gas Infrastructure.) The department also said it intends to consider whether equity and affordability impacts should be included in the evaluation of similar contracts going forward. 

Instead of changing the standard of review within the Everett proceedings, “the department finds it appropriate to engage in a more thoughtful, comprehensive process involving the participation of all interested stakeholders,” the DPU wrote. 

The department agreed to include annual transparency and reporting requirements around the cost and climate effects of the agreements, as well as on the utilities’ efforts to reduce their need for Everett. 

“We agree with the attorney general and DOER that open and transparent insight into the companies’ efforts to reduce or eliminate their reliance on EMT is critical to ensuring that the commonwealth remains on a path to achieve its decarbonization goals,” the DPU wrote. 

Throughout the process, climate and environmental advocates in the state have expressed concern that the contracts could function as a stop-gap measure to a more permanent pipeline capacity expansion into the Northeast. Enbridge has said it could complete a major capacity expansion of the Algonquin pipeline by the end of the decade. (See Enbridge Announces Project to Increase Northeast Pipeline Capacity.) 

Joe LaRusso, senior advocate at the Acadia Center, said the DPU’s approval of the contracts is “potentially in conflict with Order 20-80,” particularly if the contract timelines are intended to align with Enbridge’s pipeline expansion effort. 

He said the reporting requirements should give the DPU ample information on the utilities’ gas demand trajectories, with the “open question” being whether the DPU allows the companies to reduce their reliance on Everett by securing additional pipeline capacity. 

Meanwhile, Constellation applauded the DPU’s ruling, writing in a statement that the contracts will help “ensure adequate gas availability during extreme weather conditions as the region transitions to clean energy.” 

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Iberdrola to Take Full Ownership of Avangrid

Iberdrola is moving to acquire the 18.4% stake in Avangrid that it does not already own.

The Spanish-based multinational utility operator said May 17 that this is a growth strategy: It wants to expand its presence in markets with strong credit ratings and its exposure to regulated businesses such as networks.

The $2.55 billion deal is subject to approval by shareholders, FERC and utility regulators in Maine and New York. Upon completion, which is anticipated in the fourth quarter, Iberdrola will seek to delist Avangrid shares from the New York Stock Exchange.

Avangrid is headquartered in Orange, Conn. It has approximately $45 billion in assets and 8,000 employees, mainly in renewables and networks. Its operations include eight electric and natural gas utilities in New York and New England serving more than 3.3 million customers.

Iberdrola is based in Bilbao, Spain, and is the largest European electrical utility by market capitalization. Its assets on five continents are valued at more than 150 billion euros; its 2023 installed capacity was 62,883 MW; its power lines stretch 1.28 million km; and it employs more than 42,000 people.

Both companies claim leadership roles in the clean energy transition.

Avangrid has 8.7 GW of renewable capacity installed in 24 states and is a 50/50 partner in the first large-scale U.S. offshore wind farm, Vineyard Wind 1, now under construction. Iberdrola is pursuing a renewable portfolio totaling 100 GW.

The acquisition works out to $35.75/share, an increase from the original offer of $34.25. That represents an 11.4% premium over the closing price of Avangrid stock on March 6, the last unaffected trading day before Avangrid announced it had received Iberdrola’s unsolicited offer.

Avangrid said its board of directors unanimously approved the agreement.

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EEI Sues EPA over Power Plant Rules’ Carbon-capture Requirement

The Edison Electric Institute has joined the litigation against EPA’s power plant rules under Clean Air Act Section 111, filing its own petition to review the rules and intervening in existing suits. 

The agency had already been sued over the rules by a group of states and the National Rural Electric Cooperative Association, the latter of which has asked the court to stay implementation of the rule. (See Republican-led States Sue EPA over Power Plant Emissions Rule.) 

The rules imposed stricter emissions limits on existing coal plants and new natural gas plants. They identified carbon capture and storage as the best system of emission reduction (BSER) under the CAA. Coal plants intending to operate past 2039 will have until Jan. 1, 2032, to cut their emissions to a level based on a presumption that they will install a CCS system capable of capturing 90% of their emissions. (See EPA Power Plant Rules Squeeze Coal Plants; Existing Gas Plants Exempt.) 

EEI CEO Dan Brouillette said in a statement that the investor-owned utility trade group still supports EPA’s ability to regulate greenhouse gases under the CAA but opposes the use of CCS as the BSER. 

“We are intervening today to preserve our ability to defend, if needed, elements of the final 111 rules that are consistent with the ongoing clean energy transition and that do not create reliability impacts for customers,” Brouillette said. “At the same time, we are seeking judicial review of the agency’s determination that carbon capture and storage should be the basis for compliance with other portions of the 111 rules. EPA’s record and the docket do not support the agency’s finding that CCS is adequately demonstrated for broad deployment across our industry.” 

CCS is an emerging technology, and the rule’s implementation timelines do not align with its commercial reality, Brouillette said. No power plants are operating today that would meet the agency’s requirements for CCS. 

“Throughout the rulemaking process, we repeatedly raised concerns that CCS is not yet ready for full-scale, industrywide deployment, nor is there sufficient time to permit, finance and build the infrastructure needed for compliance by 2032,” he added. 

EEI said its members are investing in CCS and other technologies that can deliver power around the clock and without emissions, but it cannot bet the future on a technology that is not ready for industrywide deployment. 

The utility group’s concerns about CCS are not unique, with SPP and PJM both recently saying the technology was not ready. (See related story, SPP Shares Concerns over EPA’s GHG Rule.) 

In a statement this month, PJM noted that EPA had responded to concerns it brought up in joint comments filed with SPP, ERCOT and MISO before the rules came out, making some helpful improvements. However, the final rules’ reliance on CCS was still a concern. 

“The availability of CCS is highly dependent on local topology, such as salt caverns available to sequester carbon and the availability of a pipeline infrastructure to transport carbon emissions from individual generating plants to CCS sites potentially hundreds of miles away,” PJM said. “There is very little evidence, other than some limited CSS projects, that this technology and associated transportation infrastructure would be widely available throughout the country in time to meet the compliance deadlines under the [rules].” 

Advanced Energy United put out a statement urging the broader electricity industry against litigation in response to EEI’s petition for review. 

“With the Inflation Reduction Act at our backs, and clean energy the most affordable and reliable choice, it’s time for all of us to lean into the energy transition,” said CEO Heather O’Neill. “Dragging our feet and betting against America’s technological innovation will only drive up utility bills for consumers. The most cost-effective way to power our electric grid is by scaling up the use of the proven, clean and reliable technologies we already have.” 

Technologies like wind, solar, energy storage, geothermal, demand flexibility and efficiency are proven, clean alternatives to fossil-fueled power plants, United said. 

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FERC Denies PacifiCorp Formula Rate Change

FERC on May 21 rejected PacifiCorp’s request to include in its Open Access Transmission Tariff the interest it pays when refunding advance payments such as interconnection study deposits (ER24-1595). 

In a March 22 filing, PacifiCorp described the interest payments as “prudently incurred costs.” 

The company noted that FERC Order 2023 requires interest to be paid on refunds of interconnection study deposits, commercial readiness deposits and payments in lieu of site control. PacifiCorp said its Large Generator Interconnection Procedures also include that requirement. 

The deposits are refunded when an interconnection customer reaches commercial operation or withdraws from the interconnection queue, the company said. Interconnection study deposits are refunded after deducting study costs PacifiCorp paid for, while commercial readiness deposits are refunded less any withdrawal penalties owed. Site control deposits are fully refunded. 

PacifiCorp asked to include the interest payments for those refunds in its Annual Transmission Revenue Requirement that is part of the OATT. And in response to comments during a previous proceeding, the company said it would deduct from the interest expense the interest it earned while holding the deposits. 

“The interest expense is a legitimate and required cost for PacifiCorp to provide interconnection service,” the company said. 

The filing drew protests from Bonneville Power Administration and a group of customers comprising Utah Associated Municipal Power Systems, Utah Municipal Power Agency, and Deseret Generation and Transmission Cooperative. 

The Utah customers said PacifiCorp’s proposal would inappropriately shift costs from generators seeking interconnections to transmission customers. 

BPA said PacifiCorp hadn’t been clear on how it would determine the interest expense, or explained why it should have discretion in calculating its interest income on the deposits. 

BPA also argued that under a 2013 settlement that implemented a formula rate for PacifiCorp’s transmission service, single-issue rate filings related to the formula rate are prohibited. 

FERC rejected PacifiCorp’s proposed formula rate revision, saying the company had not shown that its plan to recover interest expense on the deposits was just and reasonable. 

“PacifiCorp has not demonstrated that its proposal would restrict the use of the deposit funds,” the commission wrote. “Although PacifiCorp represents that it currently puts the deposit funds in short-term, daily rate interest-bearing accounts, the record in this proceeding does not indicate that PacifiCorp is required to do so.” 

While not addressing all of the protesters’ objections, the commission said PacifiCorp hadn’t fully explained how it would calculate interest expense. 

According to its filing, PacifiCorp’s interest expense in 2023 amounted to $15.1 million, which was offset by $9.4 million in interest earned on the deposits, for a net interest expense of $5.7 million. The rate impact of that expense would be about 1%, according to the company, which noted that the interest expense would vary each year. 

PacifiCorp said it had tried to work with BPA and other customers on its interest-expense proposal. The company sent its proposed methodology to them in February and followed up with a conference call in March. 

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Strategy Offered for Success of Future West Coast OSW Sector

A new report outlines steps that could pave the way for a robust offshore wind industry on the West Coast, where there’s limited infrastructure to support it. 

Key actions suggested in Oceantic Network’s “Suppliers’ Guide to Success” include making investments in port and transmission infrastructure, structuring offtake awards to emphasize deliverability and following a steady, long-term procurement schedule. 

Oregon and particularly California have ambitious goals for this emissions-free source of power generation, but they will not be in the forefront of U.S. offshore wind construction because their projects will rely on floating wind turbine technology that still is being developed and tested. 

The report provides a chance for the West Coast to analyze the mixed record of first-wave offshore wind development on the East Coast and work to avoid pitfalls when development begins in earnest off the California and Oregon coasts, Oceantic said. 

The trade organization’s West Coast Supplier Council assisted with production of the report. 

It leads off by laying out some of the challenges — floating wind turbines have been installed only at smaller scale, and never at the depths present along parts of the U.S. West Coast.  

So, while early East Coast projects can turn to foreign suppliers and foreign expertise for their bottom-fixed turbines, that option is less promising for floating wind. 

Further, the report states, the near-to-midterm market potential for offshore wind on the West Coast is less than on the East Coast, where statutory goals are higher. 

Building a West Coast offshore wind industry requires a financially sustainable and scalable supply chain that can produce results at the right time and cost. A predictable and steady pipeline is essential to attracting the investment needed to make this happen. 

“We cannot repeat the experience of the East Coast, where a focus on least-cost offshore wind procurement yielded projects with business cases that were not resilient to macroeconomic change, [were] often delayed and, ultimately, proved to be undeliverable,” the authors write. 

They proceed to lay out problems and suggest solutions: 

Infrastructure Investment

The West Coast has a severe shortage of ports and transmission, the biggest hurdle to creating a viable floating wind industry.

A massive buildout of both is required, and it needs to start as soon as possible due to the long timelines to completion.  

The California Energy Commission’s analysis in its strategic plan of port functions to support offshore wind is a great first step, and the state needs to create a funding strategy for the Port of Humboldt and Port of Long Beach. The effort should be state-led and federally supported, with guidance from the offshore wind industry. 

CAISO’s draft 2023/24 Transmission Plan, which included a proposal to bring at least 1.6 GW of offshore wind power onto the grid in the North Coast, was a tremendous first step, but substantial further investment will be needed in that region. Reserving existing capacity for offshore wind in the Central Coast could reduce the major transmission investment that otherwise would be needed there. 

Offtake Award Criteria

Offshore wind offtake contracts should prioritize quality, timeliness and capacity rather than unrealistic price targets. 

Inflexible prices and a confluence of other factors resulted in the recent cancellation of 13.2 GW of offshore wind contracts on the East Coast, causing damaging ripple effects that still are manifesting across the nascent supply chain.  

The West Coast can learn from this, but it may encounter new hurdles because of the differences between new floating technology and relatively mature bottom-fixed technology. 

It should be recognized that initial projects will reflect the higher cost of establishing an ecosystem, and that their success will reduce the cost of subsequent projects. 

Bids submitted to state solicitations should be evaluated not just for price tags, but also for supply chain and infrastructure readiness, experience and credibility, and technology maturity. 

Procurement and Production

West Coast states should set up markets to encourage development of a local supply chain rather than simply specifying local content requirements. 

This is accomplished by the firm promise of a long and steady pipeline of work, which improves return on investment, provides a clear line of sight for workforce development needs and allows for more stable pricing. 

(The desire for clear market signals was aired this month at the Pacific Offshore Wind Summit in Sacramento, during which developers called on California to set an interim goal of 10 GW installed by 2035 on the way to its existing goal of 25 GW by 2045. See Developers Urge New Target for Pacific Offshore Wind.) 

Policymakers should focus supply chain development in sectors where the West Coast could have a competitive advantage in attracting new investment, rather than on components that are readily available on the world market. 

Global supply chains already exist for blades, nacelles, towers and cables, for example. The West Coast could do better by targeting components and processes specific to floating wind for which there is not yet a robust supply chain, such as floating platform assembly and turbine integration, vessel construction or retrofitting, and manufacture of mooring systems. 

Finally, Pacific states should coordinate and collaborate regionally to use their existing industrial strengths. 

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MISO Braces for Hot Summer, Potential 130-GW Peak

MISO said it’s expecting a hot summer footprintwide and while it should be able to survive load peaks into the 120-GW level, the system could be at the brink if a scorching day produces demand near 130 GW.  

Per usual, MISO said the bulk of the danger lies in July. MISO said it likely will encounter a 122.6-GW peak sometime that month but doesn’t rule out a high-demand forecast of 129.3 GW. That level of demand would break all load records, outstrip its 123.8 GW of cleared, accredited capacity and force it to declare an emergency to access its approximately 15-GW store of operating reserves and load-modifying resources.  

In June, MISO said load could crest at an expected 115 GW or climb near 122 GW in a high-demand scenario. By August, MISO expects an almost-120-GW peak load under normal conditions, or as much as 126 GW.  

MISO’s all-time summer peak of 127 GW occurred July 20, 2011. Last year, MISO expected to eclipse that record twice during late August and early September heat waves that produced temperatures exceeding 95 degrees in northern portions of the footprint. MISO rounded out summer with a 125-GW peak Aug. 23. (See MISO: Could Have Employed Wait-and-see Approach for August Emergency.)  

During a May 21 summer readiness workshop with stakeholders, MISO resource adequacy engineer John DiBasilio said while MISO should have sufficient capacity under normal operating conditions, it’s likely to enact emergency procedures if demand intensifies this summer.  

The RTO estimates it has a 4.6-GW capacity surplus beyond its 136-GW planning reserve margin requirement heading into summer from excess capacity offered into the auction and from members’ fixed resource adequacy plans.  

MISO’s primary weather forecast vendor, data analytics and technology company, DTN, has predicted “above-normal to well-above-normal” average temperatures May through September.  

The RTO noted that the National Oceanic and Atmospheric Administration is projecting above-normal temperatures across the country June through August. MISO also said it expects precipitation this summer between near normal and slightly above normal.  

MISO in-house meteorologists Brett Edwards and Adam Simkowski said it doesn’t seem that the RTO can use last summer, which held nearly normal average temperatures in MISO Midwest, as a reference for the upcoming summer. They said more appropriate reference points include summers where load topped 120 GW systemwide and more than 30 GW in MISO South.

Edwards said all data points to a very warm summer, and MISO expects “pervasive heat across pretty much the entire continental U.S.”  

The RTO anticipates a developing La Niña weather pattern contributing to hotter conditions in July and August.  

MISO also said there’s a good chance heat could emanate from the eastern U.S. this summer, affecting PJM’s ability to export to MISO during heat waves.  

“That’s something we’re going to be watching closely as the entire Eastern Interconnect heats up,” Simkowski said. 

“Our teams are constantly working to identify and manage the areas of growing risk within our region and throughout our industry,” Executive Director of Market Operations JT Smith said in a press release.  

Finally, MISO said while it’s expecting solar penetration to increase to 6 GW of in-service capacity this summer, it’s also keeping an eye on the potential for wildfire smoke drifting from Canada to stifle a percentage of output. MISO has been routinely breaking its own solar records monthly as developers complete solar farms. Currently, MISO’s solar arrays are briefly capable of about 5-GW peaks. 

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MISO Says Risk Driving It to LMR Reorganization, Stronger Requirements

CARMEL, Ind. — MISO said with resource adequacy risks at its doorstep, it may need to place tougher requirements on its load-modifying resources and devise new, nonemergency means of using the load offsets that cannot meet new performance standards. 

During a May 22 Resource Adequacy Subcommittee, MISO’s Neil Shah said he expects the grid operator will use LMRs differently from how they’ve been used in the past to aid reliable grid operations. He said the RTO plans to “redefine the LMR product” and “remap” its load management that can’t meet qualifications into potentially new resource modes that can be used during nonemergency conditions. The LMR category going forward might contain only those resources that can be ready within 30 minutes, staff suggested.  

Shah said MISO still plans to draw on “all types of resources both on the demand side and the supply side.” He said reserves that cannot meet new LMR standards will still be used to aid reliability in its markets, albeit differently.

“We see the grid is transforming at a rapid pace. We see the risk patten changing,” Shah said, adding that the LMR construct must change with it. 

Shah said that since 2007, LMRs have been used strictly during emergency conditions. LMRs are out-of-market voluntary response resources, Shah said, which are “guaranteed capacity market payment regardless of actual performance.” He said when MISO begins issuing capacity advisories and emergency alerts, LMRs sometimes will self-schedule reductions, and because MISO isn’t aware of the load offsets until after they occur, it complicates the ability to estimate needs before peak hours.  

Shah said MISO plans to present its new approach to LMRs at its Resource Adequacy Subcommittee’s July meeting. 

Sustainable FERC Project’s Natalie McIntire asked that MISO find ways to “maximize” the resources that might not be able to make the LMR cut. 

Michigan Public Power Agency’s Tom Weeks said it might be simpler for MISO to remove the requirement that it be in an emergency before LMRs can be accessed. He also said he wished MISO would “weed out bad actor” LMRs that don’t provide load reductions as promised.  

“Instead of using a scalpel to correct the issue, MISO is pulling out a bone saw and doing Civil War-like medicine to cut off a limb,” Weeks said.  

Shah acknowledged MISO needs better-defined auditing and monitoring standards for its LMRs. He repeated that MISO is open to creating a new market product to make sure participants can make use of longer-lead demand response offerings. However, MISO’s Zak Joundi later said MISO prefers to route nonemergency LMRs into one of its existing participation categories. 

Shah said MISO can examine its current Demand Response Resource Type I participation model to make sure it’s still useful to participants. If not, the RTO can make tweaks, he said.  

“It’s MISO’s job to make sure that it can make use of the resources available to it,” WPPI Energy’s Steve Leovy said. He argued that MISO shouldn’t need strictly 30-minute LMRs and that it should activate emergencies a few hours beforehand when it requires demand response. MISO should expect some level of inefficiencies during emergencies, he said.  

“We’re talking a few times a year during severe conditions … to keep the system intact,” Leovy said.  

“Managing a 15-state footprint is incredibly complicated. When you get into real-time emergency conditions, more simplicity is needed in the design,” Executive Director of Market Operations JT Smith said.  

Smith said the problem of when LMRs could deliver wasn’t present 10 years ago because MISO had ample resources. Now, he said MISO’s “entire reserve fleet is sitting behind an emergency call.”  

MISO initially was slated to use summer to design a new capacity accreditation for its LMRs; however, it said it was persuaded by stakeholders to pause on remodeling accreditation in favor of redrafting the LMR rulebook.  

LMRs were not included in MISO’s recent filing to implement a new capacity accreditation that would accredit resources based on their projected availability and historical performance during periods of high system risk. (See Stakeholders Deliver Negative Reactions to Proposed MISO Capacity Accreditation at FERC.)  

Before it announced the pivot, MISO said it considered splitting LMRs into emergency and nonemergency resources, giving 100% capacity credit to more nimble, emergency LMRs and apply a sliding scale to nonemergency LMRs that would reduce capacity credits as response times rise. 

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FERC Watchers Digest Order 1920 and Forecast its Future

The ultimate future of FERC Order 1920 depends on rehearing, implementation and inevitable litigation, but after reading through the order itself in the past week, many stakeholders see it as an important step forward in expanding the grid. 

FERC issued the 1,364-page order on a 2-1 vote May 13, with Commissioner Mark Christie (R) filing a dissent and countered by a joint concurrence from Chair Willie Phillips (D) and Commissioner Allison Clements (D). (See FERC Issues Transmission Rule Without ROFR Changes, Christie’s Vote.)  

The order requires regional transmission planners, including ISOs and RTOs, to plan at least 20 years ahead of time using multiple scenarios while taking into consideration several benefits. Their cost allocation plans for projects must ensure only customers who receive those benefits pay for the projects. 

“The status quo is not working, and this stuff is hard,” former FERC Chair Neil Chatterjee (R) said. “I think that Commissioner Christie raised a lot of significant points in his dissent that I need to think through. I think he’s probably right on a lot of it. But the reality is, somebody’s got to make a tough call. And I commend Chairman Phillips for making the tough call here.” 

Chatterjee said the issue has bounced back and forth between Congress and FERC, and one of the two needed to act to move the ball forward. 

“It’s a 1,300-page order; there is a lot to unpack,” Chatterjee said. “But from what I know of it to date, I honestly believe had I still been on the commission, I would have voted for it.” 

Outside of claims that the order is aimed at implementing President Joe Biden’s green energy policies, much of Christie’s concerns have to do with the impact on consumers. Devin Hartman, of the conservative think tank R Street Institute, argued that consumer response to FERC’s rule would determine how far his arguments go. 

“The big thing will be whether the consumers see the proactive and more comprehensive benefits approaches as leading to more economical transmission development than the status quo,” Hartman said. 

Regional economic transmission projects have generally done well on the cost-benefits front, saving consumers plenty of money, but consumers have been against the general rise in transmission rates, as most spending in recent years has gone to local projects that address specific reliability needs, he added. 

The National Association of Regulatory Utility Commissioners expressed disappointment with “the significantly diminished state role” envisioned in Order 1920. But the organization represents 50 states, and some of them are supportive, such as Michigan Public Service Commission Chairman Dan Scripps. 

“You’re going to have a trade-off any time you do interstate infrastructure planning on a consistent basis across state lines; you’re going to gain more efficiencies, but you’re going to lose some autonomy of those states,” Hartman said. 

The Electricity Consumers Resource Council, which represents large industrial customers and is “resource-neutral” in outlook, found the rule to be generally positive for consumers, said CEO Karen Onaran. 

But Onaran’s predecessor, Travis Fisher, who is now with the Cato Institute, wrote a critical take that argued Order 1920 represents FERC putting its thumb on the scale to help build out renewables. 

It is unfortunate that the partisan politics around green energy have “hijacked” the transmission issue because the grid needs to be expanded regardless, Onaran said. 

“I think for the Republican side, we just need to emphasize — especially as industrials are looking to expand their operations onshore in the U.S. — we’re going to need reliable service,” Onaran said. “And we’re going to go to those regions that have favorable regulatory policies that do look at expanding the grid that can support our operations, regardless of what the generation choices or availability is; we’re just going to need to get access to a lot more energy.” 

Even when it comes to the grid’s transition to more green power, Chatterjee said he sees the politics eventually working itself out. 

“I do think in the coming years that we will get to a point where red supply is feeding blue demand,” Chatterjee said. “Where you have a lot of this renewable capacity is in red states, and the demand for that clean energy is going to be in blue states. And I don’t think I’m being naive about this; I think that will fundamentally alter the politics around climate.” 

While Chatterjee did not like how the Inflation Reduction Act was passed in Congress, it was good policy to onshore the supply chain for renewable energy, which should help make that future possible, he added. 

How the Rule Will Change Cost Allocation

Supporters of the rule see little difference in transmission built for renewables, or that needed for reliability and economics. 

“It’s not any one driver behind it; it’s multiple drivers,” said WIRES Group Executive Director Larry Gasteiger. “And I think even if you exclude one of those drivers, you still have plenty of other things that are pushing the need for more transmission. There’s going to be some overlap between some of them. If you build a line to deal with a clean energy mandate or integrating more renewables, you may wind up getting more resilience out of the system and enhanced reliability; you may be able to meet some increasing load needs.” 

That has already played out, with the lines New Jersey is paying for under FERC Order 1000’s State Agreement Approach to interconnect its initial tranche of offshore wind farms, Abraham Silverman, of SilverGreen Energy Consulting and a former state Board of Public Utilities staffer, said in an interview. 

“When PJM did the modeling for the State Agreement Approach that New Jersey ultimately selected, they determined that they were benefits in … three other states,” he added. 

Under the currently effective transmission planning and cost allocation regime in PJM, no other option is available, and New Jersey will have to pay for all of those transmission lines despite benefits flowing to other states. Order 1920 requires PJM to plan for binding state policies like New Jersey’s offshore wind targets. 

“Now there’s an option on cost allocation, which is if the project meets certain benefit-to-cost ratios, then the costs are socialized across the entire grid,” said Silverman. “If the proposed project doesn’t meet the 1.25 benefit-to-cost ratio, then states can get together and voluntarily allocate those costs.” 

States will have a chance to decide how such lines are allocated, but Silverman said that if they were to just stick to the current SAA, then the commission could reject that because it would leave beneficiaries that are paying nothing. 

“Now, they’re only required to pay up to the benefits that they receive, and we’re not talking carbon benefits, or anything else,” Silverman said. “We’re really talking production cost; reliability; other sort of very tangible benefits.” 

Grid Strategies President Rob Gramlich likened the dispute between the three commissioners on cost allocation to getting the check after group dinner. 

“The way I think it’s easiest to think about is if you’re at a restaurant, should you pay for what you eat, or should you pay only for what you ordered?” he said on a webinar with reporters. “And one commissioner thinks you should only pay for what you ordered. And … the majority said, ‘No, you have to pay for what you eat.’ And it’s really just that very basic principle.” 

Part of the reason the majority allowed regional planners like RTOs to file their own cost allocation rules that could even overrule the states is because legal precedent from a 2002 case, Ari Peskoe, director of Harvard Law School’s Electricity Law Initiative, said in an interview. 

“Basically, the Federal Power Act is written in such a way so as to give transmission owners the right to file any changes in their rates,” Peskoe said. “And so, FERC was concerned that if it gave the state regulators equal rights, it might be infringing on the utilities’ rights to file rate changes.” 

Commissioner Christie argued that legal precedent would not be a problem in litigation if states got the right to file cost allocation rules of their own. Peskoe said he agreed with that interpretation. 

While that would mark a big change for PJM and some other markets, Brattle Group Principal Johannes Pfeifenberger said that MISO’s Multi-Value Projects have proved very popular even with red states in its footprint. 

“MISO did a good job explaining how their states benefit from the Multi-Value Projects, and then has also shown that the portfolio of projects they have come up with benefits each state more than the postage-stamp cost allocation,” Pfeifenberger said. 

How Far Will Regions Take the Rule?

One open question is how the rule will be implemented in different regions. 

Order 1000 required changes to transmission planning and cost allocation around the country, but only some regions effectively used it to cooperatively build out their grids. 

“FERC can take the horses to the water but can’t make them drink,” Pfeifenberger said. “How the regions respond to it will be different, no doubt. And some of them will take this as an opportunity to really improve the planning process to create low-cost transmission solutions. And other regions will just comply with the letter of the order and implement processes on paper that don’t really do anything in the real world.” 

The regions are going to have a lot of discretion to implement the rule, which is the case for nearly every major FERC rule, said Silverman. 

“How you quantify benefits is going to be something that each individual public utility transmission provider is going to have to do,” he said. “How you incorporate some of the more discretionary pieces of state policies into the transmission planning — the scenario-building process is going to be absolutely key. And then, of course, at the end of the day, you are only as good as the desire to build new transmission.” 

The rule gives regions more tools in the toolbox, but it does not necessarily require their use, he added. 

Former FERC Chair Jon Wellinghoff (D), who ran the commission when it issued Order 1000, agreed that it was time for an update to its transmission rules. 

“FERC just needs to ensure … that those rules are adequately drafted so that there is clear direction to the ISOs as to what they should be doing,” Wellinghoff said. “I mean, FERC has tremendous power there.” 

The chair can convene the ISOs and RTOs and other regions and explain what the commission expects to see as its rule is implemented, he added. 

Wellinghoff also argued that FERC needs to ensure that Order 2222 is fully implemented alongside Order 1920, as the growth in electric vehicles and other distributed energy resources needs to be fully accounted for. With millions of EVs hitting the road in the coming years, FERC needs to get that rule right so they can be an asset to the grid instead of a burden on it, he said. 

Rehearing and Appeal?

A rule this far reaching is going to have requests for rehearing, likely even from parties who largely support it but want to see something changed.  

For example, while WIRES supports the planning and cost allocation changes, Gasteiger said it was disappointed the final rule did not go as far on reinstating the federal right of first refusal as the proposed rule did. 

Christie’s dissent lays out a “great roadmap” for parties who support his position to follow on appeal, Chatterjee said. 

One major issue on appeal is which circuit court gets the case, noted Harvard’s Peskoe. Opponents of federal rules like to go to the 5th U.S. Circuit Court of Appeals in Texas because it has handed down decisions against Biden administration policies previously, he said. But to get it appealed to a specific circuit, opponents need to find an appropriate party located in its territory. 

Most FERC cases are adjudicated in the D.C. Circuit Court of Appeals, and the commission likely would prefer it there as the judges have experience with the issues, Peskoe said. 

Another major issue is the changing precedents in federal courts, with the Supreme Court considering cases that could overturn the Chevron doctrine of deference to “expert agencies,” which is how the D.C. Circuit upheld Order 1000. (See Supreme Court Hears Oral Arguments on Overturning Chevron.) 

“So, it’s possible that the litigants will attack first authority in this case, use this rule as vehicle for a broader attack on FERC that could undermine flexibility to regulate utilities going forward,” Peskoe said. 

Christie raised the Chevron issue in his dissent, and he also argued FERC’s rule went against the newer “major questions doctrine” that came out of West Virginia v. EPA (which was argued by FERC nominee Lindsay See, solicitor general of West Virginia). 

Litigation against FERC rules of this size and scope is almost a “rite of passage,” Americans for a Clean Energy Grid Executive Director Christina Hayes said on a webinar hosted by the American Council on Renewable Energy. 

Order 1920 is built on nearly 30 years of precedent dating back to Order 888 that have opened up the grid and led to significant cost savings for customers, enhanced resource adequacy and other benefits, she said. 

“This is built on very stable ground in that there’s so much significant precedent supporting it,” Hayes said. “Were this to be overturned, it would really remake the electrical industry and in ways that are hard to contemplate. For that reason, for the stability of the system, I imagine that there are significant forces that would support upholding this rule.” 

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Manchin not Ready to Give up on Bipartisan Permitting Bill

Sen. Joe Manchin (D-W.Va.) is not ready to give up on getting permitting legislation out of the Energy and Natural Resources Committee and to the chamber’s floor, he said in his opening remarks during a May 21 hearing on the opportunities and risks of growing electricity demand in the U.S. 

Approved May 13, FERC’s long-awaited Orders 1920 and 1977 address regional transmission planning and the commission’s backstop permitting authority but will only “help with one aspect of one part of a bigger set of grid permitting problems,” said Manchin, who chairs the committee. “They are a Band-Aid on congressional inaction.” (See FERC Issues Transmission Rule Without ROFR Changes, Christie’s Vote.) 

Manchin said he has been working with Sen. John Barrasso (R-Wyo.), the committee’s ranking member, on a permitting bill, and “we finally have language. We want to start sharing that language with everyone [so] that people can see where we are and hopefully that we can get our act together.” 

Sen. Joe Manchin (D-W.Va.) | Senate ENR Committee

Accelerating permitting was one of several familiar themes raised at the hearing, which primarily served as an echo chamber for the argument that meeting rising electricity demand from new factories and data centers across the U.S. will require not only keeping existing coal- and natural gas-fired power plants online, but also building more. 

EPA’s recent rules on cutting carbon emissions from existing coal and new natural gas plants were a particular target for both Manchin and Barrasso, who represent major coal-producing states. Already facing legal challenges from a group of Republican-led states and an industry trade association, the rules could require coal-fired plants without some form of carbon capture to close by 2039. (See Republican-led States Sue EPA over Power Plant Emissions Rule.) 

“These plants play a major role in ensuring electric reliability,” Barrasso said. “They also make electricity more affordable. President Biden doesn’t seem to care at all. He wants the cost of complying with EPA rules to be high. He wants to force operators to shut down these plants before the end of their useful life. It is a disgrace. We cannot regulate our way to more electric generation.” 

That additional generation is needed, Barrasso said, to keep the U.S. ahead of China in the emerging competition for dominance in artificial intelligence. China is continuing to build coal-fired plants to power its data centers, while the U.S. is closing down plants. “The president’s opposition to coal, to natural gas and even to hydropower … is a white flag. It is … an act of surrender to China,” he said. 

Sen. John Barrasso (R-Wyo.) | Senate ENR Committee

Both lawmakers also pointed to NERC’s recent summer assessment warning that extreme heat waves could put reliability at risk in some regions. (See NERC’s Summer Assessment Sees Some Risk in Extreme Heat Waves.) 

Witnesses at the hearing generally provided variations on the same core themes: the need for reliable power to meet increased demand and rising concerns that the U.S. grid will not be able to deliver. 

To a certain extent, the U.S. electric system has fallen victim to the success of the Infrastructure Investment and Jobs Act, Inflation Reduction Act, and CHIPS and Science Act, all of which have catalyzed new investment in domestic industry and manufacturing, but also new demand, said Benjamin Fowke III, interim CEO of American Electric Power. 

“Just a few years ago, a large industrial manufacturing facility might require 100 MW,” Fowke said. “A facility that size would typically be one of a kind in a region, would be the major source of economic activity for that region. Now it is common for a single data center to require three [or] up to 15 times this amount of power for a single site.” 

Demand growth related to data processing could double nationwide in three years, he said. FERC, other federal agencies and state officials should collaborate “to evaluate the establishment of a central planning authority focused on reliability and directing FERC to ensure that viable reliability safety valve mechanisms are in place to prevent premature plan retirements,” Fowke said. 

Congress should also work to expedite permitting of resources ― “new 24/7 dispatchable and clean energy” ― that utilities identify as critical for system reliability, he said. 

Mark P. Mills, founder and executive director of the National Center for Energy Analytics, went further. “The fastest way to increase power supplies ― because we’re talking about demands that are occurring in the next few years, not decades ― it’s not things we don’t know how to build, but things we know how to build,” he said. “The best construction of dispatchable power will come from gas pipes and gas turbines. They’ll be the primary source of new supply. 

“This will be true with the United States, [in] almost every state; and it’s also true in Europe. It’s what’s happening around the world, but especially here,” he said. 

The Cost of a Tow Truck

Speaking for big industrial power users, Karen Onaran, CEO of the Electricity Consumers Resource Council, said U.S. industry could need an additional 36 GW of power by 2030, which will require right-sizing the grid and reducing regulatory barriers. She also criticized EPA’s power plant rules, saying they “further complicate a tenuous situation on our grid,” impeding access to affordable and reliable energy, she said. 

“We cannot afford to take any options off the table right now,” Onaran said. “We need all-of-the-above resources, and we need the infrastructure to support those resources. We need an agile and flexible grid that can manage variable supply, as well as variable demand. Demand is going to change [its] profiles.” 

Scott Gatzemeier, corporate vice president for front-end expansion at Micron Technology, spoke of the memory chip maker’s need for firm, 24/7 power and its efforts to reduce its power demand as it builds out new capacity for energy-efficient chips in New York, Virginia and its own home state of Idaho. 

The company’s site in Onondaga, N.Y., is 40 miles north of a nuclear power plant “with a direct line connection to a 345-kV substation across the street from [our] site,” Gatzemeier said. “Reliability of the system is incredibly important [for] semiconductor fabs because a small millisecond blip in our power would take down our factory for up to a week by interrupting processing.” 

For its Idaho facility, Micron is waiting for Idaho Power’s Boardman-to-Hemingway transmission line, which will allow bidirectional flows of clean power — hydro and wind — with the rest of the Pacific Northwest. The project has been in development and permitting since 2007 and is now waiting for final federal and state notices to begin construction, according to a project timeline on Idaho Power’s website. 

At the same time, Micron has committed to use 100% renewable power at its U.S. factories by the end of 2025. Gatzemeier said in his written testimony that its customers are always pushing it for more energy-efficient chips. Customers are reporting that Micron’s most recent memory chip, designed for AI, uses 30% less energy. 

One of the last senators to speak, Sen. Angus King (I-Maine) said the hearing’s discussion was missing the critical role of climate change in the energy transition. 

Sen. Angus King (I-Maine) | Senate ENR Committee

“We’re only talking about half the equation,” King said. “We’re like in a car on a railroad track with a train coming toward us, and we’re talking about the cost of a tow truck. The cost of not addressing climate change dwarfs the cost of addressing climate change. … 

“To act like the transition is just something we’re doing because it’s a nice thing to do or because some elite group says we should do it is just not accurate.” 

From grid-enhancing technologies to pumped hydro storage to old-fashioned conservation, other options exist for meeting increased demand, he said, but permitting reform will be the key. 

Speaking to reporters May 13, Senate Majority Leader Chuck Schumer (D-N.Y.) said he had told Manchin he did not think permitting reform would go anywhere in the current Congress. “I think it must go somewhere,” Manchin countered May 21. “We have it ready to go, and we will … see if we can move this from this committee forward on the floor.” 

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SPP Shares Concerns over EPA’s GHG Rule

SPP told its members May 20 that the EPA’s final rule curbing greenhouse gas emissions from power plants could negatively affect the nation’s ability to provide reliable service during the “swift” transition from fossil fuels to renewable energy. 

In a statement, the grid operator expressed concern about how Rule 2023-0072, finalized in April, will affect its region’s ability to maintain resource adequacy and ensure reliability. (See EPA Power Plant Rules Squeeze Coal Plants; Existing Natural Gas Plants Exempt.) 

“SPP is concerned that limited technological and infrastructure availability and the compliance time frame will have deleterious impacts including the retirement of, or the decision not to build, thousands of MW of baseload thermal generation,” the RTO said. “If sufficient flexible thermal resources are not available to play their critical roles in SPP’s resource mix, SPP’s ability to maintain regional reliability will be directly impacted.” 

SPP noted the final rule’s emissions limits for existing coal and new gas generation are based on EPA’s finding that carbon capture and sequestration (CCS) technology is a viable “best source” of emissions reduction. It argued that CCS has not yet been “adequately demonstrated at the required capture rate” and will not be “widely available and practicable” to meet the agency’s 2032 compliance time frame. 

The grid operator also said it is concerned about the availability of gas infrastructure that will be needed for EPA’s assumption that a natural gas co-firing option would be available for existing coal units that retire before 2039. Its 2023 loss-of-load expectation study indicated that it would need as much as a 50% winter season planning reserve margin to maintain a one-in-10 LOLE, SPP said. 

“A PRM of that magnitude would require a significant amount of new capacity to be added in a short time frame,” the RTO said. “The study and its projected increase in PRM did not consider the additional at-risk generation that may retire and not be adequately replaced in a relatively short time frame resulting from the compliance time frames.” 

SPP filed comments in EPA’s rulemaking and joined with other grid operators to file joint comments. 

MMU Releases Market Report

SPP’s Market Monitoring Unit (MMU) said the return of natural gas prices to a “more normal” range and wind generation’s increasing role in the markets highlighted its annual State of the Market report for 2023. 

The MMU said gas prices dropped from an average of $5.83/MMBtu to $2.16/MMBtu at the Panhandle Eastern hub, down 63%, and were the largest contributor to a decrease in energy prices. Average day-ahead prices last year decreased 46%, from $48/MWh in 2022 to $26/MWh last year, and real-time prices were off 47%, from $44/MWh to $24/MWh. 

Wind generation continues to play an increasing role in SPP’s markets, with 33.7 GW of nameplate wind capacity producing 37% of the RTO’s generation in 2023, more than any other resource. At the same time, that has produced challenges that include the increasing variability and uncertainty of supply, out-of-market actions to ensure system reliability, higher make-whole payments and negative prices, the MMU said. 

However, the Monitor said the addition of new wind resources has slowed. Just under 1,700 MW of nameplate capacity joined the market after 1,500 MW of capacity was added in 2022. Three years ago, 3,200 MW of capacity was added. 

The Monitor made two new recommendations: Improve the uncertainty product design to ensure the procurement of adequate rampable capacity; and ensure planning, markets and operational processes appropriately consider large loads’ integration. 

The MMU will host a webinar to discuss the report at 1 p.m. June 4. Registration is open on the SPP website.