MISO’s Independent Market Monitor is condemning the modeling software MISO uses to plan its second long-range transmission portfolio.
MISO held another long-range transmission planning (LRTP) workshop Dec. 1, during which it rehashed its analyses pointing to a need for more backbone transmission. Meanwhile, IMM David Patton criticized the resource expansion tool MISO uses to plan transmission as unsophisticated and not up to the job of helping develop a collection of multibillion-dollar transmission lines.
Patton said MISO’s modeling software continues to decide to hypothetically “build an enormous amount of generation that goes beyond states’ plans,” distorting the amount of new transmission facilities needed in the future.
He said MISO’s capacity expansion tool used in modeling, the Electric Generation Expansion Analysis System (EGEAS), might not be the best fit to plan LRTP portfolios. Patton said EGEAS prioritizes economics above all, choosing to add intermittent renewable energy and ignore the reliability benefits and attractive higher capacity accreditations of battery storage and hybrid resources.
Patton said MISO should test transmission projects under different sensitivity cases before moving ahead with recommendations.
“The LRTP is not a generation expansion plan. It’s a transmission expansion plan,” WEC Energy Group’s Chris Plante said, requesting that MISO run a sensitivity that doesn’t use EGEAS’s resource expansion predictions.
Minnesota Public Utilities Commission staff member Hwikwon Ham thanked MISO for not trying to assume the role of resource planner and not second-guessing utilities’ and states’ resource planning and decarbonization goals.
“When a utility makes those announcements, they’re not making those announcements for fun,” Ham said, adding that intensive analysis goes into resource plans.
MISO Vice President of System Planning Aubrey Johnson said MISO continues to hold discussions with the Independent Market Monitor about his vision of resource expansion in MISO.
“I think we have some different views about EGEAS and modeling tools,” Johnson said.
Johnson said MISO will strive to build a portfolio of the least-cost solutions that work under a variety of scenarios, including a smaller-sized resource expansion.
Last month, MISO said it found significant overloads, voltage violations and congestion on the system absent a second LRTP portfolio when it applied its envisioned 2042 resource mix in studies. Those conclusions stemmed from MISO’s initial economic and reliability analyses under its second LRTP portfolio. (See MISO Says Overloads and Congestion Loom Without 2nd Long-range Tx Portfolio.)
MISO’s reveal of which lines it may pursue is pending. Results from the economic and reliability analyses will set the stage for which lines MISO will recommend.
MISO will host additional LRTP workshops Jan. 26 and March 15. It will open an LRTP submission window for stakeholders to suggest project needs in late January.
Executive Director of Transmission Planning Laura Rauch said the grid operator is reassessing its goal to finalize the second LRTP portfolio for approval in the first half of 2024. Rauch said if it appears MISO’s recommended portfolio needs more “robustness testing,” MISO will take time to conduct more analyses.
A recently retired Washington State Department of Transportation (WSDOT) economist has filed a claim against the state alleging he was ordered not to include cap-and-trade costs in an early 2023 revenue forecast, leading to him to leave his position with the agency.
But Washington officials have quickly contested the allegations in the complaint, saying the staffer had only a limited role in developing the forecasts.
Represented by the Citizen Action Defense Fund (CADF), Scott Smith filed a claim Nov. 30 against the Transportation Department, the state’s Office of Financial Management (OFM) and the governor’s office seeking $750,000 in lost income because he felt pressured to leave the agency before he was ready to retire. A claim must be filed 60 days prior to the filing of a lawsuit seeking damages from the state. CADF is a conservative organization that opposes Washington’s cap-and-trade program.
CADF in January filed a lawsuit in Thurston County Superior Court arguing the Washington Legislature violated the state constitution by cramming multiple subjects into its 2022 transportation bill, including tackling the nuts and bolts of the cap-and-trade program. The judge in that case rejected the suit and CADF is appealing the ruling to the state Supreme Court. (See Wash. Judge Rejects Cap-and-trade Lawsuit.)
In Thursday’s complaint, CADF said Smith worked as WSDOT’s gasoline tax revenue and price forecaster for at least five years, following decades in a similar role with the New Mexico government.
The complaint alleges that when Smith prepared his gas revenue and price forecasts at the beginning of 2023 for WSDOT’s revenue forecast council, he calculated that the cap-and-trade program — which went into effect on Jan. 1, 2023 — would have significant effects on gas prices and gas tax revenue. The complaint alleges that WSDOT and OFM told him to remove those calculations from his forecast.
“He was approached by a supervisor and told not to include what the impacts of cap-and trade will be. … They were asking him to lie, and he wouldn’t do that,” Jackson Maynard, CADF’s executive director, said in an interview.
Maynard and the complaint contend that Smith was told for the first time that he would need OFM approval on future calculations, that he was denied a promotion and that he was denied leave to see his sick mother — alleging retaliation. Smith recently retired because of what he perceived to be hostilities toward him, Maynard said.
“It’s very disturbing to hear that executive agencies under the governor’s oversight are pushing staff to misrepresent facts and figures,” state Senate Minority Leader John Braun (R) said in a press release. “This is especially upsetting if it was done to hide the full impact of the governor’s [cap-and-trade program] and manipulate the people of Washington into accepting the spike in gas prices without knowing the true cause. The projections by the state employee who is at the center of this lawsuit have been proven to be correct — not because oil companies or gas station owners got greedy, but because the state of Washington did.”
‘Complex and Highly Variable’
The political controversy around the cap-and-trade program ramped up in June when Washington posted the highest gasoline prices in the nation. Republicans have seized on the development as a major political issue, while Democrats have defended the program.
Gov. Jay Inslee (D) is taking political heat because he said the cap-and-invest program would add “a few pennies” per gallon to gasoline prices when the Legislature approved the program in 2021 along party lines. Various analyses have shown numerous factors beyond the program are contributing to Washington’s high gas prices.
The program is on track to raise close to $2 billion in 2023, with most of the money going to mitigate the effects of climate change.
Inslee’s office first became aware of Smith’s complaint on Nov. 30, Inslee spokesperson Mike Faulk said in an email to NetZero Insider. The governor’s office receives its gasoline price and revenue information from the state’s Ecology Department and not from WSDOT, Faulk said.
“The Washington Legislature directed the Washington Department of Ecology to develop and implement the cap-and-invest program — not the Department of Transportation,” Ecology Department spokesperson Andrew Wineke said in an email. “Ecology used its own economists to conduct the regulatory analysis for the cap-and-invest program, with support from a respected independent economics firm. No one from the Department of Transportation provided input on that analysis.”
OFM spokesperson Hayden Mackley added that the transportation revenue forecasts are important in developing the state’s budget.
“It’s important that this complex work is completed by professional forecasters. We rely on staff in other agencies who have this expertise to fill this role.” Mackley said.
WSDOT spokesperson Kris Abrudan told NetZero Insider: “Transportation revenue forecasts are complex and highly variable. … Data integrity, transparency and consistency are integral to this process and any changes to that model to include incorporating [the cap-and-trade program] would be a much broader determination than any one employee or agency.”
In the evening on Dec.1, Faulk sent out an email to several news organizations, including NetZero Insider, saying the appropriate OFM official does not recall discussing this matter with Smith and does not recall declaring that Smith’s work needed to be reviewed by OFM.
The email also said:
The Legislature eliminated Smith’s position last session, with his functions transferred to the state’s Economic Revenue Forecast Council. Therefore, his position was not eliminated by WSDOT.
WSDOT was considering Smith’s request to be able to work remotely, but he did not complete the process for that decision-making.
Smith’s request to take time off to be with his mother around Thanksgiving conflicted with a presentation that he was scheduled to give.
Earth is living through its hottest year on record, and global efforts to curb human-generated greenhouse gas emissions driving those high temperatures are not keeping up with commitments to cut emissions, which individual countries made under the Paris Agreement signed eight years ago.
New directions, new actions and higher ambitions are urgently needed if the increase in the global average temperature is to be held to the 1.5 degrees Celsius set in Paris.
The opening day of the 28th U.N. Climate Change Conference of the Parties (COP28) in Dubai, United Arab Emirates, offered multiple opportunities for speakers to repeat these rallying cries — and put their own spin on what those statements mean and what actions should be taken.
“The world has reached a crossroads,” said Sultan Ahmed al-Jaber, COP28’s president, who is also CEO of UAE’s state-run Abu Dhabi National Oil Co.
“Yes, since Paris we have made some progress, but we also know that the road we have been on will not get us to our destination in time,” al-Jaber said. “The science has spoken loud and clear. It has confirmed that the moment is now to find a new road, the road wide enough for all of us.”
Calling on participants to adopt a different, more flexible mindset, al-Jaber argued for his “bold choice to proactively engage with oil and gas companies,” many of which he said “are committing to zero methane emissions by 2030 for the first time, and many … oil companies have adopted net-zero 2050 targets for the first time.”
“I know there are strong views about the idea of including language for fossil fuels and renewables in the negotiated text,” al-Jaber said, referring to whatever official agreement is hammered out at the end of the conference. “We collectively have the power to do something unprecedented; in fact, we have no choice but to go the very unconventional way. I ask you all to be flexible, find common ground, come forward with solutions.”
Al-Jaber’s strong ties to the fossil fuel industry have been a flashpoint since January, when the UAE named him to lead the conference.
Controversy flared again Nov. 27, when the BBC reported that the UAE was planning to use the conference for business meetings with more than a dozen countries to promote oil sales, citing documents that included specific talking points for each country. At a press conference Nov. 29, also reported by the BBC, al-Jaber denied any knowledge of the talking points or ever using them in COP-related discussions.
Al-Jaber is also one of the leaders of an international drive to have countries at COP28 commit to triple renewable energy capacity and double energy efficiency by 2030.
‘Teach Climate Action to Run’
Expectations for COP28 — and U.S. leadership at the conference — have been mixed.
After bringing the U.S. back into the Paris Agreement early in his term, President Joe Biden is not attending the conference, sending Vice President Kamala Harris in his stead.
But the opening day saw a major success with the approval of a loss and damage fund, to be used to compensate developing countries for damages they have already sustained from extreme weather events made worse by climate change. Developing countries have been pushing for years for this fund, which was initially approved at COP27 last year in Egypt.
Thursday’s vote actually created the fund, and the UAE immediately pledged $100 million, with the EU announcing a pledge of $245.39 million, including $100 million from Germany, according to a report from Reuters. The U.K. will contribute $51 million; the U.S. $17.5 million; and Japan $10 million.
Rachel Cleetus, energy and climate policy director at the Union of Concerned Scientists, called the loss and damage fund “a significant step forward” but still “deeply flawed.” Speaking at a press conference held by the Climate Action Network, a global consortium of nonprofits and community groups, Cleetus said the recommendations approved for the fund “represent richer countries exercising power and getting their way, for example, through ensuring that the fund’s interim host is the World Bank.”
Rachel Cleetus, Union of Concerned Scientists | United Nations
But the centerpiece of the conference will be the first Global Stocktake (GST), an evaluation of countries’ performance on their climate commitments, in preparation for new commitments to be submitted in 2025, as mandated by the Paris Agreement.
The U.N. 2023 Emissions Gap report, released Nov. 20, found that even if all nations deliver on their original commitments under Paris, the average temperature could rise 2.5 to 2.9 C by 2050. Limiting warming to 1.5 C would require a 42% drop in GHG emissions by 2030, the report says.
“We are taking baby steps, stepping far too slowly from an unstable world that lacks resilience, to working out the best responses to the complex impacts we are facing,” said Simon Stiell, executive secretary of the U.N. Framework Convention on Climate Change. “We must teach climate action to run.”
Taking a stronger line on fossil fuels than al-Jaber, Stiell said the GST will provide two options.
Simon Stiell, UNFCCC | United Nations
“Either we can note the lack of progress, tweak our current best practices and encourage ourselves to do more at some other point in time; or we decide at what point we will have made everyone on the planet safe and resilient,” Stiell said. “We decide to fund this transition properly, including response to loss and damage, and we decide to commit to a new energy system. If we do not signal the terminal decline of the fossil fuel era as we know it, we welcome our own terminal decline, and we choose to pay with people’s lives.”
Following the GST, countries will have to submit transparency reports at the next COP in 2024, ensuring that “the reality of individual progress can’t be concealed,” Stiell said. New, higher commitments for emissions reductions will be due in early 2025, before COP30, where “every single commitment on finance, adaptation and mitigation has to be in line with a 1.5-degree world,” he said.
A Fast, Fair and Full Phaseout
Jim Skea, IPCC chair | United Nations
Jim Skea, chair of the U.N. Intergovernmental Panel on Climate Change, gave the opening session a short but brutal summary of the current state of global warming and its likely impacts and called for climate action based on science.
“Our planet has warmed by more than 1 degree Celsius since the preindustrial era as the result of burning fossil fuels, deforestation and the unsustainable use of resources,” Skea said. “Human activity has led to changes in the Earth’s climate of a magnitude that are unprecedented over centuries and thousands of years. Climate impacts, some of them irreversible, are widespread, rapid and intensifying, from the poles to the tropics and from the mountains to the oceans.
“Without immediate and deep emission reductions across all sectors, we will not meet the goals of the Paris Agreement,” he said. While options exist for reducing greenhouse gas emissions now, “they need to be scaled up and mainstreamed through policies and increased financing.”
Tasneem Essop, Climate Action Network | United Nations
“Ambition levels have to increase fivefold to be able to put us back on track to address this climate crisis,” said Tasneem Essop, executive director of the Climate Action Network. Speaking at the press conference, she called for a just and equitable “phaseout of fossil fuels” while also criticizing the presence and influence of fossil fuel companies at past COPs.
Romain Ioualalen, Oil Change International | United Nations
Al-Jaber’s calls for inclusion notwithstanding, a recent report found, for example, that Shell has sent 115 staff members to the annual climate conference over the years.
Romain Ioualalen, global policy campaign manager for Oil Change International, a research and advocacy group, said the success of COP28 could rest on “whether it delivers a decision on the phaseout of fossil fuels … which is a fast, fair, full and funded phaseout.”
“That being said, we cannot ask all countries to phase out fossil fuels at the same pace, and in particular rich countries … with diversified economies have a responsibility to phase out fossil fuels first,” he said.
NYISOreleased its 2023/32 Comprehensive Reliability Plan (CRP) on Nov. 29, finding no “actionable reliability needs” for the next decade, but warning of narrowing reliability margins.
The biennial-CRP serves as the ISO’s 10-year strategy map for New York’s electric system, outlining emerging risks and recommending actions the state can take to ensure grid reliability. It encompasses demand forecasts, resource adequacy, infrastructure development and renewable energy integration. The CRP is the culmination of NYISO’s reliability planning process and assesses the feasibility of solutions proposed in the annual Reliability Needs Assessment (RNA).
The draft CRP, which received NYISO stakeholder approval earlier this month, was presented throughout the year. (See “Comprehensive Reliability Plan,” NYISO Operating Committee Briefs: Oct. 11, 2023.)
The CRP concludes that the system should be reliable, assuming demand and weather conditions align with NYISO’s forecasts. However, delays in key projects like the Champlain Hudson Power Express (CHPE), increased electric demand, additional generator deactivations due to state regulations, unplanned outages or extreme weather events could necessitate new reliability measures in next year’s RNA.
The critical risk outlined in the CRP is the on-time completion of the 1,250-MW HVDC CHPE project, which will bring hydropower from Québec to New York City. If delayed beyond its expected May 2026 completion, reliability margins could become “deficient for the ten-year planning horizon,” leaving New York City unable to meet demand from 2026 onwards.
Without CHPE, statewide summer reliability margins become deficit by 2025. | NYISO
The plan also anticipates a notable increase in peak demand driven by the electrification of transportation and buildings, along with the addition of large loads, especially in upstate New York.
This growing demand becomes even more pressing since about 3,300 MW of fossil fuel plants, which tend to meet demand during extreme conditions, are expected to retire due to the Department of Environmental Conservation’s peaker rule starting in May 2025. This is a particular concern for New York City, which heavily relies on natural gas.
NYISO recently announced plans to extend the operation of two natural gas peaker plants beyond their 2025 retirements to address a 446-MW shortfall in New York City identified in the second quarter Short-Term Assessment of Reliability. (See NYISO to Keep Gas Peakers On.)
The CRP cites the 2023 Fuel and Energy Security study, which predicts that New York will transition from a summer to a winter peaking system as electrification increases and become increasingly reliant on dual-fuel generation resources in winter. This poses a future challenge, especially as many fossil fuels plants expected to retire soon would have been key to meeting peak winter demand.
The CRP recommends introducing new dispatchable emissions-free resources (DEFRs) and inverter-based resources (IBRs), constructing additional transmission, integrating more distributed energy resources (DERs), and expanding demand response and energy efficiency programs.
In an Oct. 23 memo commenting on the draft CRP, Potomac Economics, the ISO’s Market Monitoring Unit, recommended market design changes to encourage the development of flexible resources and the integration of intermittent renewables to maintain reliability. (See Providers See ‘Mixed Signals’ on Demand Response in NYISO.)
Summer extreme weather events represent a risk to statewide system marginal deficiency. | NYISO
Risk Factors
While identifying no immediate reliability needs requiring action, the CRP says that generation retirements could outpace resource additions, which it says could result in a transmission security deficit exceeding 600 MW in New York City by 2033. It says the state’s 2019 Climate Leadership and Community Protection Act, along with other public policy initiatives, significantly accelerated generator retirements.
Even with projects like CHPE, meeting peak demands during extreme winter conditions could become a challenge as early as the winter of 2027/28 due to increased building electrification, electric vehicle growth and the addition of large energy loads like data centers and microchip fabrication plants.
The CRP warns of potential power deficits in future winters, with a projected shortfall of 6,000 MW by winter 2032/33, which could be compounded by gas shortages and extreme cold snaps.
Extreme weather events such as heat waves and storms also represent significant risks, potentially leading to increased electrical demand and more frequent generator outages. An extreme heat wave could cause a statewide deficiency of over 2,500 MW by 2025.
The plan encourages continued interregional collaboration, predicting NYISO will likely have to increasingly rely on its neighbors to meet demand during above-average loads.
Road to 2040
New in this year’s report is a section titled “Beyond the CRP — Road to 2040,” which assesses the impacts of public policies on New York’s electric grid and fuel mix, outlining steps needed to meet the state’s climate targets amidst reliability, generation and transmission risks.
NYISO estimates New York will require between 111 GW and 124 GW of capacity by 2040, with at least 95 GW coming from new generation projects or modifications to existing plants. However, the CRP says this may not even be enough, warning “the sheer scale of resources needed to satisfy system reliability and policy requirements within the next 20 years is unprecedented.”
The section notes a significant portion of this new generation will be IBRs, which are subject to meteorological conditions and also willl need to be supplemented with other resources like energy storage and DERs.
The section emphasizes the need for DEFRs to provide energy and capacity over long durations, especially during low output from intermittent resources, and to replace the attributes of retiring synchronous generation. Resources with the attributes needed for DEFRs are not yet commercially available, prompting the New York Public Service Commission to explore potential technologies such as hydrogen, bioenergy, nuclear power and carbon capture (15-E-0302).
And although NYISO has identified several major public policy transmission projects to deliver renewable energy efficiently across the state, further development is needed to serve renewable generation pockets.
The Road to 2040 also discusses the need for a more resilient power system against climate change impacts and extreme weather, appropriate market price signals and ensuring new resources can provide essential grid services like operating reserves, ramping or voltage support.
The section acknowledges the need for New York to adapt its planning strategies to guarantee future reliability and maintain energy markets flexible enough to respond to evolving grid and environmental conditions.
The Bonneville Power Administration is pulling back from its ambitious schedule for choosing which Western day-ahead market it will join, officials with the federal power marketing administration said during a workshop Nov. 29.
But those officials also indicated BPA still plans to issue a decision on whether it will sign up with either CAISO’s Extended Day-Ahead Market (EDAM) or SPP’s Markets+ sometime early next year.
When BPA launched its process for deciding between the markets in July, staff said it would propose a “policy direction” in the form of a “record of decision” on the issue shortly after SPP filed its Markets+ tariff with FERC in February, following a series of five stakeholder workshops.
The decision would cover two points: whether BPA would participate in a day-ahead market, and which of the two it would join, staff said. (See Regulators Propose New Independent Western RTO.)
Some industry stakeholders criticized the timeline for being overly aggressive and expressed concerns that the timing of the decision suggested an implicit bias in favor of Markets+. Others said the pacing was necessary to ensure that BPA — and the Northwest at large — had a strong influence on the direction of electricity market developments in the West. (See NW Stakeholders Divided on BPA Timeline for Day-ahead Decision.)
The critics may have partly gotten their wish during BPA’s fourth workshop on the issue, when agency officials revealed that while they’ll be sticking to the original timeline for issuing a decision in the first quarter of 2024, they intend to alter the content of that decision.
That record of decision is now likely to cover whether BPA has the statutory authority to join a day-ahead market, while potentially conveying a “leaning” on what market the agency is favoring by that time, Russ Mantifel, the agency’s director of market initiatives, said during the workshop.
Mantifel acknowledged the level of uncertainty around the issue and said BPA still has “limited information” on which to base a decision.
“I would say that the timing of this is still up in the air, right? Like, there’s literally no market that somebody could join. Right now, EDAM has not been approved. There’s no tariff yet for Markets+,” he said, pointing out that SPP is still surveying potential participants on “even what it would look like to start making the commitment” to that market.
Mantifel pointed to other, internal matters that BPA must deal with before making a decision on whether to join a market, including the impact on its rates, tariffs and contracts with power and transmission customers.
“I think it’s fair to expect that that policy direction will establish our authority to join a market and will establish the business case for pursuing a market,” Mantifel said.
“Our customers and regional leaders have expressed to us the importance that our market engagement needs to be consistent with our statutory obligations. We’re right there with you,” said Suzanne Cooper, BPA senior vice president of power services.
Cooper pointed to another factor that might be prompting BPA to ease up its timeline: stakeholder requests that the agency more deeply evaluate the “cost advantages” of a single Western market.
In that vein, she said, the agency continues to monitor developments around the West-Wide Governance Pathways Initiative (WWGPI), which seeks to establish an independent entity to oversee an RTO that would include CAISO and build on the grid operator’s existing market services without subjecting non-California members to the ISO’s state-run governance. BPA has not been participating in that effort. (See West-Wide Governance Pathway Group Digs into its Work.)
“We have heard and definitely acknowledge the requests that we’ve heard for taking some more time for additional analysis and to allow the Pathways concept to develop,” Cooper said. “We’ve heard also from many entities, including within our public power customers, that desire for BPA to maintain our current timeline.”
To Lean or Not to Lean
A representative from a key group representing many of those public power customers asked BPA for more clarity on the process that will follow the first record of decision.
Lauren Tenney Denison, director of market policy and grid strategy at the Public Power Council (PPC), noted that in the “multiphase” process that BPA followed in its decision to join CAISO’s Western Energy Imbalance Market, “it was pretty clear what was being decided and what was still open for discussion.”
“What is the expected action that will happen after the leaning is issued at the end of this process?” Denison asked.
“I think that is still up in the air,” Mantifel said. “The processes for joining the markets themselves are still somewhat fluid as opposed to EIM.”
Fred Heutte, senior policy associate at the Northwest Energy Coalition, advised BPA not to include a “leaning” in the first record of decision. NWEC has been a consistent advocate for a single Western market that includes California.
Reading from comments that NWEC submitted to BPA a day earlier, Heutte said, “The BPA day-ahead market policy should provide principles and a road map for assessment, analysis and modeling to inform BPA’s decision about joining a day-ahead market. Given the wide range of implications for market selection, we strongly urge BPA not to proceed with a leaning on day-ahead market choice at this time.
“We feel that any leaning, whichever direction this goes, not be included with day-ahead market policy, because it really belongs with the decision process.”
Mike Linn, director of market analytics at the PPC, took the opposite view.
“We think that because of the nature of Bonneville’s system, Bonneville’s decision or leaning would be very informative to other Western prospective participants, and [I] just want to kind of re-emphasize that we do think that is a key element and something to include.”
Mantifel defended BPA’s inclusion of the leaning.
“I worry that just making a statement generally about a day-ahead market without recognizing the reality of the fact that there are two options that people are making decisions on … might not reflect the practical reality that entities are facing at this point in time in terms of needing to be in a position to make commitments,” he said.
The Nov. 29 meeting left lingering question about exactly what BPA will provide to stakeholders in the first quarter of 2024.
“BPA is on track to issue a proposed policy decision with respect to participation in day-ahead markets early next year,” agency spokesperson Doug Johnson told RTO Insider. “BPA indicated that it would continue to address stakeholder comments in its public process to evaluate day-ahead market participation.”
Johnson said BPA has“committed to provide a timeline of what decisions would be made and when because some decisions would take place in different processes, such as our rates and tariff proceedings.”
BPA tentatively plans to hold its final day-ahead workshop Feb. 1, but the date is subject to change.
(Editor’s Note: This article was originally titled “BPA Delays Decision onDay-ahead Market Choice.” BPA requested the title be changed to reflect the fact that the agency still intends to issue a proposed policy direction related to day-ahead markets in early 2024.)
The Bureau of Land Management is seeking public input on potential changes to several of its designated West-wide energy corridors, sites that are preferred locations for transmission and other energy transport projects on federal lands.
The changes now being considered include additions, deletions or revisions to about 673 miles of seven designated corridors, BLM said in an announcement Nov. 30. The changes would involve amendments to 19 resource management plans in seven states: Arizona, California, Colorado, Nevada, New Mexico, Utah and Wyoming.
The bureau said the changes are intended to “support transmission siting to speed clean energy production across the West.” Other goals of the project are improving reliability, relieving congestion and strengthening energy security.
“Transmission is a vital piece of moving our country to a clean energy economy,” BLM Director Tracy Stone-Manning said in a statement. “These updates will help plot a course for successful transmission deployment in order to bring renewable energy to markets across the West.”
The work will be funded with $1.2 million from the Inflation Reduction Act.
BLM has scheduled four in-person and two virtual public meetingsin January to hear comments on the proposals.
The West-wide energy corridors are also known as Section 368 corridors, a reference to the section of the Energy Policy Act of 2005 that directed federal agencies to designate the corridors.
The idea behind the corridors is to facilitate transmission development while minimizing impacts to natural, cultural and historic resources across the West. In addition to electric transmission lines, the corridors may be preferred sites for oil, gas and hydrogen pipelines.
The corridors were first designated in 2009, covering about 6,000 miles across federal land in 11 Western states. But the Wilderness Society and other environmental organizations challenged the corridors’ approval in court. As part of a 2012settlement agreement, BLM agreed to work with other agencies to reexamine the corridor designations.
The settlement agreement included “siting principles” for agencies to consider when evaluating corridors. One principle is to look at whether the corridors facilitate connections to renewable energy resources as much as possible while also considering other sources of energy generation.
Other principles were siting of corridors to provide “maximum utility and minimum impact to the environment,” promoting efficient use of the landscape and identifying appropriate uses for specific corridors.
As part of its corridor reexamination, BLM conducted a series of regional reviews to look at new information and hear from stakeholders. The regional reviews were compiled into a final reportreleased in April 2022.
The final report includes recommendations for corridor additions, deletions and revisions. Several of the proposed additions would co-locate a corridor with existing transmission lines.
For example, a new corridor aligned with the planned Santa Fe transmission line in New Mexico could potentially facilitate the transmission of renewable energy from northeastern New Mexico to the Four Corners energy hub.
Another recommended corridor addition, along an existing 230-kV transmission line and the proposed Cross-Tie line, would provide a continuous east-west corridor through Nevada and Utah.
This would facilitate the transmission of high-capacity renewable resources from Wyoming and Utah to southern Nevada and California and give Utah and Wyoming customers access to excess solar energy from CAISO, according to the report.
But topography and the presence of the Utah Test and Training Range could make the changes challenging, the report acknowledged.
Many generator owners (GOs) are not following NERC‘s recommendations for improving the performance of inverter-based resources (IBRs), and new reliability standard projects and other regulatory actions may be needed to enhance these generators’ reliability, according to the findings of a Level 2 alert the ERO released Nov. 30.
NERC issued the alert in March, providing a series of recommendations that GOs were “strongly encouraged to adopt.” (See NERC Issues Level 2 Alert on IBR Issues.) Recipients were required to respond to a series of questions about their grid-connected solar facilities (if any). While the topic of the alert was solar subject to NERC standards, the ERO said in Thursday’s report the recommendations may be applicable to other IBRs including wind and battery energy storage systems.
Entities initially were required to submit their responses to the alert by June 30, but NERC said it had received only 15 submissions by the due date, which the ERO called an “unprecedented and unexpected low response rate.” As a result, the deadline was extended to July 31. By the end of the extension, NERC received 1,149 responses, for a response rate of about 97%.
A total of 217 entities reported owning one or more grid-connected solar facilities. The greatest number of positive responses, 85, came from entities in WECC. SERC Reliability followed with 59, and the Texas Reliability Entity came next with 45. Also, 18 entities in ReliabilityFirst reported having applicable resources, followed by eight in the Midwest Reliability Organization and just two in the Northeast Power Coordinating Council.
Difficulties Obtaining Needed Data
All but three utilities with grid-connected solar resources submitted responses to the alert’s questions by the extended deadline, despite “anecdotal comments [that] indicated that the data was difficult to obtain,” NERC said. GOs reported needing “significant assistance from OEMs [original equipment manufacturers] or consultants,” but OEMs and consultants themselves said they also had problems getting needed information from GOs and each other.
The quality of data submitted was questionable even though most worksheets were technically complete, the report said, with analysis of the responses showing “significant and numerous instances of misunderstanding … the information requested.” In one case, a GO said its inverter manufacturers had not “experienced instances of inadvertent tripping at other facilities” even though its equipment had been “documented to be involved in past major disturbances.”
NERC said it developed the worksheet questions based on input from industry groups and experience from multiple IBR events analyzed by the ERO Enterprise, under the assumption that GOs “would have the requested information available to submit with relative ease.” That such issues exist within the submissions casts “doubt on the accuracy and quality of the submitted modeling data used in reliability studies,” which also would come from GOs, the ERO added.
NERC’s analysis of the data indicated widespread deviations from the ERO’s guidance. For example, about 2,260 grid-connected solar facilities have voltage and frequency protection settings within the “no-trip zone” defined by NERC’s reliability standard PRC-024-3 (Frequency and voltage protection settings for generating resources). While the standard allows for protection settings to border and enter the no-trip zone in some circumstances, NERC said the facilities in question are “at an elevated risk of tripping during [grid] disturbances.”
The ERO also found that less than a third of solar facilities’ protection settings were based on the maximum capability of the equipment, indicating that “there is significant underused ride-through capability across the” electric grid and raising concerns about the availability of reliability services as traditional generation sources are retired. Additionally, about 27% of the solar fleet by MW is not configured with NERC’s recommended ride-through settings, though the report acknowledged that many of these facilities may be older and not capable of being modified.
New Standard Actions Recommended
NERC concluded many GOs and generator operators are providing “only the minimum [performance] as explicitly stated in FERC orders, regional requirements, and NERC reliability standards,” which can put the grid at risk of losing significant amounts of resources and essential reliability services.
One reason for the shortcomings identified by the ERO is the lack of uniform performance requirements for solar facilities. NERC said its Inverter-Based Resource Performance Subcommittee (IRPS) is developing a standard authorization request (SAR) to update FAC-001-4 (Facility interconnection requirements) and standardize performance requirements across North America. Two other standard projects — Project 2020-02 (Modifications to PRC-024) and Project 2023-02 (Performance of IBRs) — are expected to help with the performance deficiencies as well.
NERC also faulted “systemic deficiencies in the availability and understanding of facility information,” and recommended the IRPS draft a new SAR to introduce commissioning requirements for GOs of IBR facilities. The ERO further said its concerns about the quality of modeling data should be addressed as soon as possible.
NERC said it will issue another Level 2 alert next year to gather modeling and study information from GOs and transmission providers, and to “share recommended practices regarding modeling and study enhancements.” A Level 3 alert will follow “in the first half of 2024” with essential actions for GOs to address high-risk IBR issues.
FERC has upheld its ruling on a series of updates to ISO-NE’s Inventoried Energy Program (IEP) which could result in larger payments for generators to keep stored fuel on-site as a grid reliability backstop (ER23-1588).
The changes shift the IEP from fixed payment rate format to indexed rates and are intended to “align the program with current market conditions,” according to ISO-NE. The IEP compensates generators for storing up to three days’ worth of stored fuel and covers the winters of 2023-24 and 2024-25.
Climate organizations argue the changes amount to an unnecessary subsidy for fossil fuel generation. The Sierra Club, Union of Concerned Scientists and Conservation Law Foundation filed for a rehearing in early September.
“The order approves significantly increased incentive payments to oil and gas generators with no assurance that these incentives will change those generators’ behavior in ways that improve reliability,” the organizations wrote in their request. “The commission failed to assess whether the benefits to consumers justified the costs.”
FERC denied the request by default due to the lack of timely action in October. In the Nov. 30 order, the commission upheld its ruling while responding to the arguments of the rehearing request.
“The proposed tariff revisions represent a just and reasonable means of updating the program payment rates to ensure that the Inventoried Energy Program provides appropriate incentives and compensation for market participants to participate in the program,” the commission wrote.
FERC also disagreed with the climate groups about how the IEP will affect generators’ behavior, concluding “ISO-NE’s proposed indexed rates are expected to change market participants’ behavior in the manner intended.”
In the rehearing request, the climate organizations argued most relevant generators already are required by their capacity supply obligations to be available to produce energy, making additional payments from the IEP unnecessary.
FERC disagreed, writing that “the capacity supply obligation does not require the same behavior that the Inventoried Energy Program is designed to incent.”
While the climate groups argued recent ISO-NE studies indicate that “even in a severe winter, there is negligible reliability risk, in part due to increased deployment of wind and solar resources,” FERC said ISO-NE’s winter reliability analyses cited by the environmental groups “actually underscore the important role of the Inventoried Energy Program in providing winter reliability in New England.”
“The winter analyses rely on the assumption that the Inventoried Energy Program will ‘operate as intended’ and that the Inventoried Energy Program will fulfill its purpose of enhancing reliability,” FERC wrote.
Casey Roberts, senior attorney at Sierra Club, wrote in a statement that the organization is disappointed with FERC’s ruling.
“Rather than raising costs for ratepayers across the region to pay polluting oil and gas generators, ISO-NE should instead focus its efforts on building a reliable, lower-cost electric system by bringing more wind and solar online and ramping up energy storage,” Roberts said.
Roberts added that the Sierra Club “will continue to review FERC’s order as we consider our next steps moving forward.”
The Senate Energy and Natural Resources Committee on Thursday looked into the state of advanced nuclear reactors just weeks after NuScale Power and Utah Associated Municipal Power Systems terminated a once promising pilot project. (See Pioneering NuScale Small Modular Reactor Project Canceled.)
Both the Infrastructure Investment and Jobs Act and the Inflation Reduction Act gave billions of dollars to the sector for demonstration projects and commercialization incentives, said committee Chair Joe Manchin (D-W.Va.).
“Despite all of the federal and private sector support, we’re witnessing struggles and hesitancy in getting advanced nuclear projects off the ground,” Manchin said. “There are large design, cost and regulatory uncertainties associated with first-of-a-kind nuclear technology — which is why we’ve now created numerous federal programs to help reduce these risks. But someone will need to go first, and unfortunately many of the utilities I’ve spoken with won’t get in the game until others have done it first.”
The recently canceled Carbon Free Power Project was going to be constructed at the Idaho National Laboratory by NuScale, featuring 60- to 77-MW modules that could be scaled up as the municipal power agency’s needs grew, said lab Director John Wagner.
The project got $771 million in funding from the federal government that taxpayers will not get back, as it was picked for the grant in a noncompetitive process, unlike other advanced nuclear pilots by TerraPower and X-energy, Manchin said.
“I can’t speak to the procurement process, and so on and so forth,” Wagner said. “I can speak to … a lot was accomplished with that project, despite the fact that it was ultimately decided to be terminated. A design certification for an advanced small light water reactor was accomplished; experience with the licensing process; experience with developing the supply chain.”
While the project offered a chance to test out the regulatory process, in his written testimony Wagner said the industry has to end the “era of constructing paper reactors.”
“The Carbon Free Power Project was suspended because of economics,” Wagner wrote. “A lack of subscriptions was directly related to the cost issues surrounding deployment of first-of-its-kind technologies.”
The Department of Energy’s “commercial liftoff” report for advanced nuclear gave several recommendations to enable a “committed orderbook,” said Wagner: cost overrun insurance, tiered grant financial assistance, government ownership, and government-enabled off-take certainty. (See DOE Reports Highlight 3 Technologies to Decarbonize US Economy.)
Utility executives have indicated they do not want to go first on developing new nuclear technology, especially given Southern Co.’s experience with the Vogtle plant and its massive cost overruns, said Manchin. He asked the witnesses how to overcome that resistance.
The next reactors will benefit from the investment and production tax credits from recent legislation, but that is not enough to get the first reactor built, said Jeffrey Merrifield, a former Nuclear Regulatory Commissioner and chair of the U.S. Nuclear Industry Council’s Advanced Nuclear Working Group.
“That’s where I think there needs to be a backstop program,” Merrifield said. “So that if there are timing delays [or] cost overruns, there can be a sharing of that cost and not burden that single company, whether it’s a utility or an industrial user, for putting their neck out and trying to move forward with the technology.”
Utilities are not the only private companies looking into advanced nuclear, with Dow Vice President for Energy and Climate Edward Stones saying his firm is interested in using small modular reactors to replace the combined heat and power systems it uses at its factories. The firm has to produce 10 GW of electricity, heat and steam for its 25 major manufacturing sites around the globe.
Dow is working with X-energy to build four SMRs at its Seadrift facility in Texas, with plans to start construction in 2026 and be operational by 2030.
“The project will provide the Seadrift site with safe, reliable, zero-carbon-emissions power and steam as the existing energy and steam assets reach their end of life,” Stones said. “The project is expected to reduce the site’s emissions by 440,000 MT CO2e/year.”
DUBAI — The energy transition will be messy, but mistakes along the way are essential as the world attempts to solve the complex and broken ecosystem that caused climate change, leaders from the industrial and financial sectors said at a McKinsey panel on the net-zero transition.
The panel took place in COP28’s Green Zone, a short walk from the Blue Zone, where governments and NGOs are negotiating commitments and reporting on progress toward the Paris Agreement.
“The idea of orderly transition is a wrongheaded idea,” said Lord John Browne, managing director of climate growth equity fund General Atlantic and co-founder of BeyondNetZero. “It’s testing and trying: no one has the answer.”
This “test and try” approach to solving the energy transition can be seen in everything from incentives to financial structures to supply chains, he said. Governments and industry make mistakes in almost all aspects of the transition, but a poorly designed incentive with unintended consequences is better than no action at all, and those actions help figure out what does work, he added.
Accepting and embracing the three steps forward, one step back nature of the transition is essential, said Tom Linebarger, former CEO and chairman of Cummins, because without it, “it causes people to wait for the perfect solution, for some technologists to deliver something that’s going to be free for everybody and really perfect.”
“We’re going to be disappointed by the side effects of everything from batteries to hydrogen manufacturing. There are going to be things that we didn’t predict, there are going to be things that don’t work the way we want,” Linebarger said. But “if we don’t get started, we don’t solve those problems.
“The question is, how do you move when you know you’re going to make mistakes? How do you get going to take a step forward? That’s really the challenge in front of corporations, investors, people who are trying to advance the cause.”
Too many corporations wait for the risk to be removed, particularly in industries where commodity prices drive decisions, but Linebarger said companies must act in the short run, with the expectation they’ll learn and win over time.
Investing in the energy transition also means accepting that work will need to be redone over time, Browne said. For example, early wind farms are being redone with more powerful turbines, and solar farms built today will be redone when more powerful panels reach the market.
Even with alignment about the problems and commitments being made by governments at COP28 to solve them, there’s a $2 trillion shortfall of the $4 trillion a year needed to reach climate goals, said Anne Finucane, chair of Rubicon Carbon. “You can figure your way to $2 trillion through the market, just based on 20% equity and 80% financing” that’s typical from banks, private equity firms and asset managers. “The question is what to do about the other $2 trillion.”
Carbon taxes are seen as a necessary tool, but there’s no consensus on whether they should be voluntary or required, and whether voluntary carbon taxes are underpricing carbon.
Panelists said private sector funding alone wouldn’t be sufficient to close the investment gap, and that public and private partnerships are essential. “This is a catalytic moment because it will push governments to do the right thing,” Lord Browne said.
Mapping a Path to Net Zero
The panel coincided with McKinsey’s release of a new report: “An Affordable, Reliable, Competitive Path to Net Zero,” which argues for “not one objective, but four interdependent ones: emissions reduction, affordability, reliability and industrial competitiveness.”
Designing an achievable path is critical, said Daniel Pacthod, senior partner at McKinsey, because the world is far from achieving the Paris Agreement targets. “We’ve seen this in the global stock takes: we’re not going to be remotely close to where we want to be. We are closer to 2.5 degrees in, more than 1.5.”
The report looked at seven principles for decarbonization and said applying two principles — deploying lower-cost solutions and using R&D and other measures to double the expected rate of cost declines — “could substantially improve the current trajectory of emissions and help limit warming to what the Paris Agreement envisions.”
While the potential of a pathway based on those principles is hopeful, the report also warned that “a poorly executed transition could make energy, materials and other products less affordable, compromising economic empowerment. It could also make the supply of energy and materials less secure and resilient, and it could render some countries and companies less competitive. If that happened, progress toward net zero itself could stall.”
