MISO planning analyses will soon decide the fate of the contentious and delayed Hartburg-Sabine Junction competitive project in East Texas as some stakeholders question the lack of more aggressive clean-energy projections in the restudy.
The RTO last month announced it would reassess the 500-kV, $130 million market-efficiency project under its variance analysis procedures. Depending on the study’s results, the RTO has two options: cancel the project or confer the line to incumbent developer Entergy in accordance with Texas’s right-of-first refusal (ROFR) law. (See MISO Reassessing Hartburg-Sabine Project amid Texas ROFR Dispute.)
MISO approved the project under its 2017 Transmission Expansion Plan (MTEP 17). The grid operator found that the first competitive transmission project ever assigned in MISO South would alleviate congestion, ease import limitations, and allow access to lower cost generation in the chronically constrained West of the Atchafalaya Basin and Western load pockets in Entergy’s servicer territory.
However, Texas passed its ROFR legislation in 2019, blocking MISO’s selected competitive developer NextEra Energy Transmission Midwest from breaking ground. (See Texas ROFR Bill Passes, Awaits Governor’s Signature.)
During a South Technical Study Task Force meeting Wednesday, MISO Senior Manager of Competitive Transmission Administration Brian Pedersen said the variance analysis was triggered by two factors: a delay of the project’s in-service date and NextEra’s inability to secure permitting to begin construction.
Pederson said though the variance analysis criteria was in fact triggered in 2019, staff didn’t immediately embark on a restudy because of NextEra’s continuing litigation against the Texas law. However, he said the original 2023 in-service date is too close for MISO to continue to hold out for pending litigation.
Pedersen also said new planning analyses are a good practice, given the length of time that has passed without any construction.
“It’s been a little over four years since the project was approved,” he said, adding that the RTO rarely reanalyzes economic projects.
MISO will adhere to its market planning congestion study process to reanalyze the line but will use just one of its trio of existing, 20-year planning futures to assign a new benefit-to-cost ratio. The grid operator’s market efficiency projects must have a B/C ratio of at least 1.25:1 to be recommended.
Staff said they would model the project using Future 1, which predicts the least amount of future renewable energy additions, thermal generation retirements and electrification into the 2030s.
MISO will also consult with Entergy Texas on a new, estimated in-service date for the line.
Clean Grid Alliance’s Natalie McIntire questioned the use of just one future to restudy the line. She said it seemed MISO would conduct an incomplete analysis if it left out the Futures 2 and 3, which anticipate more rapid clean-energy transitions.
“We have three futures because we don’t really know what the future will look like. Future 1, as it was created, has already been exceeded based on utility announcements and state goals in recent years,” McIntire argued.
She asked staff to consider also modeling the line under Futures 2 and 3.
“If we don’t do that, I don’t think we’re doing the line justice about how it will perform 20 years into the future … It’s a concern,” McIntire said.
Andy Kowalczyk of activist group 350 New Orleans said simply using Future 1 doesn’t seem to align with Entergy’s goal to source 100% clean energy by 2050.
Other stakeholders asked whether staff will account for recent generation retirements in the area, last year’s addition of Entergy’s 993-MW Montgomery County Power Station in southeast Texas, and the likelihood that Entergy builds its planned 1.2-GW natural gas and hydrogen-powered Orange County Advanced Power Station by 2026.
MISO only includes future generation in its planning analyses when the units have a signed generation interconnection agreement. However, staff said they would look into generation assumptions and planning futures that will influence the study and report back to stakeholders.
The RTO plans to post a study scope for stakeholder review by May 23 and will hold two more South Technical Study Task Forces on June 8 and July 20 to discuss the project’s need. The grid operator said it will make a final determination for the line sometime in August.
The Northeast Power Coordinating Council’s Regional Standards Committee on Wednesday approved a guidance document on integrating distributed energy resources in the bulk power system, identifying possible risks and strategies to mitigate them.
Gerry Dunbar, NPCC | NPCC
The document incorporated substantial revisions suggested by stakeholders, including to sections on DER characteristics and capabilities, aggregation and interconnection standards, and an appendix for inverter-based resources, Gerry Dunbar, NPCC director of reliability standards and criteria, said at the committee’s meeting.
“The evolving document will see more changes as guidance is informed by ongoing DER and variable resource forums, particularly relating to electric vehicle charging and building electrification, topics that will eventually will have their own appendices in the guidance document,” Dunbar said.
FERC Update
Kal Ayoub, deputy director of FERC Division of Cyber Security, updated participants on commission activities since the last RSC meeting in February, including meetings of the Joint Federal-State Task Force on Electric Transmission.
The task force of FERC commissioners and 10 state regulators was created by Chairman Richard Glick in June to enable transmission expansion to improve resilience and connect new renewable energy resources (AD21-15).
Kal Ayoub, FERC | NPCC
“The third meeting was held just last week and focused on examining barriers to efficient, expeditious and reliable interconnection of new resources through the FERC-jurisdictional interconnection process,” Ayoub said. (See FERC-State Task Force Considers Clustering, ‘Fast Track’ to Clear Queues.)
Ayoub also noted that the commission’s Jan. 20 Notice of Proposed Rulemaking to add internal network security monitoring (INSM) to NERC’s Critical Infrastructure Protection (CIP) reliability standards also sought comments on the usefulness or impracticality of implementing INSM to detect malicious activity, including any potential technical barriers and associated costs.
“We are currently reviewing 22 comments and of course next steps would eventually be a final rule,” Ayoub said.
Committee members also had questions about the commission’s April 21 NOPR to change transmission planning and cost allocation processes to help build out the grid. (See FERC Issues 1st Proposal out of Transmission Proceeding.)
Dan Kopin, a compliance analyst at Vermont Electric Power Co. (VELCO) and part of the System Planning Impacts from Distributed Energy Resources (SPIDER) Working Group at NERC, asked whether and how much Ayoub’s division is involved in the docket and whether new NERC standards could arise from the proceeding.
“Obviously cybersecurity is not involved yet … [and] we do get plugged into these rulemakings as they are issued, but of course transmission planning itself is in another office, but yes we are involved in all of these dockets,” Ayoub said. “Is it feasible that new NERC standards or reliability standards could potentially emerge from these NOPRs? Our understanding is no; … it’s a separate part of the development process.”
Regarding the transmission planning NOPR and the joint task force, “do you think there’s any synergy between the two, or are they coming at us on two separate tracks?” Dunbar said.
Ayoub said that was a very good question but tough to answer.
“The intent of the Joint Federal-State Task Force [is] … to encourage cooperation and communication between federal and state regulators on electric transmission-related issues,” Ayoub said. “When you look at what the joint task force is doing and what the commission’s NOPR on transmission planning is asking for, I think the answer is yes … there are of course some synergies between both.”
Cold Weather Standards
Kenny Luebbert, Evergy | NPCC
Kenny Luebbert, director of operations support at Evergy, updated the RSC on evolving standards on extreme cold weather grid operations, preparedness and coordination.
The term “retrofit” was used informally by planners but did not make it into the standards.
“‘Retrofit’ was clarified to mean ‘implement freeze protection measures or modify existing freeze protection measures,’ so that’s what NERC or FERC and the report drafting team meant when they said ‘retrofit,’” Luebbert said. “It’s not anything more than that, so we wanted to make sure that ‘retrofit’ term was not used in the new standards. …
“For new builds, we understand that there may be technical, commercial or operational constraints that do not allow you to take corrective action. For instance, wind turbines in West Texas experienced freezing rain in the [February 2021 winter storm], and they froze on the blades, and the blades and the turbine shut down,” Luebbert said. “There are no existing technologies widely used in the industry that allow for de-icing of wind turbine blades; it doesn’t exist. There are conceptual things that exist, but nothing that’s available widely in the industry, so we need a method that they can take exception to.”
FERC on Tuesday approved a trio of changes to NYISO’s capacity market that were spurred by New York’s Climate Leadership and Community Protection Act (CLCPA).
With FERC’s blessing, NYISO will now exclude new capacity resources required to satisfy the CLCPA’s goals from its buyer-side market power mitigation (BSM) rules. The change will automatically eliminate offer floors for wind, solar, storage, hydroelectric, geothermal, fuel cells that do not use fossil fuel, demand response and other qualifying resources under the law (ER22-772-001).
Commissioner James Danly disagreed with NYISO dispensing with BSM rules for certain resources and dissented in part from the order.
Going forward, NYISO will also adopt a new, marginal capacity accreditation design that values installed capacity (ICAP) suppliers based on their marginal contribution to system reliability, instead of an average contribution. NYISO plans to rely on the same resource adequacy model database that it uses to establish its locational minimum ICAP requirements and installed reserve margin to value the resource adequacy contribution of different classes of resources.
Finally, the ISO will also change how it determines its ICAP market demand curves and will now use a reference unit’s individual derating factor — instead of a systemwide or regional derating factor — to calculate an unforced capacity reference point price.
NYISO filed the proposal to sidestep a possible jurisdictional dispute with the state while ensuring its capacity market still results in just and reasonable outcomes after an influx of thousands of megawatts of subsidized resources. The CLCPA requires New York to procure large amounts of renewable energy to get to zero-emission electricity by 2040. (See NYISO Details Comprehensive Mitigation Review, Related Impacts.)
The ISO already maintained a BSM exemption for its wind and solar resources. It will eliminate that exclusion because it’s now duplicative. It plans to maintain its existing BSM exemptions for self-supply and competitive suppliers.
NYISO said its proposal “better accommodate[s] New York state’s policy objectives.” It also said by exempting new capacity resources that “serve CLCPA objectives” from its BSM mitigation rules, it recognizes New York’s jurisdiction to address its resource mix.
FERC said the exclusion will preserve “New York state’s right to plan its generation mix while still protecting against the exercise of buyer-side market power.” It agreed with NYISO that the suite of changes “would provide a legally durable solution to the tension between protecting commission-jurisdictional markets and accommodating state policies.”
The commission also said NYISO’s proposed marginal capacity accreditation design will “accredit all resources based on an objective measure of their incremental contribution to resource adequacy” and said the new demand curve calculation “will better reflect the characteristics of the reference peaking plant, thus ensuring economically efficient ICAP market outcomes.”
The mitigation exclusion will begin immediately; the new marginal capacity accreditation design and ICAP demand curve changes will take effect starting with the capability year beginning May 1, 2024. FERC asked for a follow-up informational report from NYISO to apprise it of “final implementation details.”
Danly Differs on Exceptions
Danly said that while he agreed with the new resource accreditation and demand curve calculation, he could not support BSM exemption that favors “state-preferred resources.”
“As I have explained before, buyer-side market mitigation is required in order for us to find market rates to be just and reasonable,” he wrote in a partial dissent.
Danly said applying BSM to offers from state-supported resources is not an “unlawful intrusion” of the Federal Power Act’s protection of state authority over generation portfolios. He argued that it is “squarely” within FERC’s jurisdiction to ensure that states’ out-of-market subsidies don’t adversely affect wholesale capacity rates. He warned that NYISO will experience “inevitable price suppression caused by unmitigated state subsidies.”
Danly referenced the 3rd U.S. Circuit Court of Appeals’ 2009 finding that states “are free to make their own decisions regarding how to satisfy their capacity needs, but they ‘will appropriately bear the costs of [those] decision[s],’ including possibly having to pay twice for capacity.”
“This equally applies to the decisions of New York state,” Danly wrote.
The majority, however, said the order hearkens back to the commission’s “earliest BSM orders, which … focused on the exercise of buyer-side market power by market participants rather than attempting to block or mitigate the effects of state public policies.” The order is a departure from FERC’s days of issuing BSM rule orders that “treated state policy choices as equivalent to anticompetitive conduct,” it said, and the exemption will “strike a more appropriate balance between the harms of over- and under-mitigation.”
The commission also said NYISO’s BSM rules as applied today are likely causing the capacity market to ignore some resources, “causing it to clear surplus resources at an elevated price” and “suggesting that new resources are needed, or that existing resources should not retire, when such resources are not in fact necessary to ensure resource adequacy.”
In a separate statement, Commissioner Mark Christie said his agreement with BSM rule exemptions hinged on the fact that NYISO is a single-state ISO, with resulting costs from the rule likely to be confined within New York borders.
“A similar analysis could well lead to a different outcome in a multistate RTO, if the record showed that the RTO was implementing one state’s public policies as to preferred resources, and that implementation resulted in impacts being shifted to consumers in one or more other states,” Christie wrote. “Such impacts and cost-shifting in multistate RTOs, if proven by the record, could well be unjust, unreasonable and unduly discriminatory or preferential under the FPA.”
The California Energy Commission issued a draft report Friday that, if finalized later this month, would establish goals of building 3 GW of offshore wind by 2030 and 10 to 15 GW by 2045.
“These preliminary megawatt planning goals will inform the development of a strategic plan for floating offshore wind in federal waters off the coast of California,” the report says.
With technical advances, it might be possible to set a goal of 20 GW by 2050, the Energy Commission (CEC) said.
“CEC staff recognizes that by 2045 there may be sufficient technological developments and related cost reductions driven by innovation in floating offshore wind components such as advanced monitoring systems, mooring systems, flexible cabling and increased turbine size,” the report says. “Such technological developments could support a faster rate of offshore wind deployment that could potentially support a larger megawatt planning goal of up to 20 GW between 2045 and 2050.”
Assembly Bill 525, which took effect Jan. 1, requires the CEC to set offshore wind targets by June 1 and to coordinate with federal, state and local agencies to develop a strategic plan for offshore wind by June 30, 2023. The effort contributes to the state’s goal, under Senate Bill 100, to supply all retail customers with only clean energy by 2045.
The federal Bureau of Ocean Energy Management (BOEM) intends to hold the West Coast’s first offshore lease auctions later this year for the Morro Bay Wind Energy Area, off the coast of Central California, and for the Humboldt Bay Wind Energy Area, off the Northern California coast. (See BOEM to Offer Leases for Calif. Offshore Wind.)
BOEM expects Morro Bay to generate 3 GW and Humboldt to generate 1.6 GW. The areas are very different with respect to transmission, however, the CEC noted in its report.
“The North Coast wind resource is one of the best in the world with high renewable energy potential and wind speeds consistent and favorable for commercial development,” it says. “But the electric system in California’s North Coast region is relatively isolated from the California grid and serves primarily local community need. Additional transmission infrastructure will be needed to deliver offshore wind energy from this region to the grid.”
In contrast, “existing transmission on the Central Coast is robust and near large load centers,” the report says. “Near-term electric generator retirements, such as 2,225 megawatts from the Diablo Canyon Nuclear Power Plant, provide an opportunity to repurpose existing infrastructure to integrate wind energy developed offshore.”
Ports and infrastructure capable of handling massive floating wind turbines must still be developed, it said. (See West Coast Wind Faces Big Challenges.)
Potential effects of offshore wind on marine ecosystems, fisheries, Native Americans and national defense are being studied. BOEM said Thursday it had completed its environmental review of impacts to the Humboldt offshore wind area and found no significant impacts.
Early reaction to the CEC’s draft report was mostly positive.
Industry group Offshore Wind California said in a statement that the “ambitious multi-gigawatt goals set by the California Energy Commission in its draft AB 525 report are very encouraging news and an important milestone for the Golden State’s offshore wind industry.
“They show that California is serious about ‘going big’ on floating offshore wind … [and] send an important signal to the industry and other state and federal agencies that California is committed to moving forward expeditiously to make offshore wind power a reality,” the group said.
The CEC plans to host a public workshop on May 18 to discuss the draft report before it is finalized.
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.”
