WASHINGTON — The Department of Energy asked Tuesday for comment on how it should implement the “anchor tenant” and $2.5 billion revolving loan programs for transmission authorized by the bipartisan Infrastructure Investment and Jobs Act.
DOE’s Transmission Facilitation Program (TFP) is intended to aid the construction of grid infrastructure that improves reliability and resilience or increases interregional transfers. DOE said such expansions also would increase the availability of lower-cost and low-carbon electricity sources, furthering the Biden administration’s goal of a carbon-free electric grid by 2035 and a net zero emissions economy by 2050.
Avi Zevin, DOE’s deputy general counsel for energy policy, announced the notice of intent (NOI) and request for information (RFI) on the TFP at the Energy Bar Association’s annual meeting in D.C. Responses will be due 30 days after publication of the NOI/RFI in the Federal Register.
“It is critical that the infrastructure that we develop with money and authority from the law is used to address climate change by reducing greenhouse gas emissions,” Zevin said. “As the Secretary [Jennifer Granholm] has said many times, the climate crisis is real. Our hair needs to be on fire. [We need] to deploy, deploy, deploy clean energy in order to address it.”
The TFP allows DOE to offer three types of support:
Capacity Contracts: DOE can purchase up to 50% of the proposed transmission capacity of an eligible transmission line for up to 40 years.
Loans: DOE may make loans for the costs of carrying out an eligible project — new lines of at least 1,000 MW, (500 MW for projects in an existing transmission corridor) or connections of an isolated microgrid to existing transmission in Alaska, Hawaii or U.S. territories.
Public-Private Partnerships: DOE can participate in designing, developing, constructing, operating, maintaining or owning an eligible project that is in a national interest electric transmission corridor or necessary to accommodate an actual or projected increase in demand for transmission across more than one state or transmission planning region.
DOE asked for feedback on the application process, criteria for qualification and selection of projects under the TFP.
DOE is authorized to borrow up to $2.5 billion from the Treasury at any one time. The loan receipts and revenue from capacity contracts will be put in a fund to support the TFP.
DOE funding for transmission under bipartisan Infrastructure Investment and Jobs Act. | Department of Energy
Zevin said “$2.5 billion, as everyone in this room knows, is not a huge amount of money for large-scale transmission development. So, one of the critical items that we are thinking about, and we would love your input on, is mechanisms that we can use to leverage that money to drive additional deployment from the private sector.”
Funding applications will be accepted after DOE issues an initial solicitation for proposals. If DOE approves a capacity contract, it expects to issue its first solicitation in 2022 and a second in early 2023.
The first solicitation will be limited to projects that would begin commercial operation by the end of 2027. In the second solicitation, DOE will consider all forms of support under the TFP.
DOE will require applicants to show that the eligible project is unlikely to be constructed as quickly or with as much capacity without the department’s help. Applicants also must show that the project has a realistic chance of being constructed and going into commercial operation.
DOE is seeking specific feedback on whether it should conduct separate solicitations or request applications under a single solicitation that remains open for a rolling review and determination.
It also requested feedback on how it should consider the impact of proposed projects on reliability and resilience and reducing GHGs or generating host community benefits.
David Getts, general manager of SouthWestern Power Group, told the EBA conference the TFP is “potentially quite helpful” to transmission developers although too late to help his company’s efforts on the SunZia transmission project to deliver New Mexico wind power to the Palo Verde hub in Arizona.
“I think the single most beneficial aspect of the TFP will be the capacity contract, or the ability of DOE to enter into an anchor tenant relationship,” Getts said. “That potentially is a game changer” addressing the “chicken-egg” difficulty of signing customers to a line before it is built.
“You can’t find a customer — i.e., a private sector company that wants to use your line or [buy] energy from the generation project that depends on your line — until you have all your permits,” he said. “People say you’re not real; you’re never gonna happen.”
Getts had some questions of his own. “If DoD is an anchor tenant, that’s great, but you’ve got to have another anchor tenant — you might need that to get financed,” he continued. “What’s that interaction like between the anchor tenants? Are they competing for end-use customers? How does the governance work?”
The Vermont House of Representatives on Tuesday sustained Gov. Phil Scott’s veto of a clean heat standard (CHS) bill, missing the necessary two-thirds majority to achieve an override by one vote.
Scott expressed concern in a veto letter Friday that the “costs and impacts” of the bill (H.715) are “unknown.”
“I have clearly, repeatedly and respectfully asked the legislature to include language that would require the policy and costs to come back to the General Assembly in bill form so it could be transparently debated with all the details before any potential burden is imposed,” he said.
Speaking on the House floor Tuesday, Rep. Timothy Briglin (D) said he was “confused by the governor’s veto message” because the bill “clearly states” that legislators must pass a new bill on the final CHS rules for the governor’s consideration.
On May 3, the House approved a Senate amendment to H.715 that included language requiring the Public Utility Commission to return proposed CHS rules to the legislature before adopting them.
Scott, however, said the amendment is an “inadequate ‘check back.’”
A CHS was one of the major greenhouse gas emission reducing policies in the Vermont Climate Council’s initial Climate Action Plan released in December.
“This [standard] was by far the single largest emissions reduction policy recommendation in the Climate Action Plan designed to deliver a full third of the emissions reductions required by 2030 [in the 2020 Global Warming Solutions Act (GWSA)],” said climate council member Jared Duval during a council subcommittee hearing on Thursday. Duval is the executive director of the Energy Action Network.
The GWSA directs the council to develop a state plan to reduce GHG emissions 80% below 1990 levels by 2050, with interim targets for a 26% reduction from 2005 levels by 2025 and 40% below 1990 levels by 2030.
Council members are working this year to make up for a significant gap that already exists in the emission reductions that the climate plan’s strategies need to achieve.
The council was poised last fall to recommend the Transportation and Climate Initiative Program in the action plan when Connecticut, Rhode Island and Massachusetts pulled their support for the program. Loss of the multistate cap-and-invest initiative left the council with a 26% gap in emission reductions for the transportation sector needed by 2030.
Without the CHS, Duval said the council’s legal responsibility regarding GHG emissions policy planning is on “really uncertain ground.” The standard is designed to meet the thermal sector’s share of state emission reductions, which is 34% of the needed total, according to the climate plan.
The next largest emission reducing strategy in the initial climate plan is adoption of California’s Advanced Clean Cars II regulation, which Duval said could deliver a 10% reduction for the state.
In the absence of policies passed by the legislature and governor, the Vermont Agency of Natural Resources (ANR), by the end of this year, must adopt and implement rules consistent with the climate plan to achieve the GWSA’s 2025 emissions target. ANR also must adopt rules by 2026 and 2040 to achieve the state’s 2030 and 2050 targets, respectively, should state laws not provide a pathway for those targets.
The GWSA allows any person to sue the ANR secretary if sufficient rules are not adopted as required by law or if adopted rules fail to achieve target reductions.
In a statement Monday, climate advocates said Scott’s veto “disregards” the work put into designing an equitable transformation of the state’s thermal sector, 74% of which is fossil fuel-based.
“With millions of dollars in fossil fuel spending flowing out of our economy each year and oil and gas prices more volatile than ever, the Scott administration’s decision to veto this landmark climate bill represents a major environmental and economic misstep,” said Jordan Giaconia, public policy manager at Vermont Businesses for Social Responsibility.
The General Assembly is set to adjourn May 17, leaving a short window of opportunity for legislators to bring forward bill language that could satisfy Scott’s interest in robust oversight of CHS rulemaking.
ISO-NE is proposing a change in how often it recalculates key parameters of its capacity auction.
At the NEPOOL Markets Committee meeting Tuesday, Deborah Cooke, an analyst at the grid operator, laid out changes that ISO-NE wants to make to calculating the cost of new entry (CONE), net CONE and the performance payment rate in a rapidly changing market.
Currently, ISO-NE’s tariff requires triennial recalculation of CONE and net CONE, with the next recalculation scheduled for FCA 19 in 2025.
ISO-NE wants to push that back to FCA 21, two years later, to account for proposed market changes that are in the works, including new resource capacity accreditation rules and day-ahead ancillary services. Those projects could clash with the recalculation if they’re ongoing at the same time, the RTO says.
It’s also calling for changing the update frequency from every three years to every four, which would provide “less variability and more certainty,” Cooke said.
New England’s neighboring regions NYISO and PJM update their calculations every four years, and doing it less often would let ISO-NE allocate resources to other projects, Cooke added.
The committee will discuss the proposal over the next few months, aiming for a vote in June and Participants Committee approval in August.
A New Look at CSF
ISO-NE is also moving forward with a plan to try to improve the continuous storage facility (CSF) model to accommodate storage projects that inject energy into the grid but don’t consume it.
The CSF model was launched in 2019 as an update to rules that were written with pumped storage in mind, and a way to let modern storage technology participate more broadly in the markets. It also gives ISO-NE more visibility and dispatch control over the resources.
“The CSF rules currently limit participation to resources that are capable of consuming energy from and injecting energy into the ISO-administered bulk electric system,” ISO-NE technical manager Doug Smith said in a presentation at Tuesday’s meeting.
Some new projects consisting of storage plus intermittent generation are not capable of consuming energy from the grid because they have to charge their storage from the generation connected on-site. The proposed tariff changes would allow those projects to register and operate as a CSF. ISO-NE is aiming to bring the proposal through the NEPOOL stakeholder process by this summer and have them in effect by November.
Cyber Reporting
The MC agreed on recommending tariff changes that would meet mandatory reporting requirements for cybersecurity incidents and events set by NERC and the U.S. Department of Energy. The language would also modify confidentiality restrictions to enable ISO-NE to report cybersecurity incidents and events to NERC, DOE and the Department of Homeland Security.
The new policy would let ISO-NE submit confidential information to those agencies in the event of a cybersecurity incident without consent or prior notice to the involved participants.
#2 – humanity isn’t going to cut carbon emissions enough to contain it.
Most people agree on #1 so let’s focus on #2. There are many reasons for #2, first and foremost it’s the ultimate “free rider,” aka “tragedy of the commons,” aka “negative externality” problem. It boils down to this: Each nation incurring costs to reduce its carbon emissions gets some small percentage of the overall benefit to humanity from doing so. So each nation’s cost to its citizens and to its economy is relatively high, and its share of benefit is relatively low.
Given we haven’t solved this problem within nations, like our states where 60% of emissions come from states without climate goals,[1] it’s naïve to think we can solve this problem among nations. For all the happy talk at international conferences like COP26, nations are going to continue to pursue their national interests.
Global Reality Check
Asia now represents 74% of world coal electric generation, and it’s increasing there with no end in sight.[2] Asia is planning 600 new coal plants.[3]
And consider the developing world where people face personal existential crises every day — do we ask them to forgo fossil fuels that have been, and remain, critical to emerging from poverty?[4] Developing nations face many crises, not just climate change, as Daniel Yergin and others point out.[5]
There are strategic resource limitations as well. Current production of strategic minerals for batteries to back up intermittent resources, and to electrify transportation, is a pittance of what is needed, and these minerals tend to be located in problematic nations.[6]
And we haven’t untangled the importance of fossil fuels in agriculture (fertilizer), and in plastics, among other essentials of modern life.[7] Did I mention the insane closure of nuclear plants?[8]
And lest we forget, aggressive carbon emission goals by a given nation are a chimera if the consequence is the departure of energy-intensive industries to less-committed nations.[9]
What is the biggest sobering item from the latest Intergovernmental Panel on Climate Change (IPCC) report released April 4? My nomination is: “The report says that to avoid more than 1.5 degrees C of warming, global emissions must peak before 2025 and then fall by 43% before 2030, compared with 2019 levels.”[10]
Not happening.
On the Home Front
The American people aren’t going to stand for big electricity cost increases, degradation of electric reliability or NIMBY siting issues. We already are seeing pushback on electric rate increases in California.[11] We were reminded by Texas last year that the populace will not tolerate outages. And we have huge NIMBY siting issues, not just for large transmission projects,[12] but also for large wind and solar projects.[13]
Not to mention our “own goals,” like the solar panel antidumping investigation.[14] And the new NEPA rules,[15] exacerbating the existing ones,[16] which will sabotage many more renewable projects than fossil fuel projects.[17]
Lord, help us. Because we can’t help ourselves.
The Coffee
So where are we? We need to wake up and smell the coffee: Plan A ain’t happening.
We need a Plan B: Solar geoengineering. This is adding particles, like calcium carbonate (think white sands of Hawaii), to the stratosphere that would reflect more sunlight and thus reduce global warming. It wouldn’t take much extra reflection, as the IPCC stated in last month’s report: “Simple calculations and climate modelling studies show that about 2% extra solar irradiance reflected away from Earth … would suffice to offset global mean warming from a doubling of the CO2 concentration.”[18] Doubling is much less than the actual increase in CO2 concentration from the pre-industrial period to now.[19]
Bottom line according to the IPCC? “Modelling studies suggest that it is conceptually possible to achieve multiple climate policy goals by optimally designed SRM [geoengineering] strategies.”[20]
Last year a blue-ribbon committee of the National Academies of Sciences, Engineering and Medicine recommended that the U.S. spend about $100 million to $200 million researching this over the next five years.[21] If you look at only one of the footnoted materials for this column, please make it this National Academies report.
The reaction in some quarters has been outrage. The most organized opposition is from those who oppose even research, making three main arguments: (1) the risks are poorly understood and can never be fully known; (2) Plan B would delay/discourage Plan A (“moral hazard”); and (3) the “global governance system” is unfit to develop and implement the necessary agreements for deployment.[22]
Let’s take these up. Regarding objection #1, the uncertainty of the risks, that’s of course a reason to do research. This just in, we humans have been meddling with Earth for about 150,000 years without understanding the risks, much less fully understanding the risks. And could the risks of geoengineering be bigger than climate catastrophe?
Regarding objection #2, the moral hazard argument, this is akin to opposing adaptations to climate change (e.g., seawalls) because their sheer existence reduces the urgency of cutting carbon emissions. Or opposing seat belts because people drive faster. Or opposing COVID vaccine research because it would discourage mask wearing. And, again, we need to recognize that nations’ individual decisions are not going to be determined by whether geoengineering might or might not work.
Regarding objection #3, the alleged unfitness of the “global governance system” to deploy geoengineering, this begs the question doesn’t it? If nations can’t get it together for geoengineering at a cost of $250 billion to $2.5 trillion through 2100 (depending on the scenario chosen),[23] how on Earth could these same nations get it together to transform virtually everything at a ballpark cost of $275 trillion through 2050?[24]
Those who support research on geoengineering acknowledge that maybe we’re just buying needed time for technology, mitigation and adaptation to catch up.[25] Or maybe it’s a permanent offset to carbon emissions that can be managed effectively. Nobody knows.
Instead, some environmentalists went into overdrive to stop — not just geoengineering itself — but any research into it.
What About a Plan C?
There is no realistic Plan C. As The Atlantic just said: We have two impossible paths to avoid the worst of climate change.[26]
The Atlantic identifies two impossible paths: (1) a collapse in global energy usage, and (2) massive carbon removal from the atmosphere. Regarding energy usage reduction, it gives an example with vehicles where instead of world-wide vehicles increasing from 1.3 billion now to 2.2 billion by 2050, they would actually decline to 0.85 billion by 2050. Not a chance.
As for carbon removal from the atmosphere, the cost is huge, 6X to 20X the social cost of carbon, comparing the technology’s cost estimate range of $300 to $600/metric ton,[27] with the Biden Administration’s social cost of carbon of $51/metric ton.[28] The IPCC estimates in one scenario that 6 billion tons would need to be removed from the atmosphere every year to 2050 to meet the 1.5 degree goal,[29] so that translates into $67.5 trillion. If the newly announced Frontier initiative were successful in reducing the cost to $100/ton,[30] it would still take $15 trillion. Nations could pass the hat for that $67.5 trillion, or $15 trillion, but the track record for raising even relatively tiny sums is pathetic.[31]
What about new nuclear? Lazard says new nuclear has a capital cost midpoint of $10.3MM/MW and a levelized energy cost of $167/MWh,[32] more than 3X the social cost of carbon. Vogtle in Georgia is a slow-motion train wreck I wrote about five years ago.[33]
But perhaps smaller, “modular” nuclear? To take an example, TerraPower says its first Natrium 345-MW reactor will cost $4 billion — with taxpayers on the hook for half of that.[34] By the way, $100 billion has been spent over six decades on this “advanced” sodium-cooled nuclear technology, to generate roughly 0 MWh (sodium does not play well with water or air).[35] And the project is now in limbo because the only existing source for the specific nuclear fuel is Russia.[36]
Hope Is Not a Plan
Is it better to bury our heads in the sand instead of getting some answers? To condemn humanity to a global threat by ruling out even research on a Plan B?
“We all have to take a chance. Especially if one is all you have.” Capt. James T. Kirk, Tomorrow Is Yesterday, 1967.
[8] I wrote before February 24: “The Germans are shutting down the rest of their nuclear plants so they can be more dependent on Putin’s natural gas. An even worse sin than California’s and New York’s closures of the Diablo Canyon and Indian Point nuclear plants (which I railed against years ago).”
[9] The “good” nations theoretically could tax via tariff their imports from “bad” nations in an effort to rebalance the economic incentives, but will they?
August-like weather that one weatherman called “categorically insane” has settled over Texas, leading to ERCOT calling on generators to postpone planned outages or return to service in advance of the heat.
Peak demand hit 70.6 GW late Monday afternoon, breaking Sunday’s short-lived record of 67.5 GW, as well as the previous peak demand mark for June. The previous high for May was set in 2018.
ERCOT’s all-time record for peak demand is 74.8 GW, set in August 2019. The Texas grid operator said last week that it expected to have sufficient generation to meet the above-normal demand from “unseasonably” hot weather.
The problem is that about 15 to 20 GW of thermal generation, approximately a third of the fleet, has been offline in recent days during what is normally maintenance outage season. Generators have until May 15 to complete their outages. Renewables have helped pick up the slack, providing nearly 30 GW of energy, or close to 45% of total generation.
ERCOT said in an emailed statement that it is “coordinating closely” with the Public Utility Commission, generation owners and transmission utilities to ensure “they are prepared for the extreme heat.”
“ERCOT will deploy all the tools available to us to manage the grid reliably,” a spokesperson said. “At this time, ERCOT projects there will be sufficient generation to meet this high demand for electricity.”
As demand approached another record peak for May on Monday, ERCOT had plenty of capacity in reserve. | ERCOT
The grid operator on May 3 issued an operating condition notice (OCN), its lowest-level communication in anticipation of a possible emergency condition. On Friday, ERCOT extended the OCN until Thursday because of forecasted temperatures above 94 degrees Fahrenheit in its North Central and South Central zones.
The National Weather Service said heat and humidity will result in heat indexes in the low 100s in the Houston area. Highs in the state are expected to stay in the 90s through the rest of the week.
Prices briefly hit $2,183 in the Houston area early Monday afternoon. At the same time, prices were as low as -$849 in nearby Calhoun County, where renewable generation was trapped behind transmission constraints.
ERCOT and the PUC have yet to issue press releases or use social media to urge conservation or warn about the unseasonable heat; nor has Texas Gov. Greg Abbott, who continues to focus his Twitter account on Operation Lone Star, his costly effort that he says is securing the southern border with Mexico.
However, the Texas Division of Energy Management tweeted about the excessive heat, urging Texans to “spend time in air conditioning.”
Stoic Energy President Doug Lewin attributed the high demand to a combination of extreme heat, poor energy efficiency and population growth: Texas’ 15.9% population growth rate between 2010 and 2020 was more than double the U.S.’ and will help the state hit 30 million residents this year, according to the U.S. Census Bureau.
“Texas gets 80% less energy reduction from efficiency than the ‘average’ state,” Lewin said. “This particularly hurts us in extreme temperatures.”
SAN DIEGO — The West’s potential to regionalize transmission planning and participate in organized markets occupied much of the discussion at the three-day meeting of the Committee on Regional Electric Power Cooperation and the Western Interconnection Regional Advisory Body (CREPC-WIRAB) in San Diego last week.
A prime topic was FERC’s recent Notice of Proposed Rulemaking (NOPR) on transmission, which, if adopted, would require long-term regional transmission planning and increased state involvement in transmission cost allocation, among many other changes.
Western utility commissioners also discussed the work of the Joint Federal-State Task Force on Electric Transmission, convened by FERC and the National Association of Regulatory Utility Commissioners (NARUC) to spur transmission development as a means to deliver renewable power, reduce congestion and improve reliability. (The task force met virtually on Friday to discuss challenges related to clogged generator interconnection queues and cost allocation for transmission network upgrades.) (See FERC-State Task Force Considers Clustering and ‘Fast Track’ to Clear Queues and Task Force Seeks ‘Right Balance’ in Spreading Tx Upgrade Costs.)
Utah Public Service Commission Chair Thad LeVar told the audience of state regulators and others that two questions guide his work on the task force.
“The first question is, ‘Will any specific proposal or rulemaking either encourage or chill development of regional transmission coordination in the West?’” LeVar said. The second question is whether any proposal will fail to “respect and recognize the diverse carbon policies” of Western states, he said.
“To me, those are the two most important things because everybody agrees we need to move toward more regional transmission coordination … but we need to do that in a way that respects and recognizes” state policies, he said.
Those policies range from California’s drive to supply retail customers with 100% clean energy by 2045 to the plans of states of the interior West to continue relying on a mix of renewable energy and fossil fuels for the foreseeable future.
The uneasy relationship between more progressive and more conservative states in the West is likely to remain a sticking point to greater grid integration, stakeholders at the meeting said.
Even so, “there’s a lot of momentum toward regional coordination,” LeVar said.
Moves Toward Western Markets
The push toward Western coordination now extends to a major resource planning program and the possibility of participation in organized markets.
The Western Power Pool’s Western Resource Adequacy Program (WRAP), which WPP President Sarah Edmonds described in a presentation, is poised to be a West-wide effort to ensure reliable energy supply as coal plants retire and weather-dependent wind and solar resources proliferate during a time of climate change and extreme weather events. (See Western Power Pool Names New CEO.)
“This planning framework establishes a common planning reserve margin for the entire footprint … and it arrives at common counting rules across the entire footprint for the resources that we use,” Edmonds said on the meeting’s first day, May 2.
“The region has never had a West-wide view of what it needs to meet the needs of the future and how to count resources consistently across the footprint,” she said. “There’s a real value proposition in what we can do when we work together and … [leverage] our community as a whole.”
The WRAP, scheduled to enter a nonbinding phase later this year, has attracted participants in an area that stretches from British Columbia to Arizona and east to South Dakota. Stage 1 of the WRAP will include 26 participants that together represent a summer peak load of about 67,000 MW and a winter peak of more than 65,000 MW.
CAISO’s Western Energy Imbalance Market (WEIM), an interstate real-time trading platform, recently surpassed $2 billion in cumulative benefits for its participants since its founding in 2014. The WEIM has 17 members and is expected to grow to 22 participants by 2023, its benefits keeping pace with participation. (See Western EIM Tops $2B in Benefits.)
The ISO issued a straw proposal April 28 to add an extended day-ahead market (EDAM) to WEIM’s real-time market, potentially attracting even more of the Western market to its regional offerings. (See CAISO Issues EDAM Straw Proposal for the West.)
In addition, several Western entities have joined SPP’s Western Energy Imbalance Service and could eventually become members of SPP’s planned RTO West or its Markets+ program, which offers an array of RTO-like services but stops short of a full RTO.
A panel of stakeholders discussed the challenges of day-ahead market design on day two of the CREPC-WIRAB meeting.
“When you think about how unique a day-ahead market will be, especially in the West — where we have different [open access transmission tariffs] that we have to deal with, with regards to transmission utilization in the market, as well as potentially different resource adequacy programs — we have to think about how we create equity with those different constructs, and so that’ll be important as these designs continue to evolve,” Scott Kinney, director of power supply with Avista Corp., said.
Avista, based in Spokane, Wash., is a new participant in the WEIM and recently signed a letter with 14 other Western utilities saying it plans to support SPP’s efforts to develop a regional day-ahead energy market to evaluate against CAISO’s proposed day-ahead market. (See Western Utilities to Support SPP Market Development.)
A day-ahead market is “something that I think we should pursue as a region, but there’s no crisis behind it,” Kinney said. “So, let’s take the time to make sure that we fully flesh out all the options that are in front of us from a day-ahead market construct so that we can compare them equitably and make sure that they’re providing benefits to our customers.”
In the past year, FERC commissioners have urged the formation of one or more RTOs in the West, which remains balkanized with 38 separate balancing authority areas, while much of the rest of the nation is organized into RTOs or ISOs. (See Glick Says West Should ‘Finish the Job’ on RTO.)
In all the regionalization efforts, “the one area that hasn’t been tackled is transmission operation, transmission planning and transmission cost allocation,” LeVar said. The joint task force is intended to further regional transmission cooperation, he said.
FERC Transmission NOPR
FERC’s transmission NOPR (RM21-17) is separate from the work of the task force but shares its aims.
In one of its more controversial provisions, however, the NOPR would retreat from Order 1000’s effort to open transmission development to competition by giving incumbent transmission owners a federal right of first refusal (ROFR) on regional projects, provided they partner with an unaffiliated company with a “meaningful level of participation and investment” in the project.
The commission found in Order 1000 that federal ROFRs create “a barrier to entry,” discouraging nonincumbent transmission developers from proposing alternative solutions that could be more efficient or cost-effective. But the commission said it was changing course in its April 21 NOPR because it feared that Order 1000’s removal of the federal ROFR may be “inadvertently discouraging investment” in regional transmission.
Incumbent transmission providers “may be presented with perverse investment incentives” to instead engineer local transmission projects for which they retain development control, FERC said.
The NOPR troubles independent transmission developers.
Sharon Segner, senior vice president for transmission policy at developer LS Power, said the NOPR raised concerns about transmission competition in the Western Interconnection. She spoke as part of a panel on barriers to transmission development in the West, which largely focused on the NOPR’s pros and cons.
“As we look at the NOPR from a Western perspective, the first question that has to be asked is, ‘Does the rule usher in a cost-effective, clean energy transition?’” she said. “And while there are certainly areas of progress from a Western standpoint, in my company’s view we certainly see some yellow lights and red lights in terms of the proposals.”
Among the problems is that the NOPR “took meaningful steps backward on the notion of transmission competition across the country,” Segner said. “It’s a proposal that my company will rigorously object to.”
The proposal runs counter to President Biden’s July 2021 executive order aimed at promoting competition in the American economy,” she said. The order names FERC as a federal entity responsible for administering statutes protecting fair competition.
If an incumbent transmission provider has a partner, “then the competitive process could go away,” Segner said. “Having a partner in a transmission line does not necessarily mean that the consumers will have lower rates, and that doesn’t provide the benefits of a competitive process.”
“We don’t believe that FERC can substitute competition for cartels, and that’s essentially what we believe the end result of FERC’s proposal is — that if the transmission owner finds one partner then they have the ability to shut out competitive pressures and have the ability to stop competition,” she said.
Some panelists and audience members supported FERC’s goal of enhancing regional transmission planning to incorporate renewable resources.
“I was very pleased to see it,” Rob Gramlich, president of consulting firm Grid Strategies said.
An “open, transparent regional planning process,” will be more likely to get transmission built, Gramlich said. The NOPR could require planners to proactively examine the future resource mix and take a more holistic approach to balancing costs and benefits, he said.
Fred Heutte, senior policy associate with the Northwest Energy Coalition, said the co-optimization of new generation and transmission, rare in the West, is “implicit in where the NOPR is going.”
Gramlich agreed “that co-optimization is extremely important for consumers to save on generation costs and [to see an] overall delivered cost of generation plus transmission.”
A big question, he said, is who will coordinate those activities.
“I think the NOPR, first of all, requires a mindset shift” in the West toward regional generation and transmission planning, more like processes followed by Eastern RTOs and ISOs, Gramlich said.
“You can clearly envision a role for WECC and for [regional planners] WestConnect and Northern Tier [Transmission Group] and CAISO,” Gramlich said.
In January, CAISO published a first-of-its-kind 20-year transmission outlook intended to promote regional efforts to move renewable energy across the West. (See CAISO Sees $30B Need for Tx Development.)
“I don’t know exactly where the boundaries should fall, but I think that somebody needs to proactively [coordinate transmission planning], and I agree with Sharon [Segner] that, to some extent, this shouldn’t just be utility driven,” he said.
“I think there’s a lot of deference to just sort of taking what the individual utilities put together in this region … rather than an actual ‘let’s take the data and come up with an optimal configuration and then work with policymakers on an acceptable regional plan,’ Gramlich said. “I’d love to see a shift toward that latter framework.”
As Russian tanks and infantry massed on the border with Ukraine last year, U.S. government officials began reaching out to owners and operators of the nation’s critical infrastructure, including the electric grid.
Russia’s willingness to wage electronic warfare was well known, and any attack on Ukraine was sure to be accompanied by a cyber offensive that could easily spill across the borders and affect the country’s allies.
While nobody could be sure just what cyber capabilities Russia’s military had in reserve, the government’s hackers had attacked Ukraine’s power grid on multiple occasions; doing the same to the U.S. could cripple Russia’s strongest rival. Manny Cancel, CEO of the Electricity Information Sharing and Analysis Center (E-ISAC), told ERO Insider it took little effort for everyone to realize the shared vulnerability.
Manny Cancel, NERC | NERC
“One of the guiding principles that we all agreed to was sort of lowering the barrier for information-sharing on both sides of the fence, that the government needed to share information, and maybe declassify intelligence, as quickly as they could,” Cancel said. “And vice versa — it’s very important for the utility industry or the energy sector to share information back with the government to provide context [and] situational awareness.”
The result has been what Cancel called an “unprecedented level of engagement” between the government and private sector, both in the U.S. and Canada. Through both classified and unclassified briefings, as well as online alerts, public officials have made regular sharing of threat data a staple of the Cybersecurity and Infrastructure Security Agency’s Shields Up program; the E-ISAC has done its part by holding regular webinars open to the entire electric industry, not just its own members.
Cancel said a top priority has been including other critical infrastructure sectors, such as the telecommunications, finance and natural gas industries. This way all participants can benefit from each other’s work.
“The electricity sector has been operating with shields up for probably a decade — I can’t think of a day when we didn’t,” Cancel said. “But I still think the guidance was very relevant, just to sensitize people that this is really serious. We’ve got to up our game from a vigilance perspective [and] from an information-sharing perspective because that’s the only way we’re going to be able to protect and respond to a potential attack on critical infrastructure here in the United States.”
The response has also expanded beyond the U.S. and Canada, with officials in Europe reaching out to their counterparts in North America to discuss how to build a united front to the fighting in Ukraine. Cancel mentioned that NERC, the E-ISAC, and the U.S. Energy Association have had conversations with European regulators about their biannual GridEx security exercise, and how similar events could be staged in their countries.
However, he emphasized that while the E-ISAC actively works with European partners in “a number of forums,” U.S. officials are mindful that their role is collaborative rather than leading, and that every nation has its own challenges to deal with.
“There’s always an opportunity to share, not only … threat intelligence and information, but [also] risk mitigation activities and best practices,” Cancel said. “We do demonstrate a leadership role, but … our colleagues overseas … have some very robust risk mitigation programs and cyber programs.”
While Cancel praised the performance of the nation’s frontline cybersecurity defenders, he warned that utilities cannot let themselves become complacent. The current geopolitical tensions may have inspired the industry to its best efforts, but leaders must ensure their focus remains on proactive defense against any potential threats rather than returning to a compliance mentality.
“The minute you talk about standards, people generally — and I did this myself when I was at a utility — talk about, what do I need [in order] to comply, and what happens when I don’t comply?” Cancel said. “That conversation needs to change. I’m not saying you throw the compliance angle, [but] how can … industry and regulatory entities like NERC and FERC, and the rest of the federal government work to … better protect things.”
Higher operating costs tied to an increase in winter storms drove down Duke Energy’s first-quarter earnings despite an uptick in revenues from increased demand for both power and natural gas.
Duke on Monday reported first-quarter earnings of $1.08/share compared with first-quarter 2021 earnings of $1.25/share. Total revenues for the quarter were $7.1 billion, a 16% increase from $6.1 billion in the first three months of 2021.
The cost of coal ash cleanup in Indiana cost the company about $250 million. Severe winter storms in the Carolinas were the primary expense drivers. The storms alone reduced earnings per share by 7 cents, the company said.
Duke fielded crews of nearly 19,000 employees to restore power to more than 1 million customers after a series of winter storms, the highest number in eight years, swept through the region.
Duke Energy CEO Lynn Good | Duke Energy
CEO Lynn Good said despite the increase in expenses for storm restoration operations in the first quarter, the company is reaffirming its full-year earnings guidance range of $5.30 to $5.60/share, with a midpoint of $5.45.
“We’re also reaffirming our long-term EPS growth rate of 5 to 7% through 2026, at the midpoint of our original 2021 guidance range,” Good told analysts at the start of the company’s earnings call. “We’re monitoring economic trends and will take action if necessary as we continue to execute the important strategic work we have underway in the Carolinas, Indiana and Florida.”
Good said the company will file its long-term carbon-reduction emissions plan with the North Carolina Utilities Commission on May 16.
The plan, in accordance with legislation (H.B. 951) passed a year ago, will lay out how Duke will lower carbon emissions by 70% by 2030 compared to 2005 levels and achieve net-zero emissions by 2050. Once approved, the plan must be updated every two years.
“The plan will outline multiple portfolios to achieve the 70% carbon-reduction target, including proposals around timing of coal plant retirements and resource additions,” Good said.
“We expect substantial solar and battery additions, demand-side management and energy efficiency opportunities in every pathway. Onshore and offshore wind will be presented for consideration, as well as small modular nuclear reactors. Each portfolio has been rigorously tested for reliability and affordability for our customers.”
The company is planning to file a rate case in North Carolina, as permitted by H.B. 951.
Duke Energy provided investors with a summation of upcoming regulatory issues, including a long-term $7 billion “grid hardening” investment in Florida and up to 2,400 MW of new generation in Indiana. | Duke Energy
In Florida, Duke is committed to spending $7 billion over the next 10 years, including measures to harden the grid to resist storm damage.
And in Indiana, the company has proposed building 2,400 MW of new generation, including 1,100 MW of renewables and 1,300 MW of “dispatchable generation,” including new gas turbine power plants and batteries, before it can close its remaining coal plants.
The California Air Resources Board is searching for a new chief executive following the announcement that current Executive Officer Richard Corey will retire at the end of June.
Corey has worked for the agency for 37 years and served as executive officer since 2013. In that role, Corey oversees a staff of about 1,700 employees and an annual budget of more than $2 billion.
The executive officer is appointed by the CARB board. The agency issued a recruitment announcement for the position last week.
During a ceremonial presentation at the end of CARB’s April 28 board meeting, Chair Liane Randolph detailed Corey’s accomplishments.
Corey joined CARB after receiving a bachelor’s degree in environmental toxicology in 1984 from the University of California, Davis. He later received an MBA from the same university.
By 1997, Corey was grants chief in CARB’s research division
When CARB adopted first-in-the-nation limits on tailpipe greenhouse gas emissions in 2004, Corey “played a key role in developing, communicating and defending staff’s findings on the need to address climate change and the economic impacts of the regulation,” Randolph said. “This set the course for CARB’s further initiatives on climate change.”
Later, as stationary source division chief, Corey oversaw the adoption and implementation of the agency’s low-carbon fuel standard. And as a deputy executive officer, he supervised CARB’s first cap-and-trade auction.
He was named executive officer in 2013, succeeding James Goldstene.
Board members expressed appreciation to Corey for his work ethic, thorough knowledge of the agency’s work and his availability to the board.
“You’re herding cats all the time,” board member Hector De La Torre said. “It’s really hard to do.”
De La Torre, who served in the California Assembly from 2004 to 2010, called Corey’s work with the state legislature “tremendous.” The board never had to worry that there would be “blowback” from lawmakers over something the executive officer said.
“That’s really, really important … to know that we’re not going to mistakenly get into fights with the legislature,” De La Torre said. “Because that can happen. There’s egos over there.”
Although Corey’s retirement is effective June 30, the April 28 board meeting is expected to be the last he attends as executive officer.
In its recruitment announcement, the agency said the ideal candidate to replace Corey would be an air quality and climate expert with “a commitment to clean air for all Californians and a focus on priority communities that are overburdened by air pollution.”
Salary for the Sacramento-based position is listed at $17,349 to $18,850 per month. The application deadline is May 24.
New Mexico has become the latest state to adopt California’s Advanced Clean Cars regulation, which sets tailpipe emission standards and requires automakers to supply a certain percentage of zero-emission vehicles in the state each year.
The New Mexico Environmental Improvement Board (EIB) and the Albuquerque-Bernalillo County Air Quality Control Board (AQCB) each approved the rule on Thursday, at the end of a two-day joint hearing.
The rule will apply to new light- and medium-duty passenger cars and trucks starting with model year 2026.
The decision came after proponents told the boards that finding an EV to buy at New Mexico car dealerships was difficult, if not impossible.
“Automakers will prioritize electric vehicles to the jurisdictions that require them,” said Kathy Harris, a clean vehicles and fuels advocate with the Natural Resources Defense Council (NRDC). “So having New Mexico adopt the Advanced Clean Cars standard will ensure that the types of clean vehicles that drivers want will be available to them.”
Tammy Fiebelkorn, an Albuquerque city councilor, said she drives an EV that she bought used. She said she bought the car out-of-state because she couldn’t find one in New Mexico.
Fiebelkorn said that when she went shopping for a new EV last year, she visited every car dealer in Albuquerque looking for one.
“There were none to be found,” she said. “Literally none.”
And when dealers were asked if they could order an EV, they either said “no” or that they couldn’t guarantee the car would be received in less than a year, Fiebelkorn said.
Growing List of States
New Mexico joins 17 other states that have adopted California’s Advanced Clean Cars regulation in whole or in part.
Under the federal Clean Air Act, states have an option to follow federal vehicle emission standards or to adopt California’s more ambitious standards.
California’s Advanced Clean Cars regulation has two parts. A low-emission vehicle (LEV) program sets tailpipe emission standards, while the zero-emission vehicle (ZEV) program requires automakers to supply a certain number of EVs each year.
Sixteen states have adopted the LEV and ZEV components, while Delaware and Pennsylvania adopted the LEV program only, according to NRDC. The 18 states combined account for more than 40% of the U.S. vehicle market, the group said.
The ZEV program uses a system of ZEV credits, which are based on factors including the type of EV provided for sale and its all-electric range. The 22% ZEV credit requirement will work out to about 7% of new cars delivered for sale, according to written testimony on the rule from Claudia Borchert, climate change policy coordinator in the New Mexico Environment Department.
The current rate of ZEV sales in New Mexico is about 1% to 2%, Borchert said. By comparison, ZEVs accounted for more than 12% of California light-duty vehicle sales last year, according to the California Energy Commission.
Automakers will be able to earn early action credits for delivering ZEVs to New Mexico starting with model year 2023. And to further smooth the way to the 22% credit requirement, car manufacturers may receive a one-time credit for model year 2027, based on their ZEV credit balance in California for model year 2025.
Borchert described the one-time credit as the same compromise that environmental advocates and auto manufacturers reached during the clean car rulemaking in Nevada last year. (See Nev. Adopts Clean Cars Rule, Allows Early Credits.)
Although some stakeholders oppose the one-time credit because it could reduce the number of ZEVs delivered for sale, “this concern must be balanced against the need to provide a smooth, feasible ramp for manufacturer compliance,” Borchert said.
Agency Coordination
Last week’s joint hearing included the Albuquerque-Bernalillo County Air Quality Control Board, as well as the state EIB, because the city of Albuquerque has jurisdiction over its own air quality regulations. The two entities worked together on the clean cars rulemaking process.
Both boards unanimously approved the regulation on Thursday.
EIB Vice Chair Amanda Trujillo Davis noted the “overwhelming support” for the rule expressed during the hearing. In response to concerns about the fate of the lithium-ion batteries used in EVs, Trujillo Davis said she hoped New Mexico could become a leader in EV battery recycling.
EIB member Karen Garcia responded to comments from auto industry representatives who said EV adoption should be left to the free market.
“Sometimes the market needs a little push in the right direction,” Garcia said. “And I think this rule would provide that.”
The clean car rule is part of Gov. Michelle Lujan Grisham’s and Albuquerque Mayor Tim Keller’s efforts to reduce greenhouse gas emissions responsible for climate change, the city and state said in a joint release after the boards’ votes. In a 2019 executive order, Lujan Grisham directed the state to join the U.S. Climate Alliance and set a statewide GHG emissions reduction goal of at least 45% below 2005 levels by 2030.
The clean car rule will also help the city and state with their respective ozone attainment initiatives, the release said.
Concerns Expressed
Not all stakeholders supported the Advanced Clean Cars rule.
Benjamin Segovia, regional director for the New Mexico Farm and Livestock Bureau, said the group supports incentive-based approaches to clean vehicle adoption rather than mandates.
New Mexico is “vastly different” from California, he said.
“A California standard is not the right fit for a poor state like New Mexico, where many struggle to find affordable means of transportation,” Segovia said.
In her written testimony, Borchert responded to other concerns about the clean car regulations.
One concern is that New Mexico’s EV charging infrastructure is not adequate to support the rule’s ZEV requirement. Borchert said about 80% of EV owners charge their vehicle at home.
As of April, New Mexico had 180 charging stations with 437 ports, and more charging stations are on the way, she said. About 115 EV charging stations are being funded by $4.6 million in Volkswagen settlement funds. And the state will have additional money for charging infrastructure from the American Rescue Plan Act and the Infrastructure Investment and Jobs Act.
Some car dealers in rural areas questioned whether automakers would send them EVs that they won’t be able to sell. Borchert said manufacturers are expected to send more ZEVs to dealers “with demonstrated consumer demand,” such as in urban areas.
Some commenters were concerned about the impact of increased EV adoption on the state’s road construction and maintenance fund.
The New Mexico Department of Transportation has been working with RUC-West, a group that researches and shares best practices on road usage charges, to study other ways to collect the road maintenance funds. Options include an additional annual registration fee for ZEVs or a road usage charge.
DOE funding for transmission under bipartisan Infrastructure Investment and Jobs Act. | Department of Energy
David Getts, SouthWestern Power Group | © RTO Insider LLC
