The Biden administration released a plan April 2 to decarbonize the country’s building sector, which it says could reduce emissions in the sector by 65% by 2035 and 90% by 2050.
“America’s building sector accounts for more than a third of the harmful emissions jeopardizing our air and health,” Energy Secretary Jennifer Granholm said. “As part of a whole-of-government approach, DOE is outlining for the first time ever a comprehensive federal plan to reduce energy in our homes, schools and workplaces — lowering utility bills and creating healthier communities while combating the climate crisis.”
Buildings produce more than one-third of domestic climate pollution, and their owners spend $370 billion on energy annually. The blueprint projects cuts of 90% of greenhouse gas emissions from the sector, which would save consumers $100 billion in annual energy costs and avoid an additional $17 billion in annual health costs.
The U.S. is home to 130 million buildings, with another 40 million expected to be built by 2050. Buildings account for 74% of electricity demand, while their heating and cooling drives peak demand across multiple sources.
The blueprint focuses on four key strategies for cutting emissions from the sector: increasing energy efficiency, accelerating on-site emissions cuts, transforming how buildings interact with the grid, and cutting emissions from the materials and process of constructing buildings. It calls for on-site energy use to reach 35% by 2035 and 50% by 2050; cutting on-site emissions by 25% by 2035 and 75% by 2050; tripling demand flexibility on the power grid by 2050; and cutting embodied emissions in building materials 90% by 2050.
“Although the strategy focuses on federal actions that can drive change, it aligns with several state-level decarbonization roadmaps and notes key opportunities for collaboration among federal, state and local agencies,” the blueprint says.
Despite major advances in efficiency and carbon-free electricity, the scale and complexity of the building sector means that its decarbonization remains a significant challenge. The nation’s 130 million buildings all use energy differently and produce different levels of GHG pollution.
“The long lifetimes of buildings and their components mean that today’s buildings will still comprise the majority of the U.S. building stock in 2050,” the report says. “Thus, to achieve this blueprint’s vision, it is critical to accelerate deployment of low-carbon solutions in both new construction and in existing buildings — particularly in disadvantaged communities, where building upgrades are most needed.”
Recent years have seen advances in efficiency, low-carbon space and water heating, and distributed generation, so it is possible to retrofit existing buildings and construct new ones to be much less carbon intensive, the report says.
New Better Buildings Initiative for Heat Pumps
DOE on April 3 also announced a new Better Buildings initiative intended to help heat pump manufacturers produce higher-efficiency and more cost-effective rooftop heat pumps for large, commercial buildings.
“Since 2011, DOE’s Better Buildings Initiative has helped paved the way for cost-effective energy-efficiency and decarbonization solutions across America’s building sector,” Granholm said April 3. “Our new Commercial Building Heat Pump Accelerator builds on more than a decade of public-private partnerships to get cutting-edge clean technologies from lab to market, helping to slash harmful carbon emissions throughout our economy.”
The heat pump accelerator was developed with major commercial end users including Amazon, IKEA and Target, and includes manufacturers such as AAON, Carrier Global, Lennox International and Rheem Manufacturing. Its goal is to bring affordable, next-generation rooftop heat pumps to market as soon as 2027, halving emissions and energy costs compared to natural gas-fueled heat pumps.
Deployed at scale, the advanced heat pumps could save commercial customers about $5 billion on utility bills annually.
Proposed gas supply agreements between Constellation Energy and Massachusetts gas utilities that would keep the Everett Marine Terminal operating through 2030 are facing significant pushback from environmental organizations and the state Attorney General’s Office in time-constrained proceedings at the Department of Public Utilities.
Everett is an LNG import facility located just outside of Boston and is the only facility in the region that can directly import and inject LNG into the gas system. The main customer of Everett, the Mystic Generating Station, is set to retire at the end of May at the conclusion of a two-year cost-of-service agreement with ISO-NE, threatening the future of the import facility.
The impending closure of Mystic has put a looming deadline on finalizing the Everett contracts, which initially were announced in February. (See Constellation Reaches Agreements to Keep Everett LNG Terminal Open.) The gas supply agreements would extend through winter 2030.
Constellation, the owner of both Everett and Mystic, has said it will be unable to keep the terminal open after the plant closes without the contracts, and it can void the contracts if they are not finalized by May 1.
This May deadline has led to expedited regulatory proceedings (DPU 24-25, 24-26, 24-27 and 24-28), in which the AGO and several environmental organizations have raised concerns about the cost and environmental impacts of the agreements.
“Despite taking years to negotiate their gas supply contracts with Constellation, the LDCs [local distribution companies] see … fit to provide the department only two months to conduct a proceeding that would normally take about six months from filing to decision,” the Conservation Law Foundation (CLF) commented in March.
The organization initially was granted “limited intervenor” status in the proceeding by the DPU, allowing it to examine impacts on low-income customers, the consideration of alternatives and environmental justice effects. The status also potentially enabled the organization to eventually appeal the results of the proceeding.
However, the DPU rescinded this status April 1 following a protest from the utilities, which argued that giving CLF the ability to appeal any decision would mean “effectively vesting CLF with the ability to negate or veto a department decision approving the proposed contracts.”
The DPU responded by downgrading CLF to “limited participant” status, which would prevent the organization from appealing the results. Environmental advocates expressed disappointment with the decision and dismissed concerns about a “dilatory appeal.”
A CLF appeal had the potential to threaten the contracts only if the state Supreme Judicial Court (SJC) thought the issues stated in the appeal merited a hearing by the full court, said Joe LaRusso, senior advocate at the Acadia Center. “What the DPU denial of CLF’s intervenor status prevents, then, is CLF filing a meritorious appeal to the SJC and a potential direct challenge to DPU approval of the contracts.”
Cost Concerns
The contracts at issue likely will come at a hefty price for ratepayers; according to Brattle Group consultants hired by the AGO, the contracts would cost a combined $946 million, which ultimately would be passed on to ratepayers.
Brattle estimated $375 million would go to covering Everett’s operating costs, while charges associated with procuring LNG would amount to about $489 million and a third group of charges tied to how much gas actually is delivered to the utilities would be about $81 million.
The latter two charges are indexed and will vary over the course of the contract, but most of the costs (an estimated $864 million) must be paid regardless of how much LNG ultimately is needed.
“The agreements result in very high prices and, therefore, will be costly to Massachusetts ratepayers,” the consultants wrote in testimony submitted by the AGO.
The consultants specifically expressed concerns about the LNG supply costs included in the agreements, noting they “do not provide any transparency into Constellation’s upstream LNG supply costs, which means Constellation may have the ability to build in a markup above its own cost of procuring and transporting LNG cargoes to Everett.”
“The agreements have a pricing formula with poorly explained adders and multipliers that result in significant premiums,” the consultants noted. “The LDCs claim that these adders and multipliers cover the (unknown) costs of LNG procurement and (unexplained) risks faced by Constellation that would accompany its procurement obligations, though they do not know whether this is true and have no way to verify it.”
Climate Consequences
Throughout the proceedings, the utilities have emphasized the agreements are a temporary solution to preserve the reliability of the gas network, which is threatened by the region’s pipeline constraints.
In a statement, an Eversource Energy spokesperson called the contracts “a temporary and necessary solution to maintain reliability during the coldest times of the year and serve as a bridge to the clean energy future.” They also noted the agreements will increase system reliability without requiring any new gas infrastructure or pipeline expansions.
However, environmental advocates in the state are worried the agreements ultimately could function as a bridge to an expanded gas network, instead of decreased gas demand.
National Grid and Eversource, the two largest gas utilities in the state, project natural gas demand to continue to grow in the leadup to 2030. A recent DPU order and state climate laws passed in recent years are intended to reverse this trend. (See Massachusetts Moves to Limit New Gas Infrastructure.)
National Grid’s contract with Constellation would authorize the utility to purchase increasing quantities of gas through 2030, with the maximum seasonal quantity more than quadrupling between the winter of 2024/25 and the winter of 2029/30.
“I would suggest these contracts are not some stopgap measure but a continuation of the gas industry’s playbook to ensure a transition off gas does not happen in our commonwealth,” Cathy Kristofferson, secretary and treasurer of the Pipe Line Awareness Network for the Northeast, said at a public hearing.
In September, Enbridge announced a new project to significantly increase the capacity of its Algonquin Gas Transmission Pipeline network from New York to Massachusetts with an in-service date of late 2029. (See Enbridge Announces Project to Increase Northeast Pipeline Capacity.) Eversource has confirmed it offered a bid for capacity in the open season for the project, while National Grid has not responded to multiple inquiries into whether it also bid into the open season.
“It is not lost on some of us that the six-year contract length sought in these proceedings coincides with the six-year in-service time frame forecast by Enbridge for their Project Maple” expansion, Kristofferson added.
Enbridge submitted comments in favor of the Everett agreements, writing that “New England continues to be underserved by natural gas.”
“The New England region requires additional natural gas infrastructure to maintain reliability, deliver energy affordability and help the region achieve its policy goals with respect to greenhouse gas emission reductions,” the company added.
Priya Gandbhir, senior attorney at CLF, said a prolonged reliance on natural gas is “not an acceptable path forward” and echoed concerns about Enbridge’s capacity expansion proposal.
“If these contracts are going to be approved, it needs to be on the way to our clean energy future,” Gandbhir said, adding that the proceeding underscores the need for holistic energy planning in the state. “I remain very skeptical that the intent of the LDCs is to use this as a bridge to clean energy.”
The U.S. electricity grid is often described as one of the greatest and most complex machines ever built. Hundreds of thousands of miles of wires connect our nation’s homes and businesses to our domestic energy resources, helping drive American prosperity and security over the last century.
But like any aging machine — particularly one designed to meet 20th century needs — some of its components are no longer operating efficiently. And these inefficiencies are costing American consumers on their utility bills and threatening access to reliable electricity.
Nora Mead Brownell |
Existing connections between grid regions are simply not utilized as well as they should be.
The power grid is generally broken up into regions. Regional grid operators rely primarily on power plants in their service areas to generate enough electricity for homes, schools, hospitals and businesses. The supply of power must meet demand at any given time to maintain grid stability and to keep the lights on.
There are also power lines that connect these regional networks, so a home in Cleveland may receive electricity generated by a wind farm outside Des Moines. This is especially beneficial for the Ohio homeowner if that wind farm is producing the cheapest power at that time. And this interregional connection is even more important if a winter storm forces several power plants in Ohio to stop operating. That transmission line will carry critical electricity needed to keep the heat and lights on in homes hundreds of miles away.
The value of interregional transmission capacity was especially evident during the deadly cold snap in February 2021 that slammed the central U.S. While Texas’s isolated grid was forced to shut off power to millions of people, grid operators in the Midwest and Great Plains avoided widespread outages by importing 15 times more electricity than Texas through interregional lines.
But the U.S. has few of these interregional power lines. And we are not using the existing capacity very efficiently. While new electricity-carrying lines are needed, they often can take up to a decade to plan and build because of complex siting and planning processes. As a result, it’s important to maximize the use of the existing system.
Regional grid operators have a clear opportunity to optimize the existing interties they share with neighboring regions. In fact, for nearly two decades, the oversight bodies that monitor Eastern regional grid operators have recommended that they do just that. It’s now well documented that the inefficient use of these connections continues to increase system costs and reduce reliability.
At times, despite the cost of power being significantly higher in one region than the other, electricity will flow from the more expensive market to the lower-priced market, raising system costs. In the Mid-Atlantic, this costly phenomenon occurred 48% of the time in 2022, according to the PJM Market Monitor. In the Midwest, MISO’s Monitor determined that more than 40% of transactions between its neighboring regions were “ultimately unprofitable” in 2021.
But some U.S. grid regions are using these interregional connections more efficiently. In the West, markets have optimized their interties, saving more than $4 billion since the inception of system changes almost a decade ago.
Optimizing the use of existing or new interregional transmission capability between grid operators in the Midwest, Plains and Mid-Atlantic would provide approximately $50 million to $60 million annually for every 1,000 MW of intertie capacity, according to recent analysis by the Brattle Group.
The failure to optimize interties means existing power infrastructure is underutilized, and the benefits of interregional transmission are not fully realized. Thus, there is less of an incentive to build the future interregional transmission lines our country desperately needs to ensure consumers can access clean, affordable power at all hours. Recent studies have shown that the U.S. needs to dramatically hasten the pace of interregional transmission line deployment to meet future electricity demand.
There are several paths FERC can take to improve the efficiency of the existing interregional system. FERC can require intertie optimization under existing federal law or act on a request from a regional grid operator. Given the well-documented savings that improving current inefficiencies would generate, the commission is well within its authority to require grid operators to optimize their interties.
We’re long overdue to optimize the capacity currently available. Doing so will enhance the grid today and help ensure that future investment efficiently powers America through the 21st century.
Nora Mead Brownell served on the Federal Energy Regulatory Commission from 2001 to 2006 and now serves as a Venture Partner at Clean Energy Venture Group.
February held no operational surprises, MISO reported this week in a monthly market review.
The grid operator said there were “no notable events” to wrap up winter. MISO experienced an 80-GW average peak over the month, with an 88-GW peak occurring Feb. 19.
Real-time locational marginal prices averaged $22/MWh, about in line with February 2023’s $23/MWh but a far cry from 2021’s $61/MWh. The reduction is predicated on the return of $2/MMBtu natural gas.
MISO’s coal use this February, 11.2 TWh, was nearly halved compared to February 2021’s nearly 22 TWh. Natural gas and wind generation compensated for the drop in coal generation.
MISO’s growing solar fleet again registered record production Feb. 24 when it briefly supplied 7% of load at 4.6 GW. MISO has been setting solar generation records nearly every month as members add installations at a record clip.
Daily generation outages were up year-on-year, with MISO reporting a 43-GW average outage rate over the month, higher than last year’s 32-GW average for the same period.
MISO has selected Ameren Transmission Co. of Illinois (ATXI) to build a third transmission project stemming from the RTO’s long-range transmission portfolio.
ATXI will oversee construction of the $273 million Denny-Zachary-Thomas Hill-Maywood (DZTM) 345-kV project in Missouri, part of MISO’s first, $10 billion long-range transmission plan (LRTP) portfolio. It’s the most expensive project MISO has evaluated for competitive selection.
It’s the third time MISO has opted for ATXI after LRTP project solicitations. In December, MISO decided Ameren’s transmission arm will build a $23 million, 345-kV line segment from the Iowa-Illinois border to the Ipava substation in Illinois. (See MISO Selects Ameren, Dairyland to Build 3rd and 4th LRTP Competitive Projects.)
Last year, MISO also awarded ATXI construction rights on the $84 million, 345-kV Fairport-Denny project, which extends to the Iowa-Missouri state border and links up with the DZTM project. (See MISO Selects Ameren to Build 2nd Competitive LRTP Project.)
MISO’s DZTM selection announcement marks the final time MISO will compare bids on a competitive project from the first LRTP portfolio. Only five of the 18 projects were up for competitive solicitation.
MISO said ATXI “conducted the most engineering and surveying of any developer, and its routes had the least environmental impact.”
“It also more clearly detailed its construction activities and access plans, and showed how it could modify construction activities based on the in-service date of Denny substation,” MISO wrote in the selection report.
MISO said it received six proposals from four developers, including two from ATXI and the remainder from LS Power, NextEra Energy Transmission Midwest and Transource Energy, with implementation costs ranging from $265 million to $486 million. MISO originally estimated project costs would exceed $500 million. ATXI was the only developer that offered to cap project costs, MISO said.
“The selected proposal had a substantially lower cost than that of the next-closest developer,” Jeremiah Doner, MISO’s director of cost allocation and competitive transmission, said in a press release. “ATXI’s proposal also features strong cost containment, sound design, and robust operations and maintenance plans.”
The DZTM project encompasses two new single-circuit 345-kV transmission lines at 162 miles and a new, 42-mile 345-kV conductor-only circuit that will share structures with an existing 161-kV line. The project will connect four substations.
As with its Fairport-Denny project, ATXI’s DZTM proposal includes a partnership with The Missouri Joint Municipal Electric Utility Commission. ATXI plans to sell 49% of the project to the state utility agency before the project is placed into service.
SPP’s effort to impose new capacity accreditation methodologies for thermal and renewable resources has drawn protests from public-interest and clean-energy groups at FERC.
On March 29, the Sierra Club, Natural Resources Defense Council and Sustainable FERC Project challenged SPP’s proposed performance-based accreditation (PBA) for thermal resources, arguing it would threaten reliability by ignoring fossil-fired resources’ underperformance and renewables’ overperformance when power is needed most (ER24-1317).
The groups also filed a complaint under Federal Power Act Section 206 over existing accreditation methodologies for the resources SPP is trying to replace. They said the RTO’s current and proposed capacity accreditations create a competitive disadvantage for wind and solar and will increase prices for ratepayers as utilities are “artificially incentivized to overbuild gas resources and delay coal retirements.”
“Regulators at the federal and regional level must make sure that critical resource assessments are made based on the facts and that all resources are evaluated on a level playing field,” said Natalie McIntire, senior advocate at the Sustainable FERC Project and a member of SPP’s Members Committee. “Accurate accreditation will help ensure a reliable and more affordable grid and allow renewable resources to contribute to a clean, reliable and resilient electrical system.”
The Sierra Club said clean energy advocates have been pushing SPP to fix its accreditation methodologies, which it calls discriminatory and outdated, since at least 2021. It said the parallel filings were intended to avoid a return to the status quo and SPP’s flawed stakeholder process.
Separately, the American Clean Power Association, Solar Energy Industries Association, Advanced Energy United and Advanced Power Alliance also filed a protest urging the commission to reject the proposal. They said SPP’s filing included unjust and unreasonable design features, missed crucial information in violation of FERC’s rule of reason and unduly discriminated against IBRs.
SPP filed its proposed tariff revisions at FERC in February. They included an effective load-carrying capability (ELCC) methodology for wind, solar and energy storage resources. The grid operator also laid out the calculation to determine the metrics, a variant of the equivalent forced outage rate method.
The RTO’s proposal to use a different calculation for thermal resources is an “improvement on the status quo,” the renewable interests said. “However, this change alone (and taken in concert with SPP’s ELCC proposal) cannot meet SPP’s statutory burden to ensure that its filing is just and reasonable, and not unduly discriminatory.”
SPP said that accrediting resources is “critical” to its resource adequacy program, which FERC approved in 2018.
“It is not enough to have sufficient nameplate generation installed; the region needs assurance that such capacity will deliver at an expected output when the output is needed most,” SPP said, noting that grid operators have established accreditation methods valuing the resource adequacy contributions of different resource types.
SPP asked that FERC issue an order by May 23 and set an effective date of Oct. 1, 2025, for the methodologies’ implementation.
Members Endorse Controversial IBR Rule over ERCOT’s Objections
AUSTIN, Texas — ERCOT stakeholders overrode the ISO’s objections to push through a potential rule change on inverter-based resource (IBR) ride-through requirements after months of negotiations failed to bring a compromise.
The action sets up a likely appeal from ERCOT and further discussion on the controversial measure when the ISO’s Board of Directors meets April 22-23.
The Technical Advisory Committee endorsed the Nodal Operating Guide revision request (NOGRR245) during its March 27 meeting with amended language from joint commenters.
The language was “carefully crafted” to “reach a solution that properly balances risk mitigation with economic, technological and operational realities,” the commenters said. “Requirements that are technically infeasible or impracticable to meet (particularly for existing resources) do not benefit Texas consumers or the ERCOT market and do not improve grid reliability.”
The NOGRR is intended to align the grid operator’s rules with NERC reliability guidelines and the most relevant parts of the Institute of Electrical and Electronics Engineers’ standard for IBRs interconnecting with the grid. Two IBR-related voltage disturbances in West Texas in 2021 and 2022, dubbed Odessa Disturbances I and II, have added urgency to the measure’s eventual passage. (See NERC Repeats IBR Warnings After Second Odessa Event.)
Stakeholders have proposed software changes to fix the issues NERC and ERCOT have identified. They have said ERCOT’s proposals, if approved, “will implement the nation’s most aggressive ride-through performance requirements to date.”
The NOGRR passed in an 18-8 vote (69%), with three members abstaining. Two previous attempts to pass motions by stakeholders and then ERCOT failed.
“Thankfully, TAC rolled its sleeves up and refused to keep going without a compromise they could actually carry a motion on,” Arushi Sharma Frank, Tesla’s U.S. energy markets counsel and policy lead, posted on X.
The breakthrough followed hours of discussion during the meeting, a sidebar between staff and stakeholders during lunch and then an additional tweak of the stakeholders’ initial proposed revision to the motion.
ERCOT’s Stephen Solis, a principal for system operations improvement, said the modification to NOGRR245 only made things worse. Solis frequently emphasized the risks to reliability during the day’s discussion. In comments filed in January, ERCOT expressed concerns about implementing “technically infeasible” requirements that could force retirement of too much IBR capacity.
“This worsens reliability from even where we’re at today, because at least today, with the current ride-through requirements, [if] you fail, you have to go to the [Public Utility Commission]. You have to mitigate it. You have to fix it,” he said. “We are putting in a construct that reduces [the requirement]. That is worsening reliability, from ERCOT’s perspective.”
Solis said ERCOT’s comments were ignored during the sidebar discussions with stakeholders.
“[NOGRR245] is moving forward with a concept that because we went into a room with them, that somehow this has ERCOT’s input. ERCOT’s input was to make other modifications, which they denied to make right now,” he said. “This has not changed anything. They have basically thrown a bone about language that is in ERCOT’s current proposed language that they already had agreed to in the [stakeholder] discussions that we had, but they didn’t include it.”
Consultant Eric Goff, representing consumers and the joint commenters, said he didn’t want to get into a “back and forth” with ERCOT. He said stakeholder comments were based on ERCOT comments filed in January but not those filed March 26, given the lack of time. However, Goff said he was open to beginning a conversation with the joint commenters to see whether they could improve their comments by working off ERCOT’s latest filing.
“The goal here is to strike some type of balance. I understand that balance isn’t completely acceptable to ERCOT, but I think it’s important for the stakeholders’ voice to be heard,” Reliant Energy Retail Services’ Bill Barnes said. “I share a lot of concerns with ERCOT on the risk to reliability, just as much as the impact to existing resources is a very heavy issue the board needs to weigh in on.”
The NOGRR was drafted by ERCOT last year and granted urgent status in September. After working its way through the stakeholder process and reaching TAC, it was tabled in January when the ISO’s staff and stakeholders failed to reach consensus. The parties have been involved in negotiations since then. (See “Stakeholders Continue Discussion of IBR Reliability Requirements,” Technical Advisory Committee Briefs: Jan. 24, 2024.)
“I do think that that is in everyone’s best interest to continue to work together with ERCOT to potentially avoid an appeal. I don’t think it’s a good look to have two appeals go to the ERCOT board,” Barnes said. “I value the stakeholders’ opinion enough to get over the hangups that [Reliant] has so we can send a version to [the board] for its consideration and ERCOT can present their appeal if they wish to do so.”
“I’m less concerned with the optics on how it looks to [the board] than getting everybody’s actual position on record,” Jupiter Power’s Caitlin Smith said, speaking for her company and not in her role as TAC’s chair. “I’d hate to say we voted X way or Y way because we didn’t like the way two appeals would look to them than not get everybody’s real point of view on paper.”
“I think that the outcome of the two appeals presents more of a divided view than I think really exists, at least from our company’s point of view,” Barnes said.
ERCOT Reviews Price Corrections
Staff told the committee they will ask the board to approve two price corrections to real-time prices during its April meeting. An analysis of the errors’ effect on the market met the criteria for review when any single counterparty’s absolute value effect is either 2% and greater than $20,000 or 20% and greater than $2,000.
In January, ERCOT’s energy management system (EMS) retained outdated transmission line data during the weekly model builds, affecting three operating days. Staff fixed the software to ensure correct static ratings were used in the models.
The issue resulted in $1.64 million in additional payments to market participants and a $2.84 million impact on counterparties.
During routine maintenance Feb. 28, the process that exports constraint data from the EMS to the market management system sent incorrect constraint data for generic transmission constraints to the dispatch process. The second correction will return $277,930 to ERCOT.
Ögelman Extends ERCOT Service
Kenan Ögelman, ERCOT’s vice president of commercial operations, has extended his retirement date by a month and now will step away from the ISO at the end of April. (See “Ögelman to Retire from ERCOT,” ERCOT Board of Directors Briefs: Feb. 26-27.)
“I have not seen the [reliability must-run] determination for Kenan’s retirement,” Barnes joked.
Smith teasingly suggested discussing Ögelman’s final appearance before TAC during its April 15 meeting, leading Ögelman to fire back.
“You might need a [must-run alternative] for that,” he said, referring to ERCOT nomenclature for replacing a retiring resource’s capacity.
Indeed. Ögelman has scheduled a trans-Pacific Ocean trip a couple of days after he steps away from ERCOT.
TAC Passes Rule Changes
Members endorsed a nodal protocol revision request (NPRR1197) that enables resources to separately meter and settle loads located behind the ERCOT-polled settlement meters at their points of interconnection. South Texas Electric Cooperative voting against the measure over concerns it codifies into protocols the metering situation it had attempted to prohibit in the recently rejected NPRR1194.
They also endorsed a change to the Retail Market Guide (RMGRR177) that clarifies a customer’s lease agreement option when a competitive retailer tries to remove a switch hold applied to a premise it is seeking to enroll. The Office of Public Utility Counsel (OPUC) and residential customers abstained from the vote.
The consent agenda included goals for the Reliability and Operations and Wholesale Market subcommittees and NPRR1205 that, if approved by the board and the PUC, would “strengthen ERCOT’s market entry eligibility and continued participation requirements counterparties by clarifying minimum credit quality qualifications for banks that issue letters of credit on behalf of market participants and insurance companies that issue surety bonds on behalf of market participants.”
Last year’s GridEx VII security exercise demonstrated the importance of communications in maintaining grid reliability along with the need for continued discussions between industry and government on prioritization of loads during system restoration, NERC said in its report on the exercise released this week.
The Electricity Information Sharing and Analysis Center (E-ISAC) conducted GridEx VII from Nov. 14 to 16, 2023. The exercise comprised a distributed play portion, held during the first two days and involving more than 15,000 individuals from 252 participating organizations. Additionally, an executive tabletop was held on the third day with about 230 attendees from 75 organizations, including electric utilities; U.S. and Canadian government agencies and law enforcement; and representatives from the oil and natural gas, telecommunications, finance and nuclear industries.
GridEx VII marked the second exercise in a row to see a decline in organizations participating in the distributed play from the previous event: 293 organizations took part in the distributed play in 2021, and 526 in 2019. (See NERC ‘Very Happy’ With GridEx VII Participation.)
Of the organizations in the distributed play, 174 represented electricity asset owners or operators; 55 were government or “other”; 17 were reliability coordinators; and six represented the regional entities. All categories of participants were up or steady from last year except for government/other; 105 groups from this category took part in GridEx VI in 2021
NERC acknowledged the change in participation in its report while observing that the number of individuals taking part seemed to have increased significantly from the 3,000 estimated for GridEx VI. As in previous years, the number of individuals taking part was estimated based on responses in the after-action report.
The ERO attributed the participant decrease to the continuing impacts of the COVID-19 pandemic, as well as the requirement — implemented for GridEx VI — that participating entities must be E-ISAC members. NERC also noted that participating organizations may have coordinated their exercise play with unregistered entities, whose participation the E-ISAC could not track.
Organizations participating in the executive tabletop also fell from 88 participants in GridEx VI; however, the 230 individuals attending represented an increase from nearly 200 in the last exercise.
Cyber, Physical Attacks Hit Hard
The distributed play scenario was developed by the E-ISAC and customized by participants, so details of the exercise varied between entities. However, the outlines were shared by all.
The game consisted of five “moves.” It actually began over the week prior to the exercise, with Move 0 consisting of threats injected according to the “organizational objectives” of participants. Moves 1 to 4 comprised the core exercise over Nov. 14-15:
1: Cyberattacks and ransomware hit utilities’ communication software, internal information technology networks and third-party systems that operate the electricity markets. Additionally, disruptions to natural gas supply reduce generation capacity.
2: Attackers launch a coordinated physical assault against multiple substations, with gunfire targeting critical transformer components. A social media misinformation campaign and further cyberattacks hamper utilities’ responses.
3: As recovery gets underway, further attacks occur at telecommunications facilities. Protesters, frustrated by the ongoing power outages, begin to harass utility personnel. Attackers detonate explosives at equipment storage and staging areas, damaging equipment needed to restore service.
4: The game jumps forward a week after the attacks, and players consider long-term recovery challenges. Issues such as fuel and equipment shortages were highlighted, with entities having “to rely on their current inventories.”
NERC developed a set of recommendations from after-action surveys, feedback during exercise design and other engagement data.
First, NERC suggested that electric utilities continue to engage proactively with nonfederal government partners on emergency response plans. The report authors mentioned feedback from one planner who normally coordinates with county emergency managers but “realized [during GridEx VII that] it was not feasible to communicate individually with each county … in an incident that spanned many counties.”
NERC also noted the trend of declining participation by government entities. Observing that incident response “will likely require involvement from government partners at all levels,” the ERO urged municipal and state governments to step up participation.
The report also called on utilities to improve their communication and response measures in light of changes to work habits caused by the COVID-19 pandemic. Because gathering all responders together into a single room is not as feasible as it once was, it is important that utilities update their plans to account for a more distributed workforce.
NERC highlighted a comment from one planner that the simulated public unrest rendered the location intended for an in-person response inaccessible. The planners’ organization decided that a secondary location must be identified and added to emergency response plans in the future.
Additional recommendations related to communication of technical information across critical stakeholders, along with the E-ISAC’s support for organizations of varying sizes and levels of experience. Participants provided positive feedback on the inclusion of Move 4 and its focus on long-term consequences of the previous days’ events.
The distributed play portion of the exercise took place across Nov. 14 and 15 and consisted of four moves, plus a preliminary move the previous week. | NERC
Communications Struggle in Executive Tabletop
The executive tabletop also comprised four “acts,” with facilitators leading participants “through discussions designed to simulate the communication and coordination during a real event.”
1: A cyberattack compromises utilities’ inter-control center communications protocol (ICCP) software, through which grid operators receive data from transmission and generation facilities. Operators had to use alternate and manual methods and “suspend the electricity market systems that automatically dispatch and price generation.” Voice and data communications networks fail across a large swath of the country as well.
2: Coordinated cyber and physical attacks damage transformers and other equipment at substations in Louisiana and Texas. This leads to power outages at natural gas hubs.
3: Cyberattackers compromise and deface MISO’s website, demanding ransom. Backup systems are corrupted, and critical IT staff members cannot be reached.
4: One month later, ICCP telemetry is mostly restored, but MISO’s electricity market systems still are suspended, damaged substation equipment is not yet fixed and power has not been restored to natural gas facilities.
Recommendations from the tabletop included evaluating technology and processes to increase ICCP communication resilience. NERC emphasized that ICCP systems already are “highly reliable, supported by layers of redundant infrastructure and cybersecurity protections.” But the ERO said the exercise prompted participants to ask if the systems are adequately protected against certain vulnerabilities and if alternative measures would help secure the system.
NERC also suggested the industry study communication alternatives between grid operators, which could be needed if automated telemetry becomes unavailable or compromised. In addition, the ERO said industry and government should discuss whether utilities’ established restoration procedures conflict with government priorities during sustained, complex outages. Finally, NERC urged the industry to evaluate how to manage the reliability impacts of extended market system or data unavailability.
“Today’s threat landscape is dynamic, presenting challenges that are increasingly difficult to detect and protect against,” Manny Cancel, senior vice president of NERC and CEO of the E-ISAC, said in a statement. “The scenario created for GridEx VII reflected this by testing the collective ability of industry, government and cross-sector partners to restore the grid under the most extreme circumstances. … I am encouraged that several participants have already begun to implement some of the recommendations in their organizations.”
Many recent projections for energy use have fossil fuel use plateauing after 2030, when it needs to rapidly decline to meet midcentury carbon targets, Resources for the Future said April 2 in a new report.
The study — “Global Energy Outlook 2024: Peaks or Plateaus?” — reviews projections on the future of energy use and production from entities such as the U.S. Energy Information Administration, the International Energy Agency, the Organization of the Petroleum Exporting Countries and oil firms. They all use different scenarios, but RFF applied a detailed harmonization process comparing 16 scenarios across eight outlooks published last year, as well as two historical sources.
Even the scenarios that limit temperature change to 1.5 degrees Celsius by 2100 have substantial fossil fuel consumption through 2050, which suggests that a phaseout by then is not a prerequisite to achieving international climate goals.
“World primary energy demand has experienced a series of energy additions, not energy transitions, with newer technologies such as nuclear, wind and solar building on top of incumbent sources such as biomass, coal, oil and natural gas,” the report says. “To achieve international climate goals and limit warming to 1.5 C or 2 C by 2100, a true energy transition is needed.”
The scenarios in the report suggest that although a transition is needed, fossil fuels will not have to be eliminated. If fossil fuels are not phased out, the world will need to scale up carbon-removal technologies such as direct air capture; carbon capture, utilization and storage (CCUS); and nature-based solutions, all of which require robust monitoring and verification.
As of 2022, 42 million metric tons of CO2 were captured internationally — just 0.1% of annual global emissions, but a tripling of the technology since 2010, a compound annual growth rate of 8.7%. That growth is already on pace for some of the scenarios, but with more ambitious climate policies, the technology would need to grow by nearly 20% a year.
“Are these growth rates achievable? Technically speaking, the answer is ‘yes,’” the report says. “CCUS infrastructure and underground storage reservoirs are more than adequate to handle these volumes of CO2,” the report says. “However, the future costs of deploying these technologies, including to relatively novel sectors such as electric power generation (Most CCUS today is used in the industrial sector.), are not well understood.”
The scenarios all have the global economy becoming more efficient, so energy demand grows slowly or declines under almost every scenario. In the ambitious climate scenarios, demand can drop as much as a third by midcentury.
While overall energy demand drops, the scenarios all show significant growth in the global demand for power. At the end of 2019, electricity was roughly 20% of final energy consumption, but it grows up to 50% by midcentury in aggressive scenarios.
“This growth enables electricity to become a larger provider of energy services across the economy, particularly in the buildings and transportation sectors,” the report said.
Coal declines in all scenarios, while natural gas demand is mixed, with half the scenarios showing growth and the other half showing declines.
“Wind and solar grow faster than any other sources in percentage terms under all scenarios, but with a wide range,” the report said.
Wind and solar have represented about 75% of global capacity additions in the past decade, with solar growing at 10% a year from 2020 to 2022 — 320 GW per year. To reach 11,000 GW by 2030, as some scenarios call for, solar deployment would need to ramp up to 800 GW annually.
The nations of the world have committed to tripling nuclear energy by 2050, but that would require a fundamental change in the trajectory of the technology in developed countries, of which 12 out of 22 have seen declines over the last decade. Most scenarios have the technology growing modestly, with only two having it triple.
The Bureau of Ocean Energy Management (BOEM) issued its final Record of Decision (ROD) approving Avangrid Renewables’ New England Wind project on April 2, marking a major milestone for the proposed offshore wind project.
The New England Wind project is separated into two phases, which could total up to 2,600 MW of nameplate capacity. Neither phase of the project is under contract to be built, but Avangrid recently bid the project into Connecticut, Massachusetts and Rhode Island’s coordinated offshore wind solicitation. (See New England States’ OSW Procurement Receives 5,454 MW in Bids.)
The project is essentially a rebranding of the recently cancelled Commonwealth Wind and Park City Wind projects. (See Park City Wind to Cancel PPAs, Exit OSW Pipeline and Commonwealth Wind PPA Cancellations OK’d.) It would be located adjacent to the under-construction Vineyard Wind 1 project, on a lease area about 23 miles south of Martha’s Vineyard.
The ROD marks the Biden administration’s eighth offshore wind project approval, totaling more than 10 GW of approved capacity.
“Today, we celebrate the incredible progress being made toward achieving our goal of 30 gigawatts of offshore wind energy capacity by 2030,” said Secretary of the Interior Deb Haaland in a press release. “The New England Wind project will help lower consumer costs, combat climate change, create jobs to support families and ensure economic opportunities are accessible to all communities.”
Liz Burdock, CEO of the Oceantic Network (formerly the Business Network for Offshore Wind), celebrated the decision and praised the recent offshore wind permitting steps taken by the Biden administration.
“BOEM is crushing it,” Burdock said. “With the first projects nearing completion, two set to begin major construction this summer and more following in quick succession, a consistent construction pipeline is fostering the industry’s growth, creating opportunities for U.S. businesses to thrive and workers to develop critical skills.”
Representatives of environmental organizations including the Environmental League of Massachusetts, the Sierra Club and the Nature Conservancy also praised the decision.
“It is now well documented that Cape Cod and its adjacent ocean waters are among the very fastest-warming locations in the world, adding further urgency for Cape Cod’s transition to a sustainable energy future,” said Dorothy Savarese of the Cape Cod Climate Change Collaborative. “Offshore wind is an absolutely essential component of that vision.”
According to the federal permitting dashboard, the project is on track to complete the federal permitting and environmental review process by the beginning of July.
Avangrid CEO Pedro Azagra applauded the Biden administration for issuing the ROD and called the project “the most advanced and shovel-ready offshore wind opportunity in the Northeast region.”
While Avangrid backed out of power purchase agreements for earlier iterations of the project due to growing economic pressures, the states hope bid indexing will help account for future inflationary pressures and push the next cohort of offshore wind projects across the finish line.
The company has indicated New England Wind could reach commercial operation by 2030 if it is selected in the New England states’ coordinated solicitation. The states’ decisions on bids are due by Aug. 7.
