FERC on Monday conditionally accepted the New York Power Authority’s (NYPA) proposal to revise its formula rate template in response to its need to bring on large amounts of clean generation.
In its filing with FERC, NYPA sought to “update the allocation methodology for administrative and general costs and expenses as well as depreciation and net plant costs for general plant (A&G), incorporate a transmission rate incentive and a cost containment mechanism for the Smart Path Connect Project, and make certain technical and clarifying improvements to the formula rate template,” the commission noted in the order (ER23-491).
A political subdivision of the state of New York, NYPA is classified as both a “municipality” and “state instrumentality” under the Federal Power Act. The agency has no specific service territory, but it generates, transmits and sells electricity at the wholesale and retail levels throughout New York. Since the creation of NYISO, NYPA has recovered the cost of its transmission facilities through the NYPA Transmission Access Charge (NTAC), which is assessed to most loads in NYISO on a load-ratio share basis.
In seeking the revisions, NYPA asserted that, because of New York’s aggressive climate change initiatives, the organization’s “business focus and investment profile has shifted such that transmission development and construction are the dominant activities,” meaning that the current “single factor ratio allocator is no longer the appropriate allocation.”
NYPA proposed using a “multifactor modified Massachusetts Method of allocation,” arguing that the method “uses an equally weighted average of direct labor, net plant, and net revenue ratios” and “has broad regulatory acceptance and aligns with utility practice.”
The Municipal Electric Utilities Association of New York (MEUA) disagreed, contending that NYPA “failed to demonstrate how the adoption of a multi-factor allocation of A&G costs is just and reasonable.” MEUA argued that using the Massachusetts Method “will likely assign a larger portion of A&G costs to the transmission function recovered in NTAC rates and less to its other profit centers.”
NYPA responded that the changes are simple “nomenclature changes” that would not “have material impacts” nor impose “A&G costs on NYPA’s transmission customers,” providing the commission no reason to rule against the proposals.
However, FERC said its preliminary analysis indicated that NYPA’s revisions might not meet its standard for justness and reasonableness and set the issue to a settlement judge hearing.
“We note that the proposed Formula Rate Template revisions to implement the proposed change in the A&G allocator go beyond NYPA’s assertion that the revisions are only changes in nomenclature or a non-ratemaking change,” the commission wrote. “Further, the incorporation of an allocation methodology is not an ‘accounting change,’ as NYPA asserts. Specifically, the proposed changes to the Formula Rate Template provide for a changed allocation of A&G costs to ratepayers and provide for changes to the Formula Rate Template that allow for the use of new inputs for those costs.”
The commission also pointed out that the Massachusetts Method is typically used by holding companies to allocate A&G costs between the non-revenue generating holding company and its subsidiaries.
“NYPA, however, is a corporate municipal instrumentality and a political subdivision of the State of New York. NYPA’s proposal includes no support for its claim that the Massachusetts Method is appropriate for its specific circumstances and structure,” the commission said.
FERC accepted NYPA’s filing for the proposed rate revisions, making them effective Jan. 23 but subject to refund pending the outcome of the hearing. The commission encouraged parties to the proceeding to reach a settlement before hearing procedures commence within 45 days of the order.
A trend of job changes and departures in California’s three major energy agencies has continued during the past two months, as officials opted to leave CAISO, the Public Utilities Commission and the Energy Commission, allowing Gov. Gavin Newsom to appoint replacements.
At CAISO, Governor Ashutosh Bhagwat opted not to seek another term after 12 years of service. Bhagwat chaired the Board of Governors last year; his most recent term ended Dec. 31.
“It has been a truly fantastic 12-year run, like nothing else I’ve had in my life,” Bhagwat said during the board’s last meeting of the year Dec 15. “I’ve enjoyed it thoroughly.”
The University of California, Davis, law professor plans to leave the board by the end of February or as soon as Newsom names his successor
At the CPUC, Commissioner Clifford Rechtschaffen chose to leave when his six-year term ended in December. Former Gov. Jerry Brown appointed Rechtschaffen, his senior adviser on climate and energy issues, to serve on the CPUC beginning in January 2017.
“My term at the CPUC was very rewarding, but I just turned 65, and I’m ready to move on to the next phase in my professional life, including doing some teaching again,” Rechtschaffen, a professor at Golden Gate University School of Law in San Francisco and graduate of Yale Law School, said in an email to RTO Insider.
On Dec. 22, Newsom said he was appointing Karen Douglas, his senior energy adviser and former member of the CEC, to fill the open CPUC seat left by Rechtschaffen.
A month later, Newsom’s office announced that CEC Commissioner Kourtney Vaccaro had been appointed technical adviser to Douglas at the CPUC. Vaccaro had served on the CEC since March 2022. She previously worked as Douglas’ top adviser at the CEC, where she had held multiple positions including chief counsel.
Newsom must next appoint a new CEC commissioner. The position requires confirmation by the State Senate, as do seats on the CAISO board and CPUC.
The series of personnel changes are similar to those that occurred in December 2021 and early 2022, when Newsom chose Douglas as his energy adviser, named Vaccaro to the CEC and appointed his senior energy adviser, Alice Reynolds, as the new CPUC president.
Earlier in 2021, Newsom appointed CEC Deputy Director Siva Gunda as a commissioner and chose then-CEC General Counsel Darcie Houck to fill an open spot on the CPUC, after he selected CPUC Commissioner Liane Randolph to head the influential California Air Resources Board.
Once the latest round of changes is complete, all five commissioners of the CPUC, four of five CAISO governors and the majority of CEC commissioners will be Newsom appointees. The governor has sought to exercise control over the state’s energy institutions with an aggressive climate agenda and efforts to keep the lights on following rolling blackouts ordered by CAISO in August 2020.
WASHINGTON — The United States Energy Association on Thursday gathered senior leaders of the major trade associations at the National Press Club, where they focused on implementing major energy legislation passed last year and many argued for reforms to permitting processes.
The passage of the Infrastructure Investment and Jobs Act and the Inflation Reduction Act gives the energy industry plenty to implement, but Edison Electric Institute President Thomas Kuhn said Congress still needs to pass more legislation to make the investments those laws promised a reality.
“One of the things on our priority list is siting and permitting,” Kuhn said. “If you want to have the benefits of the two major legislative initiatives over the past couple years, you’ve got to be able to do siting and permitting more efficiently.”
While changes to energy project permitting laws have some bipartisan support, different interest groups have their own ideas, and it will be challenging to bring them together and get something done, he said.
The electric industry has made significant cuts in its emissions over the last 10 years and many utilities have plans to clean up even more in the coming decades, but Kuhn warned against getting rid of all fossil fuels too quickly. With so much changing now, it does not make sense to take a major source of energy away all at once, he said.
“Some people want to take natural gas away,” Kuhn said. “You know, I’ve got to tell you, if you want to do this job and you want to do it reliably and mildly affordably, you’re going to need natural gas. It’s that simple.”
Generators switching from coal to natural gas have helped bring emissions down to 30-year lows, American Gas Association President CEO Karen Harbert said. The gas industry has been trying to clean up and working to cut its methane emissions, she said.
“If the conversation is about reducing emissions, we’re all in,” Harbert said. “If the conversation is about putting us out of business, not so much. Because there is no way to address energy security, environmental progress, economic security and national security without natural gas in our system.”
Interstate Natural Gas Association of America CEO Amy Andryszak argued that many states are enacting policies that favor renewable energy while discouraging new sources of natural gas that would help balance those resources.
“We know the Northeast is supply-constrained — not due to a lack of available natural gas in the United States,” Andryszak said. “Actually, we have the Marcellus right next door. But regulatory decisions and bad policies have contributed to this problem.”
INGAA supports “smart policies” aimed at reducing carbon emissions, but, echoing Harbert, Andryszak said if the conversation is really about eliminating natural gas, then the pipeline trade group is against it.
One major policy Congress has to deal with is the debt ceiling, said American Petroleum Institute CEO Mike Sommers, who was involved in such discussions as a senior staffer for Republican congressional leaders in the 2010s.
“There are big things that could get done, like permitting reform on a bipartisan basis, potentially as part of the way that we get the debt ceiling lifted as well,” Sommers said. “So, I’m optimistic that this is going to get done. I think we should all get used to some panic moments. But I’m confident that our leaders are going to get this addressed in a timely fashion.”
Germany now has five LNG terminals after it worked to replace the Russian-supplied natural gas that it embargoed after the invasion of Ukraine.
“And they built one of them in six months, when the typical receiving terminal is a two- to three-year time period,” Electric Power Research Institute CEO Arshad Mansoor said. “So, they figured out when there’s a necessity permitting can be streamlined.”
Germany has been a leader in moving to renewable energy, but it also has avoided completely retiring coal plants; that decision proved prescient this winter as they had to be used much more often than when the country was awash in cheaper Russian gas, he added.
“I think it’s a general belief that for all of us in the research community [and] in the technology community, that we must have optionality in our clean energy transition,” said Mansoor.
Natural gas plants are still relatively young when it comes to infrastructure, and Mansoor said that early studies have found that they could run blends of 20% or 40% clean hydrogen to minimize their emissions while maximizing their usefulness to the grid.
The industry has to prepare for more extreme weather and do so ahead of time, Mansoor said. While utilities have often done well upgrading their systems after a natural disaster, climate change means extreme weather will be more common.
“How do you proactively make that investment?” Mansoor said. “Don’t wait for the flood; anticipate weather in 2030, 2045, … and start building infrastructure for that weather.”
The Southern Renewable Energy Association (SREA) said Thursday that the Duke Energy Carolinas and the Tennessee Valley Authority Christmas Eve blackouts were likely avoidable had they built more robust transmission links and had better access to organized wholesale markets.
SREA Executive Director Simon Mahan | SREA
SREA Executive Director Simon Mahan said during a briefing focused on the Southeast region’s performance issues and rotating blackouts during the December winter storm that the region contains a “balkanized, separated grid” where each utility must balance their own system without a shared resource pool to fall back on. (See FERC, NERC Set Probe on Xmas Storm Blackouts.)
“With better connections with our neighbors, we can avoid blackouts,” he said.
The load shed was a first for both TVA and Duke.
Mahan drew parallels between the recent winter storm and the more severe storm in February 2021. He predicted the Southeast will receive much of the attention for its performance in December because it’s isolated from a regional grid, as was — and still is — ERCOT two years ago. TVA and Duke need to build better transmission to prevent future outages and grid-scale failures, Mahan said.
TVA and Duke Energy both had major power outages about the same time on Dec. 24, Mahan said. He added that both imported significant amounts of power from organized wholesale markets to avoid a more dire situation.
Duke reached its highest emergency level and initiated rolling outages that same day. Mahan noted North Carolina’s northeastern corner remained stable because it is in the PJM footprint.
“While much of the state was under rolling blackouts, that corner of the state was not experiencing blackouts,” he said.
TVA at times imported more than 5 GW from MISO on Dec. 23 and 24, Mahan said. Those exports helped trigger the RTO’s own maximum generation event, setting off stakeholder debate on how far it should stretch its system to assist neighbors. (See MISO Actions During December Storm Spark Debate.)
According to the North Carolina Utilities Commission (NCUC), Duke was negatively impacting the entire Eastern Interconnection’s frequency on Dec. 24. Mahan said Duke was close to setting off “significant and widespread” outages like the 2003 Northeastern blackouts.
“The situation was really quite dire before they decided to start causing the rolling blackouts,” Mahan said.
Duke Carolinas under-forecasted demand by as much as 1.5 GW on Dec. 24, while Duke Energy Progress East had an even larger forecast gap at 2.8 GW, Mahan said.
The bitter cold proved “really difficult for the company to come back from,” he said, noting that Duke was not able to resume normal operations until nearly midday Dec. 26. Had it not been for solar generation’s strong performance on Dec. 24, Mahan said, Duke would have been thrown further into “dire straits.”
He said after analyzing preliminary import and export data from the Energy Information Administration, the Southeast region’s system may have been “so taxed and so overburdened” that loop flows materialized.
Mahan said state regulators should investigate the event and make findings public. “We need to get a better sense of what actually happened,” he said.
Mahan said the region had indications that its grid and thermal generation would struggle during the storm. He said the wave of intense cold Dec. 23-24 fulfilled predictions meteorologists forecasted a week earlier.
“We should have been more prepared. We’ve seen it before. It’s happened before,” he said.
Mahan said the main difference between the two recent winter storms is that the December event had a “more direct bullseye” on the Southeast. He said he hoped more attention is paid this time to actionable changes.
Mahan said the Southeast needs more regional and interregional transmission connections; it’s imperative, he said, that Duke and TVA also diversify their generation mixes by adding more wind, solar and battery storage than natural gas plants.
Duke and TVA would have benefitted from larger solar fleets in this instance because sunshine was surprisingly plentiful during the event, Mahan said. He said as fossil plants struggled to be available on Christmas Eve, more solar generation would have shortened the length of the blackouts or made the outages less severe.
Chris Carmody, executive director of the Carolinas Clean Energy Business Association, said Duke would be better served if it “connects with a pack of states next door who don’t have blackouts.”
Duke Energy Carolinas CEO Julie Janson appeared before the NCUC Jan. 3 to apologize and vow the utility would learn from the experience.
“We own what happened,” she said. “We have set out on a path to ensure that if we are faced with similar challenges, we will see a different outcome and provide a better customer experience.”
Duke spokesperson Jeff Brooks told RTO Insider that the company “employed thousands of megawatts” during the storm. He said solar was added when it became available, but that it “was not generating at the time temporary outages were required as the sun was not up.”
Brooks said resources that Duke was counting on “included deliveries of generation from independent power producers and purchases through our out-of-state interconnections that were not fulfilled for use on Dec. 24 due to other utilities experiencing the same challenges.”
He said RTO membership “would present more risks than benefits to our customers and our state.”
TVA has launched an internal investigation of its actions and has also pulled together an independent, three-person panel to separately review how it can better prepare for severe weather. The panel includes American Public Power Association President Joy Ditto; Mike Howard, former CEO of the Electric Power Research Institute; and former U.S. Sen. Bob Corker (R-Tenn.).
“This is not the way we want to serve our communities and customers,” TVA said in a press release late last month.
TVA said it had nothing more to add when RTO Insider requested a reaction to SREA’s recommendations.
Mahan said the Southeastern Energy Exchange Market (SEEM) didn’t appear to assuage the situation like an RTO could have.
“There should have been more willing purchasers on Dec. 23, but the market showed that it had even less purchases from the day before,” he said.
In fact, Mahan said that SEEM’s records showed no voluntary trades of excess power Dec. 24-26. He said that was “highly unusual,” but that it’s difficult to get a sense of what happened because SEEM isn’t a transparent operation.
“It wasn’t helpful at all for many days, which was very unfortunate,” Mahan said.
“It’s designed to do so little in the first place. There’s just not much to it,” Carmody said of SEEM’s structure.
Gas-electric coordination is becoming the “Achille’s heel of the energy transition,” says ISO-NE CEO Gordon van Welie.
Van Welie gave his perspective at NERC’s Reliability Leadership Summit in Arlington, Virginia, Wednesday, where speakers also discussed challenges related to physical security, cybersecurity and energy security.
New England has faced issues with natural gas supplies going back decades, but van Welie said grid operators in other regions are starting to see similar issues crop up.
For now, natural gas is important to balancing renewables and ensuring the region can make it through the winter peak when its pipeline system is maxed out and natural gas utilities have priority because they pay for firm capacity.
“I think the primary vulnerability in this pillar is the premature retirement of resources that can provide this balancing energy,” said van Welie. “And in the longer-term, the risk that there will not be sufficient investment in balancing resources as electrification drives load growth.”
Natural gas is still the largest input of energy into the grid, but the two industries are not planned together at all, said van Welie.
“The fixed-costs of long-term firm gas transportation and storage infrastructure are largely not recoverable through the wholesale electricity markets,” he added. “So, merchant generators in these FERC-regulated markets can recover the commodity costs, but they have very poor incentives, or no regulatory requirement to ensure that there’s sufficient gas transportation capacity, or storage, to meet their peak demand, particularly under these extreme weather conditions. Conversely, pipeline developers will only build capacity for customers that are willing to sign long-term, firm transportation agreements.”
Generators’ demand for natural gas is going to become increasingly “peaky” as renewable resources grow and the gas industry’s current rules are not capable of planning around that, van Welie said, calling it the “Achille’s heel of the energy transition.”
In July, FERC and NERC asked the North American Energy Standards Board (NAESB) to look at whether any new standards could bridge the gulf between the different business models of the two increasingly interconnected businesses. (See NAESB Confirms Gas-electric Forum in the Works.)
“NAESB isn’t going to be able to solve [all of] these things,” said its Chairman Michael Desselle, who is also a vice president at SPP. “And what we’re learning … as the gas industry is working together with the electricity industry, is that there are potentially some things we can do.”
From left: Kamyar Ghaderi, ISMS Lead Auditor; Rob Lee, CEO of Dragos; Tabice Ward, Vice President Xcel Energy; Puesh Kumar, Director, CESER at Department of Energy; and Manny Cancel, NERC Senior Vice President and CEO, E-ISAC | NERC
The two industries could step up information sharing, especially during extreme weather, and they could make some small changes to their market structures to improve coordination.
“There’s a whole bunch of other things, quite frankly, that we are not going to be able to solve,” said Desselle. “They are going to be policy matters that we’re going to eventually — when we put our report together — tee up for policymakers to make decisions on.”
Ultimately it comes down to how much consumer money should be spent to ensure enough natural gas is available when needed, he said.
While NAESB might be able to make some small improvements around the margins, the two industries are coming into that debate wanting to protect their own economic interest, said van Welie.
“My one wish would be to see FERC step up and take a harder look at this to figure out how we solve this problem,” he added.
FERC could require the gas industry to build out pipelines to meet electric generators’ demand, but that leads to thorny cost allocation issues. The other way would be to require generators to procure firm transportation, but that could lead to even more costs as the pipelines would be overbuilt, said van Welie.
“The gas use is going to go down over time,” he said. “But when we have a polar vortex, a winter storm Uri [or] Elliot coming into town, then you’re going to have this massive demand on the system and you’re going to have to have to supply that demand.”
‘Job 1’
Acting FERC Chairman Willie Phillips opened the summit calling reliability “job No. 1” at his agency.
“When I think about why reliability is No. 1, I think back to August 2003,” Phillips said. “This is the 20th anniversary of the 2003 blackout. We had reports say in three minutes, 21 power plants went down because of computer error related to vegetation management and what could have been a local issue became a cascading outage on our system impacting over 50 million people.”
The blackout had a huge economic cost and inconvenienced a large chunk of the country, but what really drove the importance of reliability home is the fact that 100 people died, said Phillips.
Crossing the Rubicon
Ten years ago, it would have been much harder for hackers to cause physical damage on the grid. But increasing digitization and the changing resource mix have made that a reality in other countries and it could happen here, Dragos CEO Robert M. Lee said.
Previously, attacks would focus on one area of the electric system, which gave the industry plenty of time to react. But last year new hacking software called “Pipedream” was discovered that can be reused across different industrial control systems with the ability to scale and repeat.
“It feels very much that we’ve sort of crossed that Rubicon into how we’re going to have to deal with that,” said Lee.
The pace of vulnerabilities coming at the industry is “unbelievable,” said NERC Senior Vice President Manny Cancel, CEO of the Electricity Information Sharing and Analysis Center (E-ISAC).
“The number of vulnerabilities that [the National Institute of Standards and Technology] tracked last year was over 23,000 vulnerabilities,” Cancel said. “So, if you do the math, that’s 60 vulnerabilities a day.”
Attempting to deal with those alone would be an overwhelming task, but the industry must defend itself from more aggressive and active hackers from state adversaries, he added.
The Director of National Intelligence said that foreign governments have been hacking into the electric system and mapping the network, said Puesh Kumar, director of the Department of Energy’s Office of Cybersecurity, Energy Security and Emergency Response.
“And what that reminds me about is if they’re mapping our network, have we mapped our network well enough to know what’s out there?” he added. “And that’s something really critical that we have to be thinking about: If our adversaries are doing this, how well do we know our networks and our systems to prevent what they might be planning?”
Cyber-informed Engineering
The grid is becoming more connected, which can bring increased reliability and efficiency, but it also gives cyber attackers more endpoints that they could potentially leverage.
“It’s a very complex problem, because we need to do the reliability, we need to do the efficiency, but you got to do the security with it as well,” Kumar said. “And so, [what] we’re championing is cyber-informed engineering. So, as we engineer the grid of the future, we have to do that with cybersecurity in mind.”
No Longer a ‘Six Pack and a Shotgun’
Physical attacks have been on the rise as well, said Bonneville Power Administration CEO John Hairston. It is not just the “typical vandalism” where someone with a “six pack and shotgun” just wants to “see something arc.”
“They’re more targeted, they’re focusing in on, you know, the IT infrastructure, and they’re looking to take down a system for a long period of time, with a mass outage,” Hairston said.
It can take 18 months to two years to replace a damaged substation, and doing so relies on foreign manufacturing, said Mike Wise, senior vice president of regulatory and market strategy for Golden Spread Electric Cooperative.
“Years ago, we determined [that physical attacks were] one of the highest risks,” said Wise. “And so, we went out and purchased to make sure we had a backup step-up transformer for every type of step-up transformer in our generation fleet.”
CARMEL, Ind. — MISO and SPP said Thursday during their annual issues review that they plan to treat Joint Targeted Interconnection Queue (JTIQ) projects as large generator interconnection projects when allocating costs.
The RTOs have proposed allocating 90% of the portfolio’s costs to interconnecting generators and the remaining 10% to their load. SPP’s load will be responsible for 71% of costs, and MISO will shoulder the remaining 29%.
The JTIQ study completed early last year resulted in five projects on the RTOs’ seam that should help reduce congestion and allow additional resources, primarily wind farms, to interconnect with their systems. The portfolio has an estimated cost of $1.06 billion. (See MISO, SPP Propose 90-10 Cost Split for JTIQ Projects.)
Sumit Brar, reliability analysis lead for MISO long-range planning, said the grid operators will not begin additional JTIQ studies unless the first portfolio has secured enough generation to cover most or more of its costs. Future studies will be conducted on a five-year horizon.
MISO expects the first JTIQ portfolio to support up to 28 GW of interconnecting generation on both sides of the seam.
MISO stakeholders expressed worry that the necessary amount of generation may drop out of the two IC queues, leaving load to handle the bag of costs. Some have also said a 90% cost assignment to interconnecting generation might not be fair.
They asked whether the RTOs might consider adding a cost cap on the per-megawatt charge or enact protections when generation requests drop out of the queue.
“Now, there will be dropouts, so we expect that,” MISO Director of Resource Utilization Andy Witmeier said, adding that the RTO expects it will take “a few queue cycles” to get the lines nearly funded.
Witmeier said it’s “unrealistic” to assume that the grid operators won’t have enough willing generation developers to fully fund the projects.
“Eventually, enough generators will sign up, sign [generator interconnection agreements] in the region,” he said.
The RTOs are proposing that generation be on the hook for a JTIQ per-megawatt cost when a project has a greater than 5% distribution factor on one or more facilities in the affected system and a greater than 1-MW impact on “at least one” JTIQ line.
Steelhead Americas’ Adam Solomon said the threshold was “ridiculously low” when compared to the large interconnection projects in the MISO queue.
MISO and SPP said they don’t plan an interregional planning study this year, saying their plates are full memorializing the targeted market efficiency projects (TMEPs) work and preparing for an expected FERC notice of proposed rulemaking on interregional transfer capability. MISO said its planners are also working on the second tranche of its long-range transmission plan.
The grid operators are required to undertake a coordinated system plan every other year. Last year, the two performed a TMEPs study that failed to identify any small interregional projects. (See MISO, SPP Unable to Find Smaller Joint Tx Projects.)
Basin Electric Power Cooperative had asked the RTOs to study constraints in the Dakotas, and Ameren has requested an examination of chronically congested 161-kV lines and a transformer linked to a 345-kV line in Missouri.
DOE Funding for JTIQs Won’t Affect Cost Allocation
MISO said Tuesday that potential Department of Energy funds will not affect a planned cost-sharing plan for the JTIQ projects.
The program requires that states affected by a project make the application process. Great Plains is organizing stakeholders and coordinating the multistage GRIP application process.
Brar said states with a JTIQ project are all involved. Funding will be granted to states based on the percentage of projects located within their boundaries.
The organizations sent a concept letter to the DOE earlier in January. The DOE will inform applicants by Feb. 24 whether their projects are sufficient enough for a full application that would be due May 19. Approved GRIP projects could potentially be awarded a 50% project match. (See SPP MOPC Briefs: Jan. 17-18, 2023.)
Grid modernization (GM) investments encompass myriad technologies that digitize a utility’s distribution system. They have the potential to improve the reliability of the electrical grid, better integrate alternative energy, and enable pricing that reflects the marginal cost of generation.
The present grid was designed when power plants in central locations exclusively controlled a one-way flow of electricity to customers. A modern grid has the ability to accommodate greater consumer control and two-way flows of power.
Experience has shown that achieving public-policy goals at bearable cost to society frequently requires technological breakthroughs. Many experts assert that making the transition to a clean-energy future at an affordable or politically acceptable cost will demand new technologies, such as those rooted in GM.
It seems then that it is a slam dunk for state regulators to approve utilities’ plans to modernize their distribution systems, even if the cost is high. But, to no surprise, things are rarely as certain as they seem. Public utility commissions face a formidable challenge in ensuring that utility investments in GM advance the nebulous public interest or are cost-beneficial.
Pressure for GM comes from different quarters: electric utilities, Wall Street, clean air and climate advocates, GM technology vendors, consultants, labor unions, and state and federal politicians and bureaucrats. Utility managers themselves favor GM mainly because it will accommodate additional demands from electric vehicles and households for electric space and water heating (i.e., electrification).
Proponents of GM vastly outnumber both skeptics and opponents, making it challenging for regulators to reject GM plans proposed by utilities. We know that strong pressure from special interest groups with political clout can persuade policymakers to decide in their favor, even though it would be detrimental to society overall.
Since utility customers are the eventual payers of GM investments, the critical questions that PUCs need to ask themselves, are whether (1) the total benefits from GM to utility customers exceed the costs and (2) low-income households will overpay given that higher-income households will disproportionally benefit from purchases of electric vehicles and rooftop solar systems that GM tries to accommodate. Just because a Tesla is technologically superior to conventional vehicles does not mean that it is the right choice for everyone. It’s costly, and some car drivers might consider the technological benefits to be nominal.
I have seen too often where utility customers pay through their rates for utility investments directed at benefitting a special interest with political influence; that is, customers funding the advancement of political objectives through inflated rates without compensatory benefits. I ask whether we are seeing a repeat of this for GM investments. Or as one industry observer expressed to me, “Is grid modernization another way to line utility pockets and promote renewable energy and kill fossil fuels?” While this opinion seems extreme, it may not be so far-fetched.
There is great uncertainty over the benefits and costs of GM investments. Costs overruns are common, and benefits are difficult to quantify and require different methods of varying complexity.
A serious problem is a utility’s capital bias combined with laxed regulatory cost controls. Under traditional regulation, utilities collect capital costs only after the regulator considers them prudent or reasonable; utilities would be allowed to collect them only after a general rate case.
But for various reasons, regulators have accepted new cost-recovery approaches. Both utilities and climate activists have pushed for quicker and more certain capital-cost recovery when it comes to certain technologies like GM that advance their agenda. Wall Street has also supported these new approaches, fashioning an Iron Triangle that makes it difficult for PUCs to reject them.
Utilities should be held accountable for subpar performance from GM investments. These investments have often fallen short of achieving the benefits promised in utilities’ plans.
There is evidence that reliability has not improved in states that have so far invested the most in GM. Critics have also questioned whether it is too soon to replace the current infrastructure.
Advanced metering infrastructure (AMI) has in some jurisdictions failed to realize expected dispatch efficiencies and cost savings. Most utilities have also under-exploited the ability of AMI to enable granular time-of-use rates (e.g., real-time pricing, electric vehicle charging rates) that can produce large efficiency gains.
Another problem recognized by PUCs is utilities proposing to make large-scale, multitechnology investments, some of which have questionable, ill-defined benefits that are unlikely to transpire for several years.
PUCs should not outright reject a GM plan just because it would require an increase in electricity rates or be prejudiced against a plan in spite of the evidence; or accept a plan just because it will support a popular clean energy agenda, while ignoring the effect on utility customers. There is danger that either of these scenarios can happen and probably has already in some states.
The experiences across states have shown that the benefits from GM plans are often overstated and costs understated. The burden falls on PUCs to ensure that this does not happen. Unaccountability by utilities for their large investments can have a devastating effect on customers and society as a whole. Getting the incentives right is the key element for achieving socially desirable GM investments.
Kenneth W. Costello is a regulatory economist and independent consultant. He previously worked for the National Regulatory Research Institute, the Illinois Commerce Commission, Argonne National Laboratory and Commonwealth Edison Co.
The Inflation Reduction Act’s electric vehicle tax credits sparked a spirited debate on the Senate floor Thursday as Sen. Debbie Stabenow (D-Mich.) resisted Sen. Joe Manchin’s (D-W.Va.) call for swift passage of a bill that could put a hold on the credits for some EV buyers.
Manchin’s American Vehicle Security Act would force the Internal Revenue Service to put the IRA’s domestic content provisions into effect retroactively, as of Jan. 1. The IRA required the agency to issue guidelines for the tax credit by Dec. 31, but the IRS only issued partial guidelines, delaying action on the domestic content provisions until March and triggering Manchin’s efforts to force the agency’s hand. (See Treasury Delays Key Rules for IRA’s EV Tax Credits.)
In the interim, the IRS has said EV buyers can qualify for the full $7,500 tax credit offered in the IRA, without complying with domestic content rules. If Manchin’s bill were to become law, some of those cars might no longer qualify.
Sen. Debbie Stabenow (D-Mich.) | C-SPAN
“Why the IRS did not do their job, I can’t tell you, unless their intent was never trying to comply with what we passed,” Manchin said, moving for his bill to skip a hearing in the Senate Finance Committee and go straight to a floor vote.
Framing the IRA as an “energy security manufacturing” law, Manchin said the domestic content provisions are intended to spur the buildout of a U.S. supply chain for EVs, countering China’s dominance in the EV global market.
“We’re moving rapidly into the EV markets — and I think, recklessly — as we were going into that before we were able to supply [domestic production] and be held captive by China,” he said. The U.S.’s main economic competitor now controls 80% of the world’s battery materials processing and 75% of lithium-ion battery production, he said.
Stabenow had no argument with Manchin on building out a domestic EV supply chain and cutting U.S. dependence on China. But she said the EV tax credit in the IRA “is confusing. It was not well vetted. It is not supported by anyone in the auto industry.”
Objecting to Manchin’s motion for a quick vote on the bill, Stabenow said, “This does not create any path for success for American automobile workers, for American automobile companies, for suppliers, for consumers who are interested in being able to purchase electric vehicles and benefit from a credit.”
She also defended the IRS decision to delay rules on the domestic content provisions as “not unreasonable. … They have been given, I believe, an incredibly complicated task to try to figure out how this consumer credit will work for consumers and for companies and workers,” she said.
The domestic content requirements simply don’t work “on a practical level,” she said.
The Senate recessed without acting on Manchin’s motion.
GOP Support Uncertain
Facing opposition from his fellow Democrats, the bill’s prospects for passage are slim. But Manchin is seeking GOP support, enlisting Rep. Mike Braun (R-Ind.) as a co-sponsor.
Backing up Manchin on Thursday, Braun said he had not supported the IRA. But he said the new bill “is not just about promoting our own manufacturing, which we need to do better generally. It’s also about not funding the human rights abuses of the Chinese Communist Party.”
Sen. Mike Braun (R-Ind.) | C-SPAN
Indiana snagged a major EV battery manufacturing project in May, when Stellantis and Samsung announced plans to invest $2.5 billion in a plant in Kokomo. Delaying the domestic content provisions “sends a bad message to people in our own country about making the investments, and clearly in my own state, there’s a vested interest,” Braun said.
Whether other Republicans will sign on is less certain. Industry analysts ClearView Energy Partners said that even if some Republicans agree with Manchin’s focus on domestic manufacturing, they may be reluctant to sign on because the IRA also links some of its tax credits to “labor-friendly” provisions on prevailing wages and apprenticeships.
“Accordingly, we think Republicans may be leery of backing Manchin’s modification because it could be viewed as a tacit endorsement of the IRA,” ClearView said in an email note on Wednesday.
Opposition from the auto industry is almost certain, with many automakers already concerned about consumer and dealer confusion about the EV tax credit, according to John Bozzella, president of the Alliance for Automotive Innovation, an industry trade group.
“We want to make sure we don’t increase confusion for customers who might be confused already about what qualifies for a tax credit,” Bozzella said. “So I’m not quite sure what the value of the new legislation is.”
Placating Europe
The IRA’s $7,500 EV tax credit is broken down into two parts. Consumers purchasing a new EV may qualify for half the credit if the car’s battery components are at least 50% manufactured and assembled in the U.S. To qualify for the other half, 40% of the critical minerals in the battery, such as lithium or cobalt, must be sourced either in the U.S. or a country with which the U.S. has a free trade agreement.
The law also limits eligibility for the credit based on an EV manufacturer’s suggested retail price (MSRP) and a buyer’s annual income. The MSRP for EV sedans is capped at $55,000 and for SUVs, at $80,000. The income cap for individuals is $150,000 per year and for couples, $300,000 per year.
Beyond causing confusion at home, the EV tax credits and the IRS delayed guidelines on domestic content have also riled European automakers and their governments, who see the incentives as drawing vital investment dollars away from their countries. Despite being one of the U.S.’s major trading partners, the EU does not have a fair-trade agreement with the U.S., meaning its EVs would not quality for the tax credits.
Speaking at the Washington, D.C., Auto Show on Jan. 19, EU Ambassador Stavros Lambrinidis warned that the IRA could set off a “subsidy war” as both the U.S. and EU put billions into transportation decarbonization. (See Tracking the Contradictions of the US EV Market at the DC Auto Show.)
“That’s a danger because the IRA, the way it’s structured, in a sense is endangering investment in Europe. It is sucking away investment potential, especially at a time of very high energy prices,” Lambrinidis said. “Nothing could be worse for the strength of the U.S. economy and U.S. companies than a weak European economy.”
While still working on the domestic content guidelines, the IRS has an online list of EVs and plug-in hybrids it says are qualified for a $7,500 tax credit. Popular U.S. brands — including Ford’s F-150 Lightning, Chevy Bolt and Tesla’s Model 3 and Model Y — are on the list.
The IRS says many foreign automakers have “entered into a written agreement with us to become a ‘qualified manufacturer’ but [haven’t] yet submitted a list of specific makes and models that are eligible.”
The agency may have provided an opening for foreign models that are leased by individuals. In a recent fact sheet, the IRS identifies leased vehicles as eligible for the commercial EV tax credit, which is not subject to the domestic content requirements of the IRA.
The situation has been difficult for the White House, trying to move ahead with IRA implementation while also trying not to alienate the EU, where Manchin’s bill could be seen as adding more fuel to the fire.
But, in a now-divided Congress, Manchin does not have the leverage he had when Democrats controlled both houses and he was a key swing vote in the Senate.
“In the context of a divided Congress, however, the status quo puts [the IRS] in the driver’s seat,” ClearView said. “Not only does the administration have less to lose by overtly countering the Manchin bill, but the White House might be able to placate allies simply by staying silent and letting partisan divisions quash the measure.”
The window closed Thursday afternoon on New York state’s third offshore wind solicitation.
The New York State Energy Research and Development Authority, which is leading the state’s ambitious offshore buildout, did not release details on the submissions. But at least some of the would-be developers are known: Four familiar names announced later Thursday that they had submitted bids.
Equinor and BP, already partners on Beacon Wind 1 and Empire Wind 1 and 2 off the New York coast, submitted a proposal for a 1,360-MW installation in the Beacon Wind 2 lease area.
Ørsted and Eversource, already partners on South Fork Wind and Sunrise Wind, submitted multiple bids with different configurations.
NYSERDA late Thursday said it has begun the bid review and qualifying process and will post a summary as soon as it can. The timeline estimates that companies chosen for contracts will be notified later in the first quarter of this year and the contracts executed in the second quarter.
In a news release Thursday, Equinor (NYSE:EQNR) and BP (NYSE:BP) said their plan would complement the 3.3-GW combined output of the three other wind farms the two partners are developing off the New York coast, and help the state realize its goal of 70% renewable energy by 2030.
They propose to create manufacturing facilities for key components such as cable parts, blades and nacelles in New York. They also promise $50 million for a collaborative effort to train and support workers for the offshore wind industry, with attention to historically marginalized communities and opportunities for minority- and women-owned business enterprises (MWBEs). They included options to install energy storage to help the state with its energy transition and for BP subsidiary BP Pulse to install up to 1,000 ultrafast EV charge points statewide.
In their news release, Ørsted and Eversource (NYSE:ES) provided few details about the multiple configurations they offered in their multiple bids. But they painted a general summary of the expected results: billions of dollars in economic activity for the state’s economy, strides for economic justice, prioritization of disadvantaged communities and MWBEs, and furtherance of the state’s climate goals.
The partners have reported steady progress so far on labor agreements, workforce training and supply chain development. Construction of their 130-MW South Fork Wind has begun, and it is expected to start producing power later this year. Their 924-MW Sunrise Wind is in advanced development with a late 2025 target for operation.
Meanwhile, Rise Light & Power, which owns New York City’s largest fossil fuel-burning power plant, said Wednesday it had secured a stake in an offshore wind project, and said its plans to convert the plant to a clean energy hub would be part of an offshore wind proposal submitted Thursday.
It had not followed up with further public information by late Thursday.
The subsidiary of LS Power last year proposed making its Ravenswood Generating Station the point of interconnection for power generated offshore, a connection to land-based clean-energy sources upstate, a source of clean thermal energy by repurposing its water intakes and a large-scale battery storage site.
It will cost the U.S. up to $100 billion to build and power the charging network necessary for a massive conversion of the nation’s transportation system to electric vehicles, an analyst said this week during a webinar produced by the EV Charging Initiative, a national collaborative.
“We really have to think in terms of how we build this new network. It’s not just a matter of modifying the existing network” of gas and diesel stations, said Phil Angelides, a partner with EVC Partners, a company created to identify viable building sites for EV charging stations in California.
Clockwise from top left: Phil Angelides, Riverview Capital Investments; Patricio Portillo, NRDC; Rachel Zook, Nuvve; and José Miguel Acosta Córdova, Little Village Environmental Justice | The National EV Charging Initiative
The company surveyed existing truck stops throughout California and found that limits on both the distribution and transmission system would make it difficult for many existing truck stops to convert to full EV charging, Angelides, a former California state treasurer, said during a virtual summit of the collaborative focused on Midwestern states.
Electrifying the nation’s transportation sector is a major goal of the Biden administration, which wants 500,000 public charging stations built nationwide by 2030. That’s about half the number that will be needed by then, according to experts outside of the administration, especially if half of all new automobiles sold in 2030 are electric, as administration officials hope, and if trucking companies embrace battery electric drive systems over diesel.
As a point of comparison, there are about 140,000 conventional fueling sites operating in the U.S., said Tom Kloza, global head of energy analysis at Oil Price Information Service. That total does not include the number of fuel pumps at each station, he said.
The Infrastructure Investment and Jobs Act (IIJA), passed in November 2021, created the National Electric Vehicle Infrastructure (NEVI) formula program, administered by the Federal Highway Administration. (See US Completes Review of State EV Charging Plans.)
The legislation provided $5 billion in NEVI formula grants distributed to all 50 states to “strategically deploy” EV charging stations along 75,000 miles of federally designated highway. The law also authorized $2.5 billion for a competitive grant program. Both grants require 20% local matching.
Charger Challenges
In three separate discussions, the conference also looked at what it will take to electrify diesel-powered trucks and buses as quickly as possible and the difficulty involved in planning, building and getting power to public charging stations.
“There has been a significant commitment by the federal government, and a number of states have put resources forward to support the charging infrastructure,” Angelides said. “The money is substantial, but I don’t think it’s sufficient for the issue in front us.
“Given the uncertainty of the timing of when these EVs are going to show up, both in the light-duty passenger space and the medium and heavy-duty truck space, it’s very hard to finance major infrastructure investments against that kind of uncertain revenue.”
Angelides also argued for an immediate review of how utilities, working with state PUCs, plan system upgrades, which typically take three to five years of planning and negotiation.
In a separate panel, Drew Bennett, executive vice president at Volta Charging (NYSE: VLTA), said the availability of power at any potential charging site can determine whether charging stations are built. The availability of labor in a region is also a factor, as is the availability of transformers.
“Transformers are really backordered,” he said, “and taking over a year [to obtain] for some utilities. This is something that I think is not going away. I think if you want DC fast charging or even large Level 2 charging, we’re going to need a lot more transformers put into parking lots in the future, and that’s something that needs to adjust.”
In a third panel, Chris Bast, a climate and decarbonization policy expert and principal at Hua Nani Partners in Virginia, noted that $7.5 billion authorized by the IIJA should be seen as “a down payment” on the administration’s 500,000 charging station goal.
Lynda Tran, director of public engagement at the U.S Department of Transportation, said the federal money is an effort to stimulate broader direct investment from private companies.
“We are creating a market; we’re creating a demand that is now translating into lots of private sector investment,” Tran said, referencing a recent analysis commissioned by the Natural Resources Defense Council that found the EV industry has spent $210 billion since Biden took office.
Light, Heat … and Transportation
The analysis also concludes that the total potential funding, including grants, loans and tax credits, authorized by the IIJA and the Inflation Reduction Act in the coming years amounts to $245 billion. Bast pointed out another even more significant and obvious — but hardly discussed — consequence of the effort to electrify transportation is the merger of the transportation industry and the electric generation and distribution industries.
“It’s becoming clear that one of the big challenges we’ll be addressing over the next decade is the merger of two huge sectors of the economy, transportation and electric,” Bast said.
“And [by electric], I mean electric utilities and their regulators are going to have a big and important role to play as we try and bring these two sectors together.”
Katherine Peretick, a member of the Michigan Public Service Commission, said the issue is difficult because “it requires a totally new way of thinking about the electric sector and electric utilities.”
Clockwise from top left: Chris Best, Hua Nani Partners; Michigan Public Service Commissioner Katherine Peretick; Geoff Gibson, Forth; Lynda Tran, U.S. Department of Transportation; and Brittney Kohler, National League of Cities | The National EV Charging Initiative
Utilities have for decades supplied power for light, heating and cooling, she said, adding that many utilities across the country include the word “light” in the company name.
“Now we are adding transportation to that list. That means that the jobs of utilities and the jobs of regulators are front and center and are more important than ever as a part of this transition. It will require some unprecedented coordination among all of these parties,” Peretick said.
Referencing a recent report from the Electric Vehicle Council of the Fuels Institute, she said most cities and counties surveyed “had little to no public policies for public EV charging.”
“These policies are currently being established, and we need to make sure we are being thoughtful about their implications and purposefully coordinating with a very wide range of stakeholders that are involved in transfers, transportation and electrification planning,” she said.
“We need to intentionally include a wide variety of parties in this conversation, including parties who have not traditionally been included.
“As the usage of the electric grid changes, the way that we pay to maintain and upgrade that grid is also going to need to evolve,” Peretick said.
To illustrate that point, Peretick mentioned a program the state is coordinating with Consumers Energy (NYSE: CMS-PB), a Michigan utility, transmission company ITC Holdings and EV maker Rivian Automotive (NASDAQ: RIVIN) to install EV charging stations in Michigan state parks.
Rivian is installing the chargers; ITC is paying for the power; and Consumers Energy is paying for the upgrades to power lines inside the parks.
The demonstration project is part of a longer-term plan created by Michigan, Illinois and Wisconsin to build and maintain charging stations around the perimeter of Lake Michigan, she said.
Christopher Budzynski, director of utility policy at Exelon (NASDAQ: EXC) — which serves four major metropolitan areas, primarily in the Mid-Atlantic region as well as northern Illinois — said the company is expecting 4 million EVs in its service area between 2025 and 2040, including 1 million in Illinois alone.
Clockwise from top left: Chris Budzynski, Exelon; Nancy Ryan, eMobility Advisors; Drew Bennett, Volta Charging; and Cory Bullis, Flo EV Charging | The National EV Charging Initiative
“I think we need aggressive policies that promote transportation electrification. That’s the starting point. And then I think specifically as it relates to what we can do as a utility is really promoting policies that support programs that allow us to get ahead of this. I think that’s where we’re starting to find some challenges across the industry where things are just happening so quickly,” he said.
“Your traditional utility model says build it and they will come. I think they’re already here. So, we need to start building out a little bit more to get ahead of them coming in. I think as we look at the light-duty vehicles coming on to the system, it’s happening, and it’s happening in a significant way. I think it’s happening quickly,” he continued.
Budzynski thinks Exelon is going to play a “critical role” in building that infrastructure and “supporting our customers and communities.” He said the company has a number of different programs across its utility subsidiaries that will allow for construction of over 7,000 charging ports, serving light-duty vehicles, commercial medium- and heavy-duty fleets and multi-unit dwellings.”
“We’ve got to also think about resilience and reliability and ensuring that we have that along with … wires that support these charging stations. It is a very comprehensive support role that the utility needs to play,” he said.
Cory Bullis, public affairs director for FLO EV Charging, a Canada-based company that manufactures chargers in Michigan, underscored Budzynski’s point about Exelon’s role.
Bullis said it is vital to create “well-defined roles for utilities to not only invest in infrastructure to support transportation electrification, but to do it on longer time horizons and to do it at a much larger scale. If we want a resilient grid, then let’s make sure we’re deploying assets or chargers that really fit the use case for the expected dwell time. Let’s have smart chargers so we can better manage the load.”
Keynote speakers for the webinar were Illinois Gov. J.B. Pritzker, supporting the crucial role of state governments in the initiative, and Gabe Klein, executive director of the U.S. Joint Office of Energy and Transportation.
The NRDC assisted in planning the event and provided speakers.
