The U.S. Department of Energy announced Monday that it will detail in September or October what regional consortia of industry and government must do to apply for up to $8 billion in federal matching funds to generate and use clean hydrogen on a local level.
Energy Secretary Jennifer Granholm made the announcement at the start of the department’s annual three-day symposium on hydrogen development and use.
The first day of this year’s symposium showed the breadth and depth of the government’s efforts to leverage the expertise of its federal labs in partnership with industry to develop technologies to produce and use low-cost hydrogen in industry, power generation and transportation.
The department’s Notice of Intent to fund hydrogen hub projects also came simultaneously as its $2.6 million Hydrogen Shot Incubator Prize, a contest “to identify, develop and test disruptive technologies that reduce the cost of clean hydrogen production” to help the government meet its goal of hydrogen produced by electrolysis of water at a price of $1/kg.
And it came just 14 months after President Biden announced his administration’s goal to reduce greenhouse gas emissions by 50% by 2030 compared to 2005 levels and create economy-wide net zero emissions by 2050.
“Hydrogen energy has the power to slash emissions from multiple carbon-intensive sectors and open a world of economic opportunity to clean energy businesses and workers across the country,” Granholm said in brief remarks at the start of the symposium. “These hydrogen hubs will make significant progress towards President Biden’s vision for a resilient grid that is powered by clean energy and built by American workers.”
One of the first areas that is expected to replace fossil fuels with hydrogen is heavy transportation, including 18-wheelers as well as locomotive engines and possibly shipping, which would refuel at major ports. There are also plans to replace coke (produced from coal) in steelmaking with hydrogen.
Currently, the nation’s industries produce about 10 million metric tons of hydrogen per year, almost all of it from methane, which leaves behind carbon dioxide.
The hydrogen hub grants will include funding for at least two hubs producing hydrogen from locally produced natural gas but collecting the carbon dioxide for insertion deep underground. Other hydrogen hubs will produce the gas from electrolysis of water, using either renewable energy or power generated by nuclear reactors when grid demand for their output falls.
Today, the U.S. produces about 10 million metric tons of hydrogen annually, most of it from natural gas through high-temperature steam reforming of methane.
Multiple stakeholder groups, including state regulators, protested MISO’s FERC Order 2222 compliance filing on Monday, with many expressing indignation with the RTO’s request to delay implementation until nearly 2030 (ER22-1640).
MISO filed its proposal April 14, with the commission granting its request to extend the standard 21-day comment period until June 6. In a letter accompanying the proposed tariff changes, MISO said its proposed Oct. 1, 2029, effective date is necessary because it will take “several years of technology development to enable DERA [distributed energy resource aggregation] participation in wholesale markets.”
Approved in September 2020, Order 2222 directed all FERC-jurisdictional RTOs and ISOs to revise their tariffs to allow DERAs to provide any services they are technically capable of in their wholesale markets. (See FERC Opens RTO Markets to DER Aggregation.)
The commission had set a compliance filing deadline of nine months after the order’s publication in the Federal Register (about June 2021), but several RTOs quickly requested more time, with PJM and ISO-NE, for example, filing on Feb. 2 (2/2/22). Over that time, officials repeatedly told stakeholders how complex and time consuming the work was. (See “Order 2222 Compliance Work ‘Highly Complex,’” SPP Markets and Operations Policy Committee Briefs: April 11-12, 2022.)
FERC gave RTOs and ISOs flexibility in proposing a deadline for implementation. MISO’s is the longest among the grid operators. It proposes making registration available beginning Oct. 1, 2029, with participation in energy and ancillary service markets offered by March 1, 2030. The RTO told FERC that it first needs to complete its market systems enhancements (MSE) project — a long-in-the-works replacement of its market platform expected by the end of 2024 — before it has the technological capability to comply with the order.
“The completion of the MSE project, including the replacement of MISO’s legacy systems and software with the integration of new market engines into MISO’s systems, is a necessary prerequisite to development of the software and systems needed to incorporate DERA in the [RTO]’s markets,” it said.
MISO also said it wants to prioritize work on its much-delayed Multiple Configuration Resources (MCR) initiative, which is intended to improve modeling of different combinations combined cycle unit types. When completed alongside the MSE project, MCR “is expected to provide reliability benefits by providing operational flexibility needed to manage the MISO region’s increased reliance on intermittent resources, such as wind and solar, to meet the region’s baseload demand needs,” the RTO told FERC.
“While MISO recognizes the benefits of promoting distributed energy resource participation in its wholesale markets through the addition of distributed energy resource aggregations, the benefits of these aggregations are unknown and relatively limited by the existing retail regulatory construct in many of the states in the MISO region.”
Environmentalists, consumer advocates and state regulators said the 2029 date was unacceptable.
The Organization of MISO States said it “recognizes the importance and benefits of MSE and MCR but questions MISO’s purported inability to pursue a parallel path for the implementation of MCR and Order 2222. MISO does not provide sufficient evidence why parallel implementation is not possible outside of a generic description that pursuing these changes simultaneously would increase the risks to reliably implement these products.”
OMS noted that PJM proposed a 2026 effective date, after implementing its new market clearing engine and Enhanced Combined Cycle model in 2025. “From the testimony MISO provided, it is unclear why MISO cannot do the same.”
Filing jointly, groups including the Natural Resources Defense Council, Sierra Club and the Union of Concerned Scientists noted that MISO’s proposed date would push back DERA participation to “nearly 10 years after the commission issued Order No. 2222 and nearly 14 years from the commission’s publication of the Notice of Proposed Rulemaking that led to Order No. 2222.”
“In essence, MISO is arguing that its markets must remain unjust and unreasonable and unduly discriminatory with regard to DERAs for nearly a decade while it sorts out technology issues that it ought to have been aware of and planning for since well before the commission issued Order No. 2222,” the groups said.
Advanced Energy Management Alliance argued that “MISO has not provided a reasonable explanation for such an extended implementation timeline given the rapidly evolving needs of consumers and the overall electric grid.” Similarly, Advanced Energy Economy and the Solar Energy Industries Association jointly argued that “by choosing to implement other initiatives over compliance with Order No. 2222, MISO is choosing to keep barriers to participation of DER aggregations in place nearly a decade after the commission first sought to remove them.”
Utility and TO Support
In contrast, MISO member utilities were largely supportive of the timeline, agreeing with the RTO on the complexity of the work.
“In permitting thousands of new generation resources to access wholesale markets, Order No. 2222 requires enormous technical planning to ensure that local distribution and transmission systems are upgraded to accommodate the new resources; that market rules, IT systems and data requirements are sufficient to allow coordination of these new resources without jeopardizing safety, reliability or cybersecurity; and preservation of appropriate roles and authorities for both state regulators and local distribution system owners,” Consumers Energy said.
“This is no small task, as MISO’s filing makes clear — particularly when implementation must take place alongside efforts to address other critical priorities of RTOs and ISOs, including reliability, resiliency, customer affordability and a seismic shift in the electric grid’s underlying resource mix.”
Alliant Energy said it “generally supports the changes as filed, recognizing that there is still much to learn and understand regarding the operation and impact of DER aggregations in MISO’s markets.” Ameren said it “appreciates MISO’s independent assessment of its current capabilities and supports MISO’s determination that the identified software improvements need to be completed before other initiatives can be launched.”
While noting “potential revisions … are needed,” MISO transmission owners also supported the effective date.
“MISO has undertaken multiple initiatives … to address the unique and complex challenges to electric system reliability in the MISO region,” they said. “Completion of these initiatives is expected to bring immediate and quantifiable reliability and economic benefits to the MISO region. At the same time … only three states in the MISO footprint currently permit retail demand resource aggregation, which could significantly limit participation of such aggregations in MISO’s markets.”
Maryland Gov. Larry Hogan (R) tells a great story about his part in hammering out the compromises needed to get the bipartisan Infrastructure Investment and Jobs Act (IIJA) passed in 2021.
Hogan was then chair of the National Governors Association and had a particular focus on infrastructure, he recalled at a Thursday seminar on the IIJA hosted by the Bipartisan Policy Center in D.C. When negotiations over the bill got bogged down, Hogan said, “I hosted kind of an unprecedented summit in Annapolis, where I brought together Republican and Democratic governors, senators and congressmen. … We locked them in a room, plied them with alcohol and crabcakes for two days and walked out of the front door of the governor’s mansion with a basic deal” and set of recommendations for the $1.2 trillion package.
But, six months on, the challenge for the Biden administration and state governments like Maryland’s is getting the money out the door and ensuring it gets to the projects and communities where it will have optimal impacts, Hogan and other speakers at the event said.
“Getting access to that money is not easy,” said Karen Wayland, CEO of the GridWise Alliance, a nonprofit focused on grid modernization. “Getting access to federal dollars requires you to have grant writers, requires you to do all sorts of reporting,” which smaller utilities that need the funds may not have the resources for, she said.
“How do we help all utilities everywhere access federal money?” Wayland said. “Because if we don’t, then we’ll be moving toward what I call an expanded view of the digital divide” on grid modernization.
The states have a critical role in implementation of the law, Hogan said. IIJA funds flow through state agencies to individual projects, he said, and state and local officials need both clear guidance and flexibility to ensure the money is spent efficiently and effectively.
According to a recent IIJA progress report from the White House, allocations to Maryland now total about $1.7 billion, with more than 80% earmarked for transportation infrastructure and the remainder going primarily to climate and energy projects.
Still, Hogan cautioned that while the IIJA is “an important step forward, it’s not quite the transformational, immediate thing. Everybody thinks we all of a sudden have trillions of dollars in this big pile in the back of our State House that we are ready to dole out. … It’s basically a 20% increase in infrastructure spending spread over five years, so it’s about a 4% [per year] increase in infrastructure.”
Similarly, in a moderated discussion at the BPC event, Hogan and Calvin Butler, chief operating officer of Exelon (NASDAQ:EXC), spoke of the law, and its billions for transportation, energy, water and broadband infrastructure as a foundation or force multiplier that will stimulate private investment and public-private partnerships.
Following the recent separation of its regulated utilities and nonregulated energy generation and services business, now Constellation Energy, Exelon has committed $29 billion in capital spending to transmission and distribution infrastructure through 2025, Butler said. With its own infrastructure task force, the utility plans to “partner with our local jurisdictions across the country to say, ‘If you’re going to target and go after any of those [IIJA] grants, we’re going to partner with you to leverage our dollars,’” he said.
In Maryland, for example, the utility is working with two counties seeking federal dollars to electrify their bus fleets to ensure a system of chargers is in place, Butler said.
The state has backed up such efforts, Hogan said, with public and private infrastructure spending, reforms aimed at cutting red tape and an infrastructure subcabinet established “to develop, evaluate and coordinate a cohesive infrastructure strategy that leverages” the IIJA funds.
“It’s not like we flipped the switch, and all our problems are over,” Hogan said. “It’s a small investment from the federal government, and we’re going to try to utilize that to spur a whole lot more private sector investment.”
Waiting for Guidelines
Since President Biden signed the IIJA into law in November, the White House and federal agencies have been focused on getting the money out, with some agencies, such as the Energy Department, announcing new funding opportunities almost weekly.
In January, the White House issued the 459-page Bipartisan Infrastructure Law Guidebook, which provides a high-level overview of all the funding in the $1.2 trillion law, plus online links to specific funding opportunities and information on eligibility and how to apply. Additional guidebooks breaking down the law’s funding include one each for rural and tribal communities, as well as a technical assistance guidebook aimed at providing “targeted support” to help communities and organizations access specific funding in the law.
More detailed information has been issued for individual funding streams in the IIJA, such as the law’s $7.5 billion for electric vehicle charging infrastructure. A memorandum on the program, which aims to put 500,000 EV chargers on American highways, was issued in February. (See States to Get $615 Million for EV Charging from IIJA Funds.)
But guidelines for other key infrastructure programs have been slower in coming, Hogan said. State and local officials are still waiting for guidelines for a cybersecurity grant program, and state allocations for the law’s $65 billion in broadband funding have been delayed while the Federal Communications Commission updates its service maps.
At a hearing before the House Energy and Commerce Committee in March, FCC Chairwoman Jessica Rosenworcel pledged to have the new maps completed by this fall. But a “challenge period” mandated by the IIJA, in which the maps may be contested by local communities, could further delay final determination of the allocations.
Consistency of Funding
Even when the process encounters fewer snags, challenges remain for state officials accessing IIJA funds. The EV charging funds provided a prime example for speakers on a panel following Hogan and Butler on Thursday.
Phil Jones, executive director of the nonprofit Alliance for Transportation Electrification, said that money will flow through state departments of transportation, which don’t understand the electric power system. “Building out these charging stations, especially for medium- and heavy-duty vehicles, it’s going to put stress on the grid. These are large loads coming in.”
Wayland sees a different but equally significant disconnect “between the speed with which the [automakers] have decided to make investments to transform the fleet and the desire of consumers to transform the way they drive, and the ability of the utility industry to move quickly enough to be there when people want to plug all those vehicles in.”
“We’re not going to break the grid in the long term,” Wayland said. “But in the short term, I think we’re going to see some bumps because the utility industry, even when the capital is available, has to move through a very chunky, cumbersome regulatory process.”
She hopes that grid improvement funds in the IIJA “will help de-risk some of the decisions that the policymakers and the regulators have to make when it comes to the investments that are going to be critical for supporting transportation electrification.”
A second, more detailed set of guidelines for the EV charging money could be released at a two-day stakeholder event on Thursday and Friday, to be hosted by the Joint Office of Energy and Transportation, set up by DOE and the U.S. Department of Transportation to oversee distribution of the funds, Jones said.
David Strickland, vice president of global regulatory affairs at General Motors, said his company is committed to ensuring EVs and charging infrastructure are available, and affordable, for all communities as it moves toward an all-electric fleet by 2035.
His main concern on implementation of the IIJA is “consistency of funding. We have a five-year tranche of money, and I think a lot of people are betting to make sure that it is a consistent level. I have seen more than a few times in my life where there have been interruptions of that money at the federal level, especially … for these communities in need,” he said.
For Jones, the IIJA’s $7.5 billion for charging infrastructure is only a down payment. He predicts the U.S. could need up to $250 billion for EV charging to remain competitive with China and Europe.
“We’re going to have to renew this federal infrastructure bill in five years,” he said. “So, we just have a lot more to do.”
NERC and the regional entities continued to see significant cost savings because of the COVID-19 pandemic last year, according to the ERO Enterprise’s yearly budget true-up report filed with FERC last week (RR22-3).
The commission requires NERC to report the ERO’s cost-to-budget comparison every year, along with audited financial statements for itself and each RE, giving the reasons for significant differences between the planned and actual figures. The filing must also include a justification for any use of cash reserves and explanation for why their use constitutes “unforeseen events” and not “a means to fund expected projects outside of the budget approval process.”
According to last week’s filing, NERC and every RE besides the Texas Reliability Entity spent less than they expected in 2021. NERC’s savings were the largest at more than $2.5 million, though its $80.3 million spending (actual) was also much bigger than any RE. Revenue was higher than planned for most entities, though Texas RE, SERC Reliability and the Northeast Power Coordinating Council reported their actual funding was lower than they had projected.
While NERC and the REs had factored some continued cost savings from the pandemic into their 2021 budgets, the ongoing shutdown of almost all business travel and cautious return-to-office policies across the ERO Enterprise meant entities spent even less than expected. (See NERC Aims for Cost Control in 2021 Budget.) NERC’s meetings and travel category, for instance, came in $1.9 million underbudget and personnel expenses were underbudget by $150,000, partly from “lower parking and transportation benefits due to the pandemic.”
Other entities told a similar story: The Midwest Reliability Organization spent just $5,904 of its $963,000 meeting and travel budget in 2021, and ReliabilityFirst similarly saved over 92% of its $980,000 budget for the same line item. Only WECC saw a savings of less than 90%, spending $58,097 of its $378,000 meetings and travel budget in 2021.
Some entities saved money last year by doing work inhouse that they had planned to outsource to consultants or contractors; NPCC, for example, replaced independent compliance auditors with full-time staff. NERC said that “increased experience and expertise gained by entity staffs, and implementation of process efficiencies, has enabled entity staffs to perform and complete work for which consultants or contractors were previously used.”
Despite the overall savings, however, several entities did report overspending in some categories, particularly personnel. For instance, although NERC’s personnel expenses were underbudget overall, the entity said the savings were largely from the capitalization of certain labor costs associated with various projects; without this capitalization, the category would have been $362,000 overbudget.
SERC and NPCC also reported greater-than-expected spending on salaries; in NPCC’s case, this was part because of the use of inhouse staff rather than consultants for compliance audits. SERC said its expenses were from raising compensation for critical staff because of market demand, along with incentives paid out by its Board of Directors for “exceeding corporate strategic initiatives and key performance indicator goals.”
NERC and the REs are currently accepting comments on their draft 2023 business plans and budgets, which they posted last month. (See NERC Plans Big Budget Hike for 2023.) The total ERO Enterprise budget is set to be $248.9 million, about $22.7 million more than the budget for this year. NERC’s budget hike of $12 million represents the lion’s share of the increase, but all REs are planning to raise their spending as well because of the current high inflation rate in the U.S. and the need for investments in cybersecurity. (See ERO Warns Inflation, Cyber Investments to Keep Boosting Budgets.)
The California Air Resources Board’s draft climate change scoping plan — and its proposal for the state to reach carbon neutrality by 2045 — is facing criticism from many directions.
In a letter submitted to CARB last week, a group of 73 environmental organizations said the plan would fail to meet the state’s greenhouse gas reduction requirements by 2030, as well as the 2045 carbon neutrality target.
Instead, the plan “relies on record-breaking levels of unspecified mitigation from the cap-and-trade program in 2030 and entirely unrealistic levels of direct air capture in 2045,” the groups wrote.
“This is not a serious climate plan for California,” they said.
The letter’s signatories include representatives of the Sierra Club, Earthjustice, California Democratic Party Environmental Caucus, and the Center on Race, Poverty and the Environment, among others.
Grid Impacts
On the other side of the debate are individuals who question the scoping plan’s push toward electrification — and the impacts that would have on the electric grid.
“The state of California does not have safe or reliable power,” wrote Dawn Durfee, who said she lost her home in the Paradise wildfire. Requiring all vehicles to be electric would only make matters worse, she said.
“People do need to run refrigerators, washers, dryers, air conditioners or heaters,” Durfee said in a letter to CARB. “People do not need to drive electric cars.”
In addition, Durfee said, worldwide air quality won’t improve until China and Russia cut their emissions.
“California is not the ruler of the universe!” she wrote.
Other letter writers said they couldn’t afford to buy an electric vehicle, or that an EV wouldn’t be able to tow their trailers. Some pointed to the environmental impact of used EV batteries.
“Forcing electric cars on the population is full of disastrous consequences,” Susan Dwyer said in a letter to CARB.
The CARB board will hold a public hearing on the plan on June 23. Written comments are due by June 24.
The scoping plan evaluates four scenarios. Alternatives 1 and 2 would bring the state to carbon neutrality by 2035. In Alternatives 3 and 4, the state would reach the target 10 years later, in 2045.
CARB staff have proposed going with Alternative 3, which would have the least impact on employment and economic growth among the four options, according to the draft.
In contrast, Alternative 1 would have the highest direct costs and slow economic growth the most, the plan said. That alternative would nearly eliminate fossil fuel combustion by 2035 and would have a limited reliance on carbon capture and sequestration.
Some letter writers called the proposed alternative “too little, too late.”
“Choosing the least expensive option, relying on unproven carbon capture technologies, [and] determining job loss without adding in job creation as the energy sector changes is disheartening,” wrote Meredith Rose. “My kids deserve better — and so [do] everyone else’s kids.”
The letter from the 73 environmental groups makes several policy recommendations, including phasing out fossil fuel extraction by 2035 and refining by 2045. Regarding electric power, the groups called for a ban on new gas-fired generation starting immediately and a target of zero GHG emissions by 2035.
“Fundamentally, the draft scoping plan fails to move California beyond oil and gas,” the groups wrote.
‘Puzzling’ Plan
An editorial in the Los Angeles Times on Friday called the scoping plan’s approach “puzzling” in light of California Gov. Gavin Newsom’s directive to CARB to accelerate climate action. The governor famously referred to the “climate damn emergency” when wildfires swept through the state in 2020.
And in July 2021, Newsom asked CARB to look into how carbon neutrality could be achieved by 2035.
The editorial said the plan would use “unproven technology” to remove “huge amounts” of CO2 from the air as well as capture it from cement plants and oil refineries.
Calling the carbon removal approach a “pie in the sky strategy,” the editorial advised using proven approaches.
“In reality, we already have most of the solutions to the climate crisis right in front of us — electrifying everything we can as quickly as possible and fueling it with clean renewable energy,” the editorial said.
Clean Grid Alliance on Monday asked MISO to consider penalty-fee withdraws for advanced-stage interconnection projects that are saddled with expensive network upgrade costs from SPP’s delayed affected system study (AFS) results.
A month after requesting relief for late-stage projects held in limbo until they receive AFS results from SPP, CGA’s Rhonda Peters returned to MISO’s Interconnection Process Working Group (IPWG) to propose a penalty-free withdrawal for projects rendered infeasible by SPP-identified upgrade costs. (See CGA Requests MISO Help for Late-stage Interconnection Projects.)
MISO and SPP have rolled out a new “first ready, first served” interconnection queue priority for generation projects that affect the seams through studies and cost assignments for network upgrades. The new order replaced the grid operators’ previous practice of studying projects that lined up for the queue first. (See FERC OKs New Queue Priority for MISO, SPP Seams Studies.)
In MISO, the new priority bypassed projects that entered the queue in 2018 and 2019. The RTO said those project cycles are destined for generator interconnection agreements (GIA) before the changes take effect.
Peters said some late-stage projects that entered the queue with the 2018 and 2019 cycles still don’t have “complete, accurate or available” network upgrade costs from SPP’s affected system studies.
She said the uncertainty has jeopardized the projects’ financing and power purchase agreements. “The risk factor is too high,” she said.
Peters said MISO should consider allowing penalty-free withdrawals from the queue when late AFS results unexpectedly increase affected system costs. That would allow developers to depart the queue without forfeiting their milestone fees, she said. Peters said MISO could allow projects to interconnect beyond the original seven-year deadlines to reach commercial operation or it could provide nonbinding estimates of likely upgrade costs to aid the developers’ decision making.
Peters said developers of late-stage generation projects have already committed significant capital but might be forced to withdraw when AFS costs “are so high that they could completely change the financial viability of the projects.”
“Advanced stage projects only withdraw if forced to due to circumstances beyond their control, such as unexpected or new network upgrades,” she said. “The financial commitment to reach GIA is significant, even without consideration of milestones. … The interconnection customer wants to reach its commercial operation date. Withdrawals occur only when there is no other course of action.”
MISO’s Ryan Westphal said allowing penalty-free withdrawals could “potentially harm other customers.” The RTO usually keeps milestone fees when interconnection customers leave the queue to minimize the costs of network upgrades on lower-queued projects.
Stakeholders pointed out that AFS results can often double an interconnection customer’s network upgrade costs.
Westphal asked whether other stakeholders would be comfortable with penalty-free exits from the queue.
Invenergy’s Sophia Dossin said while her company has projects in the 2018-19 cycles of the queue, it also has projects that entered in 2020 and later. She said Invenergy is poised to be affected on both sided of the issue and is comfortable with penalty-free exits.
“I would say a lot of customers that are being impacted by the 2018-19 delays will also be impacted by the penalty-free withdrawals. … If there were a Venn diagram, there would be substantial overlap.” Dossin said. “This already is creating a lot of financial issues today.”
Dossin added that no project’s financing partner wants the risk of a “multimillion dollar question mark” on projects waiting on AFS upgrades.
“We’re not in the business of playing games. We’d rather see our projects online,” National Grid Renewables’ Rafik Halim said. He added that he didn’t think developers would view the option as an unconditional “greenlight” to remove generation projects from the queue.
“We shouldn’t be signing a blank check as we sign our GIAs,” Halim argued.
Peters said MISO could institute “rigid” criteria, such as a minimum cost threshold increase for network upgrades.
Westphal said MISO wouldn’t likely move forward with a penalty waiver unless all stakeholders are on board.
“In our opinion … this seems like a mechanism to allow harm and financial impact to other customers,” he said.
Staff also pointed out that interconnection customers should already be estimating a spectrum of AFS costs. They said extending operation deadlines for the 2018-19 project cycles might simply perpetuate uncertainty and affect lower-queued generation projects.
Peters argued that it would “make a huge difference” to financiers if bookends for upgrade cost changes came from MISO instead of the interconnection customers themselves.
MISO is set to again discuss the fate of the 2018-19 interconnection projects during the IPWG’s August meeting.
Connecticut’s ongoing investigation into opportunities to integrate medium- and heavy-duty electric vehicles (M-HDEV) on the state grid is at the forefront of rate design in the U.S., Benjamin Mandel, Northeast region senior director at the nonprofit CALSTART, said Tuesday.
“I don’t think there are robust examples of a state that’s taken a statewide approach, particularly that has been fit for purpose on M-HD vehicle electrification, especially with regard to rates,” Mandel told the Connecticut Public Utilities Regulatory Authority (PURA).
While a handful of utilities in the U.S. have taken the initiative to establish charging rates for the large EV segment, Mandel says it’s still “early days” for those programs.
“We don’t have a ton of empirical track record to go on to see how the rates are doing, and how the fleet operators for whom those rates were designed … are adjusting and responding to them,” he said during a technical meeting for PURA’s investigation (Docket 21-09-17).
Mandel spoke to regulators on behalf of the Connecticut Department of Transportation, which CALSTART supports through a Federal Transit Administration grant. PURA launched its investigation last fall and is taking input from state agency representatives and members of the public through a series of technical meetings.
“We have an opportunity to take guidance from some of these [utility rate] examples and pick and choose elements that seem interesting and appropriate for the Connecticut context and work with the [state utilities] to make sure that they’re able to be implemented here,” Mandel said.
The authority’s investigation complements its decision last summer in a separate docket to develop infrastructure incentives and rate design options for light-duty EV charging. (See Connecticut Set to Pull Trigger on EV Charger Program.)
Innovative Approach
In California, Pacific Gas and Electric’s business EV charging rates have a longer track record than others in the U.S. and is considered innovative, according to Mandel.
The utility offers separate charging packages based on business size that include time-of-use consumption rates and reduced demand charges, which Mandel says is a common theme across other utility offerings. PG&E’s design, he said, differs by allowing fleets to “determine for themselves how much demand they want to subscribe to in either 10-kW or 50-kW blocks.”
Customers can subscribe to the demand blocks on a month-by-month basis, but they must pay a fee for going over the block. In that case, a customer can adjust the next month’s block to match the increased demand.
By lowering demand charges and offering flexible monthly subscriptions, PG&E also benefits from some predictability from its larger EV charging customers, Mandel said.
Like PG&E’s business offering, he added, utilities’ M-HDEV charging rates should be cost-driven, balanced, predictable, flexible and forgiving.
Mandel recommended that regulators think of charging rates in terms of different load characteristics instead of being technology-specific, such as light duty vs M-HD.
“The predominant forms of commercial and industrial rate designs in place by utilities nationally … were not developed with these types of load shapes and load factors in mind,” he said. “We have different charging behavior and charging behavior possibilities at play with the policy goals that Connecticut and other states have signed on to.”
WESTMINSTER, Colo. — SPP continued its delicate dance with Western Interconnection entities last week with a charm offensive that included a first-hand look at the RTO’s “sausage-making” process.
Promoted as a development session for Markets+, SPP’s “RTO light” offering, the two-day gathering at Tri-State Generation & Transmission’s headquarters gave the grid operator’s staff and Western stakeholders a chance to share their thoughts on a proposed governance model, transmission operations, congestion management and the benefits of RTO management.
Western utilities have long been wary of transferring control of their transmission facilities to RTOs, but SPP officials said they were pleased with the “healthy dialogue” and exchange of information. They also noted an increase in turnout from an earlier face-to-face session in Phoenix, with more than 100 in-person attendees and more than 80 participating virtually.
Another session will be held in Portland, Ore., in August.
Listening intently during the two days was Kathleen Staks, director of Western Freedom, a coalition representing large industrial customers in technology, oil and gas, mining, renewable energy, agriculture and other sectors. Staks took a guarded approach the discussion.
“We’re sort of tracking and compiling information and comments on behalf of our coalition … trying to kind of make sure that the customer voice is represented and incorporated into these efforts for whatever the end result is,” she told RTO Insider. “It’s about lower rates, it’s about access to clean energy, but it’s primarily an economic conversation in our coalition.”
Brad Hans, director of wholesale electric operations for SPP member Municipal Energy Agency of Nebraska — and also a member of MISO and WECC — was quick to share with others his company’s positive experience with SPP’s stakeholder process. He pointed out that the discussions taking place in Colorado were very similar to those of the RTO’s members during their stakeholder meetings.
“This is a true example of what SPP is all about, and that is members driving us. This whole meeting was about what they’ve done so far, and that is absolutely SPP’s stakeholder concept,” Hans said afterward. “I kind of wonder if they realize they’re in the midst of that right now … those that aren’t as familiar with SPP and, through this development process, in that culture as they develop this.”
AG Policy Solutions’ Alaine Ginocchio — “That’s Pinocchio with a G,” she said — consults with Western Resource Advocates, a public interest organization that was prominent during SPP’s attempt to integrate the Mountain West Transmission Group (See Xcel Leaving Mountain West; SPP Integration at Risk.) While she reluctantly uses the “sausage-making” expression, she appeared to like what she saw.
“We’re used to having sort of a higher level of stakeholder engagement and being engaged on more of an equal footing with everybody else,” she said. “The energy market they’re standing up right now … is structured more to have equal footing. Not as much as CAISO, but it’s a different program. Public interest organizations have more of a voice in voting and processes [in Markets+] … and that sort of flows out of how other regional coordination efforts have worked. That’s what we’re used to, and it has worked.”
Incremental Changes in the West
Those out West will say the Western energy crisis of 2000-01, when Enron’s market manipulation led to rolling blackouts in California, had a chilling effect on regional coordination and energy markets. SPP Director Mark Crisson, who spent nearly 30 years with Tacoma Public Utilities, said in April that “RTO paranoia” still hangs over the balkanized region and its 38 balancing authorities. (See SPP Strategic Planning Committee Briefs: April 13, 2022.)
“There’s a lot of concern about FERC regulation,” Crisson said during an SPP Strategic Planning Committee meeting. “A lot of people remember that exercise.”
Change has been incremental in the West since then. The region’s wide open spaces and political differences can make it difficult to coordinate regionally, but renewable standards, the success of Eastern markets, CAISO’s Western Energy Imbalance Market (WEIM), and legislation in Colorado and Nevada mandating that utilities join RTOs by 2030 have managed to bring the interconnection’s entities closer together.
The Markets+ day-ahead market is another incremental step toward a Western RTO. It provides a “voluntary” opportunity to realize the benefits of centralized day-ahead and real-time unit commitment and dispatch, “hurdle-free” transmission service, and “reliable” integration of renewable generation for utilities that aren’t ready “to pursue full membership in” an RTO.
“We recognize that not everyone is at a point where they’re comfortable moving to an RTO, because they are transferring control of their facilities to the RTO,” SPP Senior Vice President of Operations Bruce Rew told the gathering. “We see Markets+ as a possible long-term solution to meeting some market needs.”
All of this is familiar to Xcel Energy’s Carrie Simpson, director of Western markets for Xcel’s Public Service Company of Colorado. Simpson joined Xcel in 2015 after helping design SPP’s Integrated Marketplace, which will serve as the foundation for Markets+.
“It’s a similar vibe,” she said before appearing on a resource adequacy panel.
Simpson has become something of a rock star in Western power circles for her market expertise. She was not present for the opening introductions, but Joe Taylor, manager of transmission access for Xcel Energy Services, made sure everyone knew she would eventually show up.
“Joe Taylor, Xcel Energy. And don’t worry, Carrie Simpson will be here in a few hours,” he said to laughs.
Governance Model a Key Issue
SPP has said Markets+ will eventually replace the Western Energy Imbalance Service (WEIS) market it currently operates. When three new members join the WEIS next year, it will be regionally balancing 13.5 GW of load generation. Rew said an imbalance market is a great introduction to markets but is only a short-term solution for participants.
“There are some limitations to Markets+,” Rew said. “You don’t have a regional tariff; you don’t have a consolidated balancing authority, so you’re not going to get all the benefits. It will provide a lot of potential outcomes for certain market participants that are uncomfortable moving to an RTO.”
SPP is attempting to ease that discomfort. It has hired two very familiar faces from the West in Steve Johnson, formerly senior vice president of the Colorado River Storage Project for the Western Area Power Administration, and Kara Fornstrom, former Wyoming Public Service Commission chair. Johnson is directing the RTO’s various markets’ administration and operation. As director of state regulatory policy, Fornstrom is leading state regulatory policy efforts in the West where she appears to be on a first-name basis with many participants.
SPP executives also pointed out that two members of its board, Crisson and newly-elected John Cupparo, both have deep ties to the West. A Colorado State graduate, Cupparo was CEO of Berkshire Hathaway Energy’s transmission subsidiaries and also served in leadership roles at PacifiCorp, WECC and Northern Tier Transmission Group.
“Somebody made the comment [earlier], ‘Do I want a board member from Little Rock [Ark.] determining matters for the [Western] markets?’” SPP legal counsel Paul Suskie said. He took pains to note that only one SPP director (Oklahoma law professor Phyllis Bernard) has ever hailed from the footprint, and that she has since moved to Oregon. The other 16 directors since 2004 have come from outside the RTO’s service territory.
“So that gives you a taste of the board,” Suskie said. “They are truly independent.”
That is important, as the West’s most immediate experience with an organized market is that of CAISO, where the board is appointed by California’s governor.
Last week, SPP shared a straw man of its proposed Markets+ governance model, based on input from Western stakeholders and the grid operator’s best practices. The model is also designed to gain FERC approval and to minimize financial consequences for SPP, which will have to carry the debt necessary to stand up the market.
The model has an independent panel, comprised of one SPP director and four Western representatives elected by a forum of Markets+ participants and stakeholders, that would govern market operations and report to the RTO’s board. Suskie was asked why it’s called a panel and not a board. Simply to avoid confusion, he said.
The Markets+ Independent Panel (MIP) would oversee a Markets+ Participants Executive Committee (MPEC), which would be responsible for creating and managing the various stakeholder groups. A Markets+ State Committee would provide input from Western regulatory commissions to both the MIP and MPEC.
Market participants will be classified as either participants or stakeholders, depending on whether they contribute generation or load. They will sign either participant or stakeholder agreements, with stakeholders retaining voting rights in return for an annual $5,000 fee. Non-voting stakeholders could eschew the fee and provide input during stakeholder meetings, but they would not have voting rights.
The design is part of SPP’s key foundation of ensuring everyone can contribute to stakeholder discussions, Rew said.
“We are going to continue to foster engaging discussions on Markets+, making sure that we give voice to diverse perspectives,” he said. “Then, continuing to develop this vision for Markets+ until ultimately Markets+ is your market. It’s not just for the participants, but also the benefit it provides overall to the Western Interconnection.”
Maury Galbraith, executive director of the Western Interstate Energy Board, called the governance model “acceptable,” and alluded to a race between SPP and CAISO to establish a Western RTO.
“You get a lot of people saying that ‘This is not a race.’ People say, ‘No, it is a race. It is a competition; we need to move forward,’” Galbraith said. “I understand that time is important here. The governance proposal is something that is probably acceptable to a large number of states. I think the word ‘acceptable’ is right. I don’t see any showstoppers in there. I’m not aware of any state that is, sort of at the point where they’re ready to go to FERC and oppose anything.
“I think it’s a workable solution. But in terms of the overall competition and really striking a bold governance structure, I don’t see the proposal being a bold proposal. I think we could have gone farther in terms of really trying to win the governance battle, if that’s what it is. I think there’s some additional steps that could have been taken to really, really come up with a best-practice governance structure, and I’d be happy to have that conversation.”
Next Steps for Markets+
Galbraith’s comments were among several, some more pointed than others, from a panel during a breakout session on the proposed governance model. Suskie thanked those offering feedback. What they had just experienced, he said, was a best practice at the RTO.
“We like to call this an example of how SPP does things,” he said before drawing on his experience as an officer in the Army reserves during a stint in Afghanistan. “We put out a straw proposal, we put on our body armor, and we get shot at. We have our ideas, we take feedback, and then we can figure out how to adjust it. Part of the balance that we have is SPP has a lot of responsibilities. It’ll be SPP’s tariff and it will be SPP who will be operating this market and facilitating that.”
Suskie and Fornstrom took the comments and returned the next day with a revised timeline. An updated governance proposal will be shared during a June 24 webinar, with written comments due July 15. SPP will summarize the written comments in another webinar before the Portland workshop.
While governance took much of the spotlight, attendees also heard updates from the transmission availability and the market products/price formation design teams. Western stakeholders briefed the room on greenhouse gas tracking and a panel of market monitors — SPP Market Monitoring Unit Vice President Keith Collins; Libertas Market Analysis’ Jeff McDonald, formerly ISO-NE’s Monitor; and Potomac Economics’ David Patton (virtually) — shared their thoughts on internal, external and hybrid monitoring structures.
Western Power Pool (WPP) CEO Sarah Edmonds, just months into her new position, appeared virtually to describe the potential relationship between Markets+ and the pool’s Western Resource Adequacy Program (WRAP), which SPP already administers in partnership with WPP. Assuming FERC’s approval of WPP’s tariff, the WRAP is scheduled to go live early next year, with members demonstrating they have procured the required quantity of credited capacity from physical resources. In return, they get priority access to WRAP’s supply.
“We have a lot of success in the region brokering consensus on a workable package around governance. A lot of the elements that have been addressed in governance for Markets+ are common to WRAP or even originated from WRAP … trying to solve some of the hardest problems in the West based around governance,” Edmonds said.
“This is still an incremental program that’s singularly focused on resource adequacy and not a market. It is not an RTO but it is a workable framework and one that we’ve always said from the very beginning would be compatible with a market … and here we are in a conversation with the West with a couple of options on the table,” she said. “[Resource adequacy] is a very important foundation for healthy well-functioning markets, and I think WRAP can serve that purpose for Markets+.”
SPP plans to have draft service offerings available for comment by the end of September. Participants will be able to agree to financially binding commitments in the first quarter of 2023, at which point they can develop the market protocols and tariff language.
Attempting to blunt the impact of the Commerce Department’s solar import investigation, President Joe Biden on Monday invoked a 1930 law to declare a two-year tariff waiver on imports of solar cells and panels from Cambodia, Malaysia, Thailand and Vietnam.
Citing a section of the Tariff Act of 1930, the president declared an emergency threat to the America’s supply of solar panels and electric reliability, which will allow panels from the four Asian countries to be imported into the U.S. duty free for two years.
“This comes as a surprise because this isn’t something that was on our radar or a lot of people’s radar as a way to deal with” supply delays and cancellations caused by the investigation, said Christian Roselund, senior policy analyst for Clean Energy Associates. “But the Biden administration said they were going to do something, and they appear to have found a legal avenue to do so.”
“Two years of imports not being subject to duties is huge,” Roselund said.
However, Monday’s announcement does not derail the investigation into claims by Auxin Solar Inc., a California-based solar manufacturer, that panels imported from Cambodia, Malaysia, Thailand and Vietnam contain Chinese components subject to tariffs imposed by the Trump administration and continued by Biden. (See Biden Extends Tariffs on Imported Solar Panels.)
Depending on the investigation results, new tariffs could still be imposed on solar imports from the four countries, but not until the end of the two-year waiver in 2024.
The solar industry conducted an intensive lobbying campaign urging Biden to provide relief from the tariff investigation. Because more than 75% of panels used in utility-scale projects in the U.S. come from Cambodia, Malaysia, Thailand and Vietnam, the investigation, begun in March, has had a chilling effect on solar projects. A recent survey by the Solar Energy Industries Association (SEIA) found hundreds of developers across the country reporting supply delays or cancellations.
ClearView Energy Partners said the Commerce Department is expected to issue its preliminary findings in the investigation in August, with a final ruling in January 2023. No tariffs resulting from the investigation would be retroactive.
“I remain committed to upholding our trade laws and ensuring American workers have a chance to compete on a level playing field,” Commerce Secretary Gina Raimondo said in a statement released after the president’s announcement. “The president’s emergency declaration ensures America’s families have access to reliable and clean electricity while also ensuring we have the ability to hold our trading partners accountable to their commitments.”
Response from solar and clean energy organizations was swift and positive.
Advanced Energy Economy CEO Nat Kreamer called the tariff exemptions “a needed stay in a more than decade-long tariff war that has been a loser for all parties. Tariffs only raise costs for consumers and don’t create domestic demand for clean energy.”
SEIA CEO Abigail Ross Hopper praised Biden’s “thoughtful approach to addressing the current crisis of the paralyzed solar supply chain. The president is providing improved business certainty today while harnessing the power of the Defense Production Act for tomorrow.”
But Auxin CEO Mamun Rashid issued a statement criticizing Biden for “significantly interfering in Commerce’s quasi-judicial process. By taking this unprecedented — and potentially illegal — action, he has opened the door wide for Chinese-funded special interests to defeat the fair application of U.S. trade law.”
Legal action challenging the waiver is possible, according to ClearView.
DPA and Federal Procurement
The waiver is the centerpiece of a three-part initiative that, ClearView says, reflects Biden’s ongoing efforts “to resolve tensions between domestic politics and [his] transition policy goals. … Fuel prices appear to have pinned the White House between voter backlash against inflation and campaign promises to accelerate [the energy] transition and end federal fossil energy leasing.”
Biden also authorized the Department of Energy to use the Defense Production Act to help expand domestic manufacture of solar panel components, as well as building insulation, electric heat pumps, grid equipment such as transformers, and electrolyzers used to produce green hydrogen.
Federal procurement will also be enlisted to boost domestic demand and manufacturing via special contracts, called master supply agreements, and “super preferences” for made-in-America solar systems. By making it easier for U.S. companies to sell to the government, these measures could increase demand for domestically produced solar panels by 1 GW in the near term and 10 GW over the next decade, according to a White House fact sheet.
The trio of initiatives is aimed at tripling current domestic solar panel manufacturing capacity from 7.5 GW to 22.5 GW by 2025, while also alleviating the negative impacts of the Commerce investigation.
Statements from administration officials pointed to the economic and national security impacts of Biden’s actions.
“In conflict, fossil fuel supply lines are especially vulnerable,” Deputy Secretary of Defense Kathleen Hicks said. The initiatives announced Monday “will help strengthen our supply chains and ensure that the United States is a leader in producing the energy technologies that are essential to our future success. They will also help accelerate DoD’s transition toward clean energy technologies that can help strengthen military capability while creating good jobs for American workers.”
Echoing Hicks, Energy Secretary Jennifer Granholm said the DPA will “help strengthen domestic solar, heat pump and grid manufacturing industries while fortifying America’s economic security and creating good-paying jobs, and lowering utility costs along the way.”
Solar supply chains were a secondary concern for Jim Matheson, CEO of the National Rural Electric Cooperative Association (NRECA), who instead zeroed in on the DPA’s potential impact on the transformer supply chain and electric system reliability.
“Shortages of transformers pose a risk to normal electric grid operations as well as recovery efforts for systems disrupted by a natural disaster,” Matheson said. “The Biden administration’s use of the Defense Production Act to shorten lead times for supplies of electric transformers is a much needed step to support reliability and resilience, and NRECA urges inclusion of all stakeholders in the implementation process.”
‘Get Stuff Built’
A major point of uncertainty for solar industry advocates and analysts is whether the president’s actions will provide the momentum needed to quickly re-open overseas supply chains and accelerate the buildout of a domestic supply chain.
Noting that American demand for solar panels hit 20 GW in 2021, Roselund said, “There’s this huge imbalance between what U.S. factories can supply, even running at full capacity, and what the market demands.”
The waivers will provide a short-term solution for developers, said Mike Kruger, CEO of the Colorado Solar and Storage Association. Two years may not be “sufficient time to get domestic manufacturing pumping out panels,” he said. “But it certainly gives folks a pretty clear signal that they’ve got some runway to get stuff built.”
Kruger and other solar advocates see solar and manufacturing tax credits and other incentives tied up in Congress as critical for the long term. In her statement, Hopper called for passage of the Solar Energy Manufacturing for America Act, which would provide incentives for a range of domestically manufactured solar components, including panels, trackers and inverters.
Roselund also sees the DPA as a short-term solution to a structural challenge for U.S. solar manufacturing ― its higher production costs compared to overseas competitors.
“If the goal is to make everything domestically then you need some way to compensate for the fact that it’s more expensive to manufacture in the United States,” he said. “The most direct way to do that is subsidies.”
Should tariffs cut off imports from the Southeast Asian countries as well as China, he said, manufacturing will go “somewhere else that is less expensive. The likely outcome if we don’t pass some sort of incentives to compensate for the cost difference is that more of utility-scale product gets supplied from places like India and Turkey.”
FERC expanded its series of orders directing refunds for premiums earned in the Western heat wave of August 2020 by telling ConocoPhillips (NYSE:COP) and Direct Energy on Friday to return excess money they made on sales in scarcity conditions.
In Direct Energy’s case, FERC said the Houston-based energy retailer had failed to justify 25 MW in sales to Macquarie Energy for $1,500 MW/h, higher than the average index price of $1,333 MW/h at the Mead Hub in southern Nevada on Aug. 18, 2020 (ER21-64).
“We find that Direct Energy has not provided adequate justification for the amount charged above the index price, and, therefore, we direct Direct Energy to refund amounts charged above the average index price for the sale at issue within 30 days of the date of this order,” FERC wrote.
In ConocoPhillips’ case, the company had justified its August 2020 sales at its “cost of energy purchased, but it has not justified the amounts charged above [that cost],” FERC said (ER21-40).
ConocoPhillips contended two sales to Arizona’s Salt River Project on Aug. 17-18 were sleeve transactions it facilitated between a third-party seller and the utility. ConocoPhillips charged far more than it paid for the energy, which it said reflected operational costs and the heightened risks from record heat, wildfires, transmission outages and the potential for nonperformance by the parties at the time.
SRP argued the sales were not sleeve transactions under FERC’s definition, in which “an entity acts as an intermediary counterparty to accomplish a sale between two other counterparties who may not be set up to transact with each other using common enabling agreements (such as the Western Systems Power Pool (WSPP) or Edison Electric Institute agreements) or who may not meet credit requirements.”
The utility said the parties were members of WSPP that could use its common enabling agreement, and it pointed out that it had a credit rating of AA+ from S&P Global Ratings when the transactions occurred.
Even if the sales were sleeve transactions, the fees ConocoPhillips charged were far more than the “nominal” add-ons allowed by FERC in such cases, SRP said.
“According to Salt River, ConocoPhillips cannot credibly report to the commission that these transactions were sleeve transactions with nominal fees, nor attest reasonably to the commission that the amount it charged above cost, which is vastly higher than a nominal fee, should apply to its transactions during August of 2020 due to heightened risks,” FERC wrote.
The commission agreed.
“While the record in this proceeding indicates that ConocoPhillips acted as an intermediary in obtaining energy Salt River sought to purchase and then selling that energy to Salt River, [our previous guidance on sleeve transactions] was specific in its description of the circumstances in which a transaction involving an intermediary qualifies as a sleeve transaction, and ConocoPhillips has not demonstrated that those circumstances are present here,” FERC said.
“Specifically, ConocoPhillips has not demonstrated that it collected only a nominal fee in acting as an intermediary counterparty to accomplish a sale between two other counterparties,” it said.
So far, the commission has decided 10 of the cases, ordering refunds in all. It also has denied motions by some of the parties to raise WECC’s soft price cap to $2,000/MWh, the same as CAISO’s, saying the matter was beyond the scope of the proceedings.
Commissioner James Danly has dissented in each case, saying FERC lacks the legal authority to interfere in contracts between willing buyers and sellers that do not harm the public interest.
