Weatherization efforts and energy efficiency policies will effectively mitigate an increase in home cooling demand in New York City, according to a new report due for release this month.
Community solar projects are also effective in absorbing excess load hitting the grid as equity cooling programs are outfitting more low-income apartments with air conditioners, the report from consulting firm Guidehouse found.
New York’s Home Energy Assistance Program (HEAP), which helps low-income residents pay the cost of heating their homes, will open a cooling assistance benefit in May 2022. Single residents with a maximum gross monthly income of $2,729, or families on a similar scale outlined in the requirements, can receive a free air conditioner if, because of medical conditions, they could benefit from cool air.
The combination of rising summer temperatures and the “heat island” effect in the city can create unbearable temperatures in apartments without air conditioning, especially those without any airflow, said Dan Rieber, weatherization director of the Northern Manhattan Improvement Corporation (NMIC), during a webinar hosted by the Northeast Sustainable Energy Association on Thursday.
The nonprofit serves as a provider and installer of air conditioning units for programs like the one HEAP is opening under the New York Office of Temporary and Disability Assistance.
Landlords in New York City are required to provide heat and hot water as part of the rental price, but not cooling services. One apartment where NMIC installed an air conditioner was about 89 degrees when the workers arrived, Rieber said.
The city also created a program to provide 74,000 air conditioners to people over 60 during the COVID-19 pandemic.
Cooling Demand
Rising summer temperatures will increase electricity consumption for air conditioning by 17% per household in New York City by 2050, Jim Young, an associate director at Guidehouse, said during the webinar.
However, with advanced building technologies and energy efficiency policies, the cooling load placed on the grid will be 14% less per home in 2050 than what it is now, Young said.
“Direct building measures such as higher efficiency AC, strengthening building envelopes and using cool roof technology have the most significant impact on reducing load,” he said.
Extending cooling access to vulnerable populations would cost between $170 million and $260 million over the next 30 years, Young said, but the benefit of avoiding heat-related medical issues will save the city at least $173 million.
Even with an increase in population and extending cooling to the current remaining non-air-conditioned housing stock in New York City, the residential cooling impact on the grid is relatively minor with a load increase of between 1% and 2%, according to the report.
While networked heat pumps would help mitigate increased strain on the grid and provide a zero-emission solution, air or ground source heat pumps should only be pursued “where they make sense,” Young said. Low-income residents should not have a longer wait time because of cost or construction barriers to get the help they need, he said.
Activists and consumer advocates in New York want to see less industry influence on the state’s clean energy policy recommendations and a greater focus on environmental justice.
The New York State Climate Action Council’s Waste Advisory Panel “was tilted to industry and appeared to be less focused on slashing global warming emissions than on advancing industry interests,” Eddie Bautista, executive director of the New York City Environmental Justice Alliance, said Friday.
“While the Department of Environmental Conservation staff was helpful and discouraging the most audacious industry proposals, they decided to submit a long list of possible initiatives … rather than identify the top five priorities that would provide the biggest climate benefits,” Bautista said.
The Council on Friday heard feedback from the Climate Justice Working Group (CJWG) on policy recommendations from the Waste Advisory Panel, the Energy-Intensive and Trade-Exposed Industries Advisory Panel, and the Just Transition Working Group.
The 22-member Council is working to complete a scoping plan by year-end to help reach the environmental goals laid out in the state’s Climate Leadership and Community Protection Act (CLCPA).
Ending the disposal of food scraps and yard waste at landfills and incinerators is probably the single most important action the state could take to cut emissions from the waste sector, Bautista said. (See Public Wants Tweaks in NY Food Waste Handling Rules.)
Prohibiting landfill disposal is the first step since landfills are the third-largest source of methane emissions in the nation according to the EPA, and the associated heavy truck traffic also harms public health, he said.
“And sending organics to incinerators leads to additional air contaminants and is inconsistent with the state’s environmental justice goals,” Bautista said.
“I don’t think all industry is bad; I think we work hard to clean the environment and that waste-to-energy facilities provide a useful tool to reduce organic pollution,” said Gavin Donohue, CEO of the Independent Power Producers of New York. “I do appreciate what [Bautista] wants here, I just have some issues with some of the facts, that’s all.”
Bautista said that in terms of waste-to energy, he didn’t think incineration was considered a renewable energy resource, but Donohue said that it is covered under the CLCPA, though not under Public Service Commission regulations or the state’s Clean Energy Standard.
Demand-side Changes
The Council also received a brief review of the Sixth Assessment Report of the United Nations Intergovernmental Panel on Climate Change from Amanda Stevens, senior project manager at the New York State Energy Research and Development Authority. (See Too Late to Stop Climate Change, UN Report Says.)
“The global occurrence of extreme weather events is unprecedented and such events will continue to increase in severity and frequency,” Stevens said. “In particular, emissions of greenhouse gases are not slowing down, and the global rate of emissions was higher in the past decade than at any other time.”
Though the Energy-Intensive and Trade-Exposed Industries Advisory Panel’s recommendations make little mention of specific technologies or energy sources, the CJWG wanted to see more attention given to methods that would allow the energy sector to continue to pollute, such as carbon capture and storage (CCS) and low-carbon fuels, said Abigail McHugh-Grifa, executive director of the Climate Solutions Accelerator of the Genesee-Finger Lakes Region.
The panel’s priorities may require reevaluation in terms of what should be promoted as industry solutions under the CLCPA, McHugh-Grifa said.
“We recommend strongly emphasizing demand-side changes such as process efficiency, materials recycling, materials substitution, waste reduction and improved product longevity,” McHugh-Grifa said. “Fossil fuel combustion for industrial heat should be greatly reduced, replacing it with electric heat whenever feasible.”
For industrial processes in which electricity is not viable, such as cement production, green hydrogen is a potential alternative, she said.
“However nearly all hydrogen commercially available today is produced from fossil fuels, and so-called blue hydrogen produced from fossil fuels but using CCS to reduce emissions could actually result in net increases in greenhouse gas emissions compared to burning gas or coal,” McHugh-Grifa said. “And I’ll just note that the Climate Action Council’s very own Bob Howarth has done some excellent research in this area. (See NY Study Highlights Rising Methane Emissions.)
Bob Howarth, Cornell University professor of ecology and environmental biology, pointed out that Sweden now has an operating plant that uses mostly renewable electricity to make steel.
“All of the heating is coming from electricity. They’re using a tiny bit of hydrogen just as a chemical reactant in it, but they’re using about 2% of the amount of hydrogen that they would have been using for the heating,” Howarth said. “So, the technologies are changing rapidly, and I would encourage us to pay attention to that changing world in which we live and begin to do everything we can to make sure we minimize the use of all hydrogen.”
This latest IPCC report placed a heavy emphasis on methane, which supports the CLCPA accounting approach. The IPCC report says that, to date, methane accounts for 0.5 degrees Celsius of all global warming, compared with 0.75-degree attributable to CO2, Howarth said.
“At a minimum, hydrogen proposals should be subject to review and possible denials under Section 7 of the CLCPA prohibiting state actions that impose disproportionate pollution burdens on environmental justice communities,” McHugh-Grifa said.
Elizabeth Yeampierre, executive director of UPROSE, Brooklyn’s oldest Latino community-based organization, pointed to the “precautionary principle,” which says that when scientific evidence on potentially harmful actions by industry or government is uncertain, public health decisions must be made in favor of prevention.
“So, the goal and the idea that the scientists and the environmental justice movement had is that from soup to nuts, from beginning to end, the process has to be one that builds, that enhances, that honors health, particularly of communities that have a legacy of toxic exposure,” Yeampierre said.
By prioritizing the precautionary principle, racial justice and equity, the state will be able to come up with transformative recommendations, “not just for New York, but literally for the rest of the world,” Yeampierre said.
The CAC aims to issue a draft scoping plan by year-end and hold public meetings throughout 2022 before releasing a final clean energy plan in 2023.
PJM stakeholders last week approved revisions to the Energy Price Formation Senior Task Force (EPFSTF) charter while questioning changes requested by Exelon.
In a sector-weighted vote of 2.88 (57.6%) at the Markets and Reliability Committee meeting Wednesday, members approved the charter revisions resulting from an issue charge endorsed at the June MRC meeting. The previous issue charge was aimed at examining PJM’s operating reserve demand curve (ORDC) and transmission constraint penalty factors and the possible creation of a “circuit breaker” to control energy prices in an emergency. (See PJM Reserve Price Formation Issue Charge Approved.)
Susan Kenney, PJM markets automation manager, reviewed the revisions to the EPFSTF charter, saying those in the original version were “strictly a copy-paste” from the June issue charge as well as closing out the prior work efforts of the EPFSTF.
The first key work activity in the revisions featured education on the current and pending market rules for use of the ORDC and transmission constraint penalty factors in LMPs, including the input assumptions for the curve.
The second key work activity from the issue charge featured exploring potential circuit breakers or other stop-loss approaches that could limit extreme pricing when the cost “likely far exceeds the value of any contribution to preserving grid reliability.”
Language in the expected duration of work section calls for an effort to “expedite voting” on the first two key work activities before the downward sloping ORDC takes effect in PJM on May 1, 2022. FERC approved the new curve in May 2020, allowing PJM’s LMPs to reach or exceed $12,050/MWh in cases of extreme reserve shortages. (See FERC Approves PJM Reserve Market Overhaul.)
The third key work activity features exploring potential enhancements to PJM’s ORDC rules to address the impact of recent changes in the RTO’s dispatch protocols on forecast uncertainty and to examine and address the additional market and credit risks of the ORDC changes related to the recent pricing events in ERCOT, SPP and MISO from the polar vortex in February.
A second version of the charter introduced by Exelon included additional clarification to some of the out-of-scope items in the second key work activity, stating, “Changes to PJM’s ORDC, reserve product structure and penalty factors outside of use in the circuit breaker are out of scope.”
Stakeholders were unable to reach a consensus at the EPFSTF meeting Aug. 26 over Exelon’s suggested revisions, and members chose to endorse the original revised charter without them, supporting it 60%.
Sharon Midgley of Exelon said the company’s proposal “provides important clarifications” to the second key work activity in order to “focus and expedite” the group’s work on the circuit breaker.
Paul Sotkiewicz of E-Cubed Policy Associates said he was supportive of the Exelon alternative because it would allow stakeholders to concentrate on the circuit breaker and not on other issues.
Adrien Ford of Old Dominion Electric Cooperative said she was concerned Exelon’s proposal could limit the scope of the work of the task force. Ford said the additional language in the second key work activity “presupposes things that are out of scope.”
“We would not want to see any changes that would limit the scope of the work effort,” Ford said.
Steve Lieberman, assistant vice president of transmission and PJM affairs for American Municipal Power (AMP), said that the Exelon changes appeared to be “an end-around of getting something that people didn’t get when we voted on the issue charge.”
Natural Gas and Electric Markets Issue Charge Approved
Members will begin examining the alignment of natural gas and electric markets this month through a new senior task force assigned to the MRC after an issue charge presented by Dominion Energy was approved with a sector-weighted vote of 4.26 (85.2%).
Jim Davis, regulatory and market policy strategic adviser for Dominion, reviewed the problem statement and issue charge at last week’s meeting. Davis first presented them at the August MRC meeting. (See “Natural Gas and Electric Markets Issue Charge,” PJM MRC Briefs: Aug. 25, 2021.)
Davis said one major change was made to the issue charge since August: removing an item that called for avoiding discussions on gas market reforms that can only be resolved by FERC or the North American Energy Standards Board (NAESB). He said Dominion decided to eliminate the item after stakeholders questioned the language.
“We think there’s some compelling arguments to have discussions on items that can be reformed [in] the gas markets,” Davis said.
The key work activity in the issue charge includes providing education on topics like the history of pipeline and electricity coordination, pipeline tariffs, products, procurement, the impact of intermittent generation on the system, and imbalance charges and penalty structure.
Davis said education is “going to be critical” for the coordination effort to be successful.
Susan Bruce, counsel to the PJM Industrial Customer Coalition (ICC), said the work to be conducted is an “important conversation” that “links to so many other big-picture issues that we are tackling.” Education will be a key piece, she said, but some of the issues involved won’t be able to be solved through the stakeholder process because of FERC’s and NAESB’s jurisdictions.
Bruce also said the ICC has “reservations” about PJM load “bearing the burden” of some of the lack of flexibility that may exist on the gas side. “This conversation in some respects becomes an economic flexibility conversation.”
Independent Market Monitor Joe Bowring said he appreciated Dominion’s changes to the issue charge on the jurisdiction item and requested that discussions also include an examination of the reasons for pipeline inflexibility. Bowring said stakeholders should also consider recommendations to make to FERC regarding “gas pipeline business models and practices.”
Greg Poulos, executive director of the Consumer Advocates of the PJM States (CAPS), said coordination between energy generation and natural gas is “not an easy effort” to tackle and has been a concern across the country for years.
Poulos said the scope of the issue charge was a concern for the advocates because it could include areas in which PJM has no decision-making ability but could later incur costs depending on what path stakeholders decide to follow. “We don’t want to see those kinds of costs included in the PJM wholesale cost,” he said.
Poulos requested a motion to defer a vote on the issue charge until more discussions could be conducted to work on the scope, but that failed with a sector-weighted vote of 2.5 (50%), falling short of reaching the required 3.33 (66.6%) threshold.
Market Suspension Vote Delayed
The MRC delayed a vote to endorse a proposed solution and Operating Agreement revisions to address rules related to market suspension after representatives from Calpine and Vistra made a motion to defer until further discussions take place at the Market Implementation Committee.
Stefan Starkov, senior engineer for PJM’s day-ahead market operations department, reviewed the proposal and revisions. The proposed rules were first endorsed at the June MIC meeting. (See “Proposed Rules for Market Suspension Endorsed,” PJM MIC Briefs: June 9, 2021.)
Starkov said PJM wanted to “address a gap” in the tariff language regarding market suspensions, specifically how to settle the real-time market if prices couldn’t be determined for a certain period. Starkov said the revisions were designed to provide clear business rules to account for a market suspension where the RTO cannot clear or produce market results.
Some of the proposed OA revisions include updating language on day-ahead market suspension by removing existing language on settlements of day-ahead and financial transmission right target allocations at real-time quantities and prices in the event PJM cannot clear day-ahead prices; and adding language on notifying participants of a market suspension.
Another section clarifies the real-time market suspension definition as the “inability to produce economic zonal dispatch solutions for at least seven five-minute intervals.”
Starkov said the new section, Declaration of Market Suspension, outlines the scenarios for determining real-time market prices. Starkov said that if the market suspension is less than or equal to six hours, then the real-time prices associated with the market suspension would be the average of the real-time prices for all intervals of the proceeding and subsequent hours.
If the suspension is greater than six consecutive hours and day-ahead prices are available, Starkov said, then the real-time prices would be the day-ahead prices for each corresponding hour. If there are no clear day-ahead prices, then the real-time prices would be set to $0/MWh.
Calpine and Vistra said they were concerned that the rules were inadequate.
Calpine’s David “Scarp” Scarpignato said they may not adequately address longer‐term market suspension scenarios, including those lasting a week, a month or longer. The concern stems from the concept of compensating generators for an extended period of time “based only on their cost‐based offers, which are based solely on short‐run marginal costs,” he said.
Scarp said longer‐term compensation at only cost‐based offers “diverges from market dynamics and expectations.” He said Calpine and Vistra are proposing to add another time‐segmented solution that would kick in if a market suspension were to last for one week and that the compensation should include an adder above the short‐run marginal cost represented by cost‐based offers.
“All these market suspensions are highly unlikely, but if they do occur, it is important to get things right,” Scarp said.
Scarp made a motion to defer the vote on the tariff and OA revisions until the MIC considers and votes upon supplemental procedures that would govern in the event of a longer-term market suspension, which could then be added to the existing proposal. He said the longer-term scenario wouldn’t change the original proposal but would simply be added to it for a future vote at the MRC.
Stakeholders approved the deferral with a sector-weighted vote of 4.05 (81%). The longer-term scenario will now go to the MIC for further discussions.
Resource Adequacy Charter
David Anders, director of stakeholder affairs for PJM, reviewed a proposed charter during a first read to create a new senior task force addressing resource adequacy topics.
Anders cited a letter issued by the Board of Managers on April 6 that urged stakeholders to address a series of topics related to the capacity market after the completion of the Critical Issue Fast Path (CIFP) process addressing the minimum offer price rule.
The letter cited several topics to be discussed, including:
evaluating all aspects surrounding the appropriate level of capacity procurement;
examining the need to strengthen the qualification and performance requirements on capacity resources;
considering clean capacity/energy auctions as an option to allow for procurement of clean resources; and
evaluating the need for PJM’s procurement of additional reliability-based services, with a particular focus on reliability needs in the face of the changing resource portfolio and increased penetration of intermittent resource technologies.
Anders said PJM is proposing the creation of the Resource Adequacy Senior Task Force (RASTF) to discuss the topics listed in the board letter and to recommend possible changes to the capacity market. Anders said the new senior task force would report to the MRC and be the “central clearinghouse” for consideration of all the capacity-related issues.
To ensure proper coordination, Anders said, the charter includes reporting protocol for work on the capacity market performed at other PJM groups like the Quadrennial Review currently being discussed at special sessions at the MIC, load forecasting at the Load Analysis Subcommittee, and reliability products and services at the Operating Committee.
Individual issue charges discussed at the RASTF would ultimately be developed and approved by the MRC to address the specific capacity market work streams, Anders said, including the timing of the work.
Anders said PJM is still working on the final language contained in the RASTF charter and is looking for more comments on the existing language from stakeholders. The committee will vote on the charter at the Oct. 20 MRC meeting.
Energy Efficiency Add-back
Jeff Bastian, senior consultant with PJM’s market operations, provided a first read of the joint Monitor/PJM proposal addressing the calculation of the energy efficiency (EE) add-back mechanism. Members had unanimously endorsed an issue charge presented by the Monitor at the August MIC meeting. (See “Energy Efficiency Add-back Issue Charge Endorsed,” PJM MIC Briefs: Aug. 11, 2021.)
Bastian said the EE add-back mechanism is applied to capacity auctions to prevent the “adverse reliability impact” associated with double-counting EE as a capacity resource and as a reduction in the forecasted peak load. The problem is the current method of determining the add-back megawatt quantity applied to a Base Residual Auction does not require it to match the megawatt quantity of EE resources that clear in that auction. Bastian said the add-back quantity in a BRA will normally exceed the cleared quantity, resulting in an artificial increase in the clearing price.
The proposed solution calls for rewriting the manual language to permit PJM to calculate the EE add-back in the capacity market clearing so that the total EE add-back megawatts offset the total cleared EE megawatts in the BRA.
Bastian said the work timeline is anticipated to take two months to ensure that the modified EE add-back method is implemented with the next BRA for the 2023/24 delivery year. PJM is currently asking FERC for a delay of the BRA, pushing the date from Dec. 1 to Jan. 25. (See PJM Proposing 2-Month Capacity Auction Delay.)
The Monitor initially requested that the “quick-fix” process be used to complete work for the upcoming BRA, but some stakeholders requested an additional month of discussion to explore options. The issue charge was amended to use the “CBIR Lite” (Consensus Based Issue Resolution) process and take two months instead of one to complete it.
“We thought that waiting another month to get MRC endorsement would be cutting the timing awfully close,” Bastian said.
Erik Heinle of the D.C. Office of the People’s Counsel said his office views EE as an “important tool to get to [D.C.’s] decarbonization goals” and would like a better understanding from PJM and the Monitor on the approach being proposed and the impacts.
“While we obviously want accuracy in the process, I want to make sure we’re not devaluing that resource in a way that will be detrimental to our ratepayers,” Heinle said.
PJM will seek endorsement of the proposal at the Oct. 20 meeting.
Consent Agenda
Stakeholders unanimously endorsed revisions to the Regional Transmission and Energy Scheduling Practices document presented on the MRC consent agenda. The document was endorsed at the Sept. 9 MIC meeting and contains updates related to NAESB’s Wholesale Electric Quadrant v3.2 Business Practice Standards that take effect Oct. 27. (See “Energy Scheduling Practices Revisions Endorsed,” PJM MIC Briefs: Sept. 9, 2021.)
Members Committee
PJM Administrative Rates
The Members Committee endorsed the proposed solution and tariff revisions related to PJM administrative rates despite some members questioning the RTO’s funding methodology.
PJM’s proposal called for changing its administrative cost recovery from the current practice of initial charges at stated rate levels with a varying quarterly refund to the new practice of monthly rates based on that month’s costs and that month’s billing determinations. The proposal was endorsed with a sector-weighted vote of 3.84 (76.8%).
Jim Snow of PJM reviewed the proposal and tariff revisions that have been worked on by stakeholders and the RTO for more than a year. Snow said the proposal was developed in conjunction with the Finance Committee and is “specific only” to PJM’s cost recovery from the membership listed in schedule 9 of the tariff and received unanimous support from the Finance Committee in July.
Snow said the administrative rate review was initiated to examine “rate equity” across the PJM membership to avoid cross subsidization among the different customer classes. Snow said the review also was conducted for “overall revenue adequacy” of PJM.
The proposal “adjusts with changes in usage patterns” of the services that PJM provides and the costs of providing the services, Snow said, and is designed to avoid over- and under-collection of funds to finance the RTO.
Jason Barker of Exelon said his company prefers having the “rate predictability” in the existing system, and introducing uncertainty in the rates presents risk to load-serving entities and its customers. Barker said it seemed like PJM changed its objectives this year, prioritizing revenue adequacy and rate equity over the previous objective of maintaining low-rate volatility and multiyear rate certainty.
“We have concerns that the transition to a formula rate will introduce new risks and costs to load and load-serving entities as a consequence,” Barker said.PJM operating expense comparison with the stated rate filing projections versus the current forecast | PJM
The ICC’s Bruce said she was in the “uncomfortable position” of not being able to support the proposal, echoing Barker’s concerns regarding changes to the formula rate. Bruce said on the equity issue, there’s going to be a “real cost consequence” to members with the changing of the billing for cost-of-service issues related to PJM settlement.
“Customers do value having an expressed rate to help in having a discipline on costs at a utility,” Bruce said.
PJM filed the new administrative rates with FERC on Friday, requesting the commission act by Dec. 1 and to have the tariff revisions take effect Jan. 1 (ER22-26).
Nominating Committee Elections
Members unanimously elected the sector representative nominees for the 2021-2022 Nominating Committee.
The committee reports to the MC and is responsible for identifying candidates to serve on the board. It includes one representative from each of the five stakeholder sectors.
This year’s nominees included: Brian Vayda, executive director of the New Jersey Public Power Authority (Electric Distributors); Delaware Deputy Public Advocate Ruth Ann Price (End-Use Customers); John Brodbeck, senior manager of transmission at EDP Renewables North America (Generation Owners); Bruce Bleiweis, of DC Energy (Other Suppliers); and Dominion’s Davis (Transmission Owners).
Transparency Forum
CAPS’ Poulos reviewed a proposed charter for the creation of a new transparency forum, which he said is designed to address issues that currently take place “in the back of the room” among PJM and its stakeholders.
Poulos said the current Stakeholder Process Forum has provided members with an “excellent opportunity” to discuss concerns and suggest improvements to the stakeholder process. The Transparency Process Forum would provide members a new venue with a similar opportunity to address matters “outside of the scope of the Stakeholder Process Forum yet equally important,” he said.
Some of the examples of discussion items sited by Poulos included establishing a formal way to request information and data from PJM and to keep track of responses. He said he would also like to see discussion around creating guidelines and expectations allowing stakeholders to provide input to PJM prior to the RTO making filings at FERC or state commissions.
Poulos said PJM has made great strides in providing more transparency in recent years, but he said CAPS traditionally has more need for information because the group actively participates in less activities in the RTO like markets and delivery of services.
Gary Greiner, director of market policy for Public Service Enterprise Group, asked how the forum would work when typical discussions in the stakeholder process already include questions around transparency. Greiner said that if an issue about transparency comes up during the stakeholder process in a committee, the issue is usually discussed as part of the process.
Poulos said the forum would look at transparency issues that have a “lingering impact” and not ones that come up during the normal stakeholder process.
Barker said that Exelon was “a bit puzzled” over what the purpose of the forum would be and asked for more examples of issues that could be discussed that warrant additional transparency. He said the MC has traditionally been the place to express concerns among stakeholders regarding PJM operations and other deliberations, as it has authority over all the other committees.
Poulos said he will provide more examples of transparency issues at the October MC meeting.
Manual 34 Revisions
Michele Greening, senior lead stakeholder affairs consultant for PJM, reviewed proposed revisions to Manual 34: PJM Stakeholder Process to address the inclusion of forums as stakeholder bodies. The proposed revisions were sponsored by PJM and discussed at the Stakeholder Process Forum, but the RTO is looking for a member to officially sponsor the revisions because the manual changes are supposed to come from the stakeholder body.
Greening said several new forums, such as the Emerging Technology Forum that was established in June 2020, have been created, but Manual 34 doesn’t currently define forum as an official type of stakeholder group. Greening said PJM wants to define what a forum is and “add some parameters” around their establishment and implementation within the stakeholder process.
The RTO is defining forums as a stakeholder body in Manual 34 to provide consistency with other defined stakeholder groups, Greening said, and to provide clarity to the purpose and role of a forum in the stakeholder process.
A forum is being defined as a “stakeholder body formed to address specific topics and scope as outlined in its Markets and Reliability Committee approved charter. Forums are non-decisional stakeholder groups.”
Members will vote on the revisions at the October MC meeting.
Consent Agenda
The committee unanimously endorsed several revisions as part of the consent agenda. They included:
revisions from the Governing Document Enhancement and Clarification Subcommittee (GDECS) addressing administrative changes and clarifications in the tariff and OA. PJM said the revisions were found to be “simple and noncontroversial enough” that they were reviewed one time at the GDECS, receiving unanimous stakeholder support. (See “Consent Agenda Manual Endorsements,” PJM MRC/MC Briefs: July 28, 2021.)
revisions to address making cure periods uniform across the tariff and OA. PJM said appropriate cure periods defined in section 15.1.5 of the OA were originally updated in that document, but not in section 7.3 of the tariff, which involves provisions limited to transmission service customers. (See “‘Know Your Customer’ Tariff Changes,” PJM MRC Briefs: Aug. 25, 2021.)
revisions to address making the definitions of working credit limits uniform across the tariff. The revisions eliminate duplicative definitions of “working capital limit” and leave it only in the definitions section of the tariff.
Members of the Massachusetts legislature questioned program administrators of Mass Save during a hearing on Wednesday asking why the utility group has fallen far behind state targets for electrification.
“There is a lot of feet dragging, even on the administration goals,” Sen. Marc Pacheco (D) said.
While Mass Save is supposed to transition 100,000 homes to electric heat each year, The Boston Globereported that the group transitioned only 461 homes last year.
That number is “woefully low,” and “under the control of the electric and gas utilities,” Pacheco said.
Mass Save is a collaborative of Berkshire Gas, Blackstone Gas Company, Cape Light Compact, Columbia Gas of Massachusetts, Eversource Energy (NYSE: ES), Liberty Utilities, National Grid (NYSE: NGG) and Unitil (NYSE: UTL).
The Joint Committee on Telecommunications, Utilities and Energy held the hearing for several bills that the committee is considering, including An Act Instituting a Governance Structure for Mass Save (S.2132).
“From a legislative view, there is no one focused on responsibility” of the role of Mass Save in electrification, reducing greenhouse gas (GHG) emissions and engaging environmental justice communities in participating in its low-cost energy transition programs, Sen. Michael Barrett (D) said during the hearing.
As proposed, the bill would create a Mass Save board of directors that would include at least two experts in the economics of GHG reductions and three residents of state-designated environmental justice communities.
The bill, filed by Barrett earlier this year, is an attempt to hold Mass Save accountable in its new role under the state Climate Act, which is to prioritize GHG emissions reductions and assist in reaching the reduction sublimits imposed on sectors such as buildings, and natural gas specifically, the state senator said.
Mass Save currently operates without a CEO or a board of directors. The Massachusetts Energy Efficiency Advisory Council (EEAC), which includes state, utility and private sector representatives, is responsible for overseeing Mass Save’s work and energy efficiency in the state.
Chris Porter, a nonvoting member of the EEAC representing National Grid, testified Wednesday that the advisory council is aware of the reporting done by the Globe and said it is inaccurate because it does not reflect the number of houses that were partially transitioned from natural gas to heat pumps. Complete transitions, Porter said, involve removing the ability to supply natural gas to the home.
The partial transitions “should not be interpreted as a lack of support” for the state’s climate goals, Porter testified, as Mass Save has “partially” transitioned about 10,000 homes, meeting goals outlined in the current three-year plan for the program.
A draft for the next three-year plan for Mass Save allocates $894 million to electrification for 2022 to 2024, including funding for high-efficiency electric heat pumps, Porter said.
However, Barrett said the current three-year plan Mass Save is operating under took effect the same year the Massachusetts Decarbonization Roadmap development process kicked off, which should have inspired Mass Save to act sooner than it did.
Changes to Mass Save Under New Bill
The proposed Mass Save board would be responsible for tracking and evaluating the program’s role in instituting emission reduction targets under the leadership of an executive director appointed by the board that is not associated with a utility.
According to the bill, the executive director would prepare the annual budget for Mass Save and oversee its coordination with the Department of Public Utilities. The director would also file an annual report to the Secretary of Energy and Environmental Affairs and the legislative Joint Committee on Telecommunications, Utilities and Energy, as well as the Senate and House Committees on Ways and Means.
The report would focus on the cost-effectiveness of the program and its contribution to state GHG reductions.
However, it will take Mass Save along with other programs to achieve the scale needed to decarbonize heating systems in 100,000 buildings each year, said Cammy Peterson, director of clean energy at the Metropolitan Area Planning Council in Boston and a member of the EEAC.
Mass Save “needs to do a much better job reaching people, and we will need to look beyond Mass Save to achieve the scale that we need,” she said.
“Can Mass Save be saved?” Barrett said during the hearing. “We will have to see.”
The state of Maine submitted a lease application on Friday to the U.S. Bureau of Ocean Energy Management for 9,696 acres in federal waters in the Gulf of Maine to build a floating offshore wind research array.
In its application, the state said it plans to install no more than 12 turbines on the site, which is 40 miles from Portland. Cape Small, north of Portland, is the nearest mainland point from the site at 29 miles.
Among the top priorities for the project is evaluating how floating technologies interact with Maine’s billion-dollar fishing industry, of which lobstering is a mainstay.
“Fundamentally, I believe that offshore wind and Maine’s fishing industry can not only coexist but can help us build a stronger economy and a brighter, more sustainable future for Maine people,” Gov. Janet Mills said in a statement.
A consortium will oversee research activities and release open-source results from the project, according to the application. Mills signed a law (LD 1619) in July that established the consortium, which must include three representatives of the state’s lobstering industry, two representatives of the state’s commercial fishing industry and the state’s commissioner of marine resources.
The law also established a moratorium on OSW development in state waters in the Gulf of Maine, where 75% of the state’s lobsters are harvested, according to the application.
“The state of Maine engaged hundreds of individuals, which resulted in selection of a proposed lease area in a location with limited lobster activity and minimal groundfish activity,” the application said.
In June, Mills signed the Act to Encourage Research to Support the Maine Offshore Wind Industry (LD 336), which directs state regulators to enter a long-term contract for a 144-MW floating wind research array. The law allows a state utility to secure the contract with New England Aqua Ventus, the joint venture behind the 11-MW floating wind pilot that will feature the University of Maine’s VolturnUS concrete semi-submersible hull.
The pilot will be sited at UMaine’s deep-water OSW test site 3 miles southwest of Monhegan Island in the Gulf of Maine. The island is 23 miles from the proposed lease site for the research array, which also will feature the VolturnUS hull.
Research activities would take place throughout the planned project development process, which Maine estimated in its application would take eight years. The array, according to the application, is a critical element of the state’s current OSW roadmap initiative.
Maine received $2 million from the U.S. Economic Development Administration to create the roadmap, which will outline the best way to build the state’s OSW potential without harming the fishing industry. The final roadmap is due in December 2022. (See Roadmap Initiative Set to Hone Maine’s OSW Goal.)
Four working groups must deliver initial recommendations for the map to the lead advisory committee by the end of this year.
A fisheries working group met on Wednesday to consider a draft proposal of pre-construction monitoring priorities for the research array for inclusion in the roadmap. The group proposed researchers conduct a survey of the amount and distribution of marine life in and around the lease area. In addition, the group said an oceanographic data buoy on the array location would provide environmental condition data and allow researchers to monitor marine life. Other recommendations included continued seafloor mapping and a survey of existing commercial and recreational fishing activity.
The fisheries working group will meet again in mid-October.
Oregon’s Environmental Quality Commission (EQC) last week approved rules that will give the state the most stringent landfill gas emissions standards in the U.S., part of an effort to reduce the release of heat-trapping methane.
The state currently follows EPA standards for landfill gas emissions. The new rules proposed by its Department of Environmental Quality (DEQ) will exceed those standards by expanding the categories of landfills subject to gas emission regulations while lowering the size threshold for facilities covered, among other changes.
According to DEQ estimates, landfills accounted for 37% of Oregon’s carbon dioxide equivalent (CO2e) emissions from stationary sources in 2019, excluding electricity generators. Landfills represented six of the 25 largest sources of greenhouse gas emissions in that category, the agency found. Methane makes up about 40 to 60% of those emissions from landfills.
“If you look at just a 20-year time span, methane’s global warming potential is over 80 times that of carbon dioxide. This shows why landfill gas control is an important element in greenhouse gas emissions reductions,” Heather Kuoppamaki, DEQ senior environmental engineer, told the EQC on Friday.
The DEQ set out to revise Oregon’s landfill gas rules in response to Gov. Kate Brown’s Executive Order 20-04, which last year directed state agencies to use their existing regulatory authority to find ways to reduce the state’s GHG emissions.
In crafting the new rules, Kuoppamaki explained, Oregon looked to California’s regulations — the country’s strictest — as a template. The DEQ found some key differences between the two sets of rules, including the fact that Oregon’s existing rules cover only municipal solid waste landfills, while California’s also include industrial waste landfills. California’s rules also have a much lower threshold for the size of landfills covered: 496,000 tons of waste-in-place versus 2.5 million tons in Oregon.
Kuoppamaki noted also that California has “much tighter” surface emissions monitoring and gas destruction standards, requiring landfills to install gas collection and control systems if they emit methane at concentrations of at least 200 parts per million by volume (ppmv), compared with 500 ppmv for the Oregon/EPA standard. California also requires monitoring equipment to be placed on pathways spaced 25 feet apart, compared with 98 feet in Oregon.
Oregon’s new rules match California’s by adopting the 200-ppmv and 25-foot standards. The DEQ will also expand program coverage to encompass industrial landfills, including construction and demolition waste landfills, which are exempt from oversight under California regulations.
The DEQ’s new rules will additionally surpass California’s by reducing the covered landfill size threshold to more than 200,000 tons of waste-in-place. Landfills under that threshold will be “conditionally” exempt from the rules if they maintain an adequate landfill cover. They will also be required to maintain records verifying the amount of waste-in-place.
Landfills exceeding the 200,000-ton threshold that produce less than 664 metric tons (MT) of methane per year must obtain a “simple” air containment discharge permit (ACDP), requiring them to submit annual reports on the amount and type of waste received and provide updated landfill gas generation reports.
Active and closed landfills that emit at least 664 MT of methane per year must obtain a standard ACDP. “Landfill owners or operators in this category would be required to either conduct surface emission monitoring, or, if surface emission monitoring shows methane emissions greater than 200 ppmv, install and maintain a gas collection and control system, along with continued surface emission monitoring,” the DEQ said.
The DEQ estimates that 15 landfills that were not previously required to have ACDPs will be required to obtain the permits, on top of the 12 in the state that already hold one. Kuoppamaki said it’s “really hard to estimate” which landfills will be required to install collect-and-control systems. After being flagged, landfill owners will have 30 months to complete the systems.
“Most landfill owners are local governments, both city and county, or private businesses,” DEQ said.
LANSING, Mich. — The governors of Michigan, Indiana, Illinois, Wisconsin and Minnesota last week agreed to collaborate to accelerate electric vehicle adoption in the upper Midwest, focusing initially on medium- and heavy-duty vehicles (MHDV).
In a Sept. 30 memorandum of understanding, the governors established the Regional Electric Vehicle Midwest Coalition to “future proof the region’s manufacturing, logistics, and transportation leadership and position the region to realize additional economic opportunity in clean energy manufacturing and deployment.”
The network’s initial focus will be installing a truck charging network on interstate and “regionally significant” commercial corridors to “leverage our existing role as a shipping and logistics hub,” the states said in a press release. “The MOU is meant to competitively position the Midwest for upcoming federal funding opportunities and create a welcoming environment for economic development and innovation around EVs, EV charging infrastructure, battery performance, and other technologies on the cutting edge of the transportation-energy sector convergence,” the agreement said.
The region is home to interstate highways such as I-94 and I-69, which play a key role in truck transport between the U.S., Canada and Mexico.
The five participating states will also “share best practices to inform the standardization of regulatory schemes” for EVs and “to develop a common customer experience across state lines.”
The agreement also calls for working with “historically disadvantaged” communities on electrification workforce development and assuring the availability of charging stations and economic development in all communities.
The states said their initial focus on MHDVs will improve air quality in disadvantaged communities located near freight and shipping facilities and highways.
The Midwest initiative is not the first multistate collaboration on EVs. In 2017, the governors of Arizona, Colorado, Idaho, Montana, Nevada, New Mexico, Utah and Wyoming created REV West, which focused on eliminating range anxiety for EV owners on major highways in those states. As of December 2020, the states reported the addition of more than 100 DC fast-charging stations by the private and public sectors since the MOU’s launch, with at least 75 additional stations in the planning phase.
Jane McCurry, executive director of Clean Fuels Michigan, said the agreement could assure commercial truckers of “cross-boundary cooperation on charging infrastructure. Heavy duty vehicles, really any fleet vehicles, need to know they can charge with confidence, and the rules won’t change from location to location.”
The states hope their collaboration will increase the region’s share of electric vehicle production.
Michigan and Indiana are top automotive production states, and electric truck maker Rivian, whose manufacturing facility is in central Illinois, plans to begin shipping its electric pickups in January 2022. General Motors (NYSE:GM) and Ford (NYSE:F) have committed to electrifying their product line.
“We shouldn’t have to choose between building a cleaner, more equitable state and economic development — and thankfully, vehicle electrification is an area where we can do both,” Wisconsin Gov. Tony Evers (D) said in the release.
The five states agreed to create a task force of senior state leaders to oversee the activities and work to remove barriers to EV charging infrastructure.
The MOU is not legally binding, and any of the states can leave the agreement. The MOU members can add more states to the agreement by a unanimous vote.
ERCOT will soon add an extra 226 MW of capacity to the market with recent announcements that two resources will come out of seasonal mothball status.
Austin Energy told the grid operator on Wednesday that it is returning the wood-fired Nacogdoches Power, the country’s largest biomass plant, to year-round service on Oct. 15. The plant, which the municipal utility acquired from Southern Power in 2019, had been operating on a seasonal basis during the summer.
Last week, Garland’s municipal utility notified ERCOT that it was bringing back a pair of gas-fired units that had been mothballed in 2018. The two units at Garland’s Spencer plant have a total capacity of 118 MW.
ERCOT has said it has enough capacity to meet a fall demand peak of 65 GW by at least 30 GW, but staff told regulators last week that forced or maintenance generator outages continue to approach 10 GW a day. (See ERCOT: Sufficient Capacity to Meet Fall Demand.)
Brad Jones Named to Reliability Council
Texas Gov. Greg Abbott on Tuesday included interim ERCOT CEO Brad Jones among six appointees to the new Texas Energy Reliability Council, which was established by legislation this summer in response to February’s Winter Storm Uri.
The other appointees represent three of Texas’ four largest urban areas: Houston, San Antonio and Austin. They are:
Nate Murphy, senior counsel for refiner Valero, San Antonio;
George Presses, vice president of fuel and energy for the H.E.B. grocery chain, San Antonio;
Edward Stones, global business director for energy and climate change for Dow, Houston;
Jon Taylor, corporate vice president of fab (silicon wafers) engineering and public affairs at Samsung Austin Semiconductor, Austin; and
Melissa Trevino, assistant vice president for power at Occidental Energy Ventures, Houston.
Senate Bill 3 tasks the council with overseeing the grid’s weatherization and improving communication in the state’s energy and electric industries.
Distributed energy resources, electrification and equitable wholesale compensation for both dominated two panels during the virtual North America Smart Energy Week.
Karen Olesky, an economist for Nevada’s Public Utilities Commission, said she’s both riddled with anxiety and invigorated over how quickly new distributed resource technology is being developed.
“It’s very exciting to see vehicle-to-grid charging and the electric company being able to access behind-the meter storage in someone’s home to use it as a demand response unit,” Olesky said during a Sept. 28 panel on electrification. “I think these are great DER technologies, and I love seeing them in pilot programs and proliferate, but I’m also scared about how quickly that technology is changing. Some of these technologies that utilities invest in might end up being obsolete well before the end of their useful lives.”
Olesky said ratepayers could be stuck paying for electric vehicle charging stations that are quickly replaced by newer models. She called the speed of adoption and its implications on long-term resource planning “exciting and kind of terrifying.”
Regulators and utilities are okay to “pivot” on incentive programs when they realize they’re unpopular or ineffective, she said.
Keith Dennis, vice president of the National Rural Electric Cooperative Association, said electrification stands to improve people’s quality of life.
“It wasn’t more than a hundred years ago when people were washing dishes and clothes by hand, and electricity really improved our lives and it can do it again,” he told attendees.
Dennis said electrification can save customers money, lessen environmental impacts, bolster grid reliability and lengthen the lifespan of heavy machinery and construction equipment. He added that he doesn’t want electrification to become politicized.
Oncor Electric Delivery’s David Treichler said the conversion to electrification is one of the most consequential changes the nation will undertake. Electrification will fundamentally change how we “move goods, people, things.”
Flying into the Dallas Fort Worth airport one night, Treichler said he concentrated on a bird’s eye view of the airport’s logistics warehouses. He said when thinking about how to electrify the airport’s freight services, he realized the centers were packed so tightly together that he couldn’t see where new substations could be squeezed in to handle charging.
Treichler said Oncor has developed a green fleet analytics tool that evaluates a customer’s load requirements for electrification and available nearby capacity to gauge the need for new electric facilities.
“The longer you wait to talk to us, the harder it is,” he said, urging companies interested in fleet electrification to act sooner rather than later.
National Grid’s Kristin Munsch said electrification’s growth is uncertain now because the changeover hinges on customer adoption.
“It’s talking about people’s cars, people’s home heating systems,” Munsch said. She said investments need to be made thoughtfully so that all customers can electrify their homes, not just those that can afford it.
“Like everywhere in the country, we’ve got very affluent communities, and we’ve got more challenged communities,” she said.
Panelists during a wholesale pricing session said appropriate compensation is necessary for a more active demand-side market.
“We have a generational problem of how we count it. How do we know what a megawatt is anymore?” OhmConnect’s Cisco DeVries said. “Ultimately, I think we just need to agree on some methodologies, and I think it’s really critical for the wholesale market that we get there quickly.”
“We have historically underestimated the potential of distributed clean energy in terms of serving our wholesale markets,” SunPower’s Suzanne Leta said. “A key question in my mind is: how do we ensure the right policies are in place to enable consumers to offer that value to the wholesale market and get paid for it? That’s really the question we need to focus on answering.”
Leta said the industry often ignores that just 3% of residential customers currently have rooftop solar. She said rooftop solar is poised for a “massive” growth trajectory. “We are just at the tip of iceberg,” she said.
In SunPower’s nationwide surveys, Leta said residents cite concern over outages as the primary reason for installing their own solar and storage.
“This is real-time for consumers, whether it’s an ice storm in Texas, or flooding in Louisiana or a hurricane in New York. … That’s what people are concerned about. Are power outages happening on a much more frequent basis?”
Leta said in addition to wholesale pricing, state commissions and utilities need to think differently about resource procurement. She said commissions’ resource planning is rooted in one-way transactions sourced from fossil fuels or nuclear power.
“That’s just not how our grid works today, and it’s not going to be how it works in the future,” Leta said.
Jill Powers, CAISO’s infrastructure and regulatory policy manager, said dynamic rates and demand-side management will feature more prominently in wholesale pricing.
“The duck curve is about 10 years old, and he’s been progressing quickly,” Powers said, noting that CAISO underestimated rooftop solar’s contributions. She said CAISO contends with oversupply and dramatic ramping needs in any given day.
DeVries commended CAISO for being among the first to allow bids on a 15-minutes basis from aggregated DERs.
“The wholesale market is the place where this transaction takes place,” he said. “It is not a place the customer understands at all. They are never going to understand it. They’re still incredibly confused as to why we might pay them to save energy. That makes no sense [to them].”
He said the aggregator’s role is to simplify and translate DER use into the wholesale market.
“We can’t say to customers, ‘You can’t turn your air conditioning on right now.’ Right? That’s a no-go,” DeVries said. “The utilities have tried that forever. It just doesn’t work.”
Kicking off the Texas Reliability Entity’s annual winter weatherization workshop last week, CEO Jim Albright noted a “renewed focus by all of us on winter weather.”
That’s no surprise, given the February winter storm that drove the ERCOT grid to the brink of collapse and led to human and financial suffering across Texas. A joint inquiry by FERC and NERC has since pinpointed a lack of winter weatherization of generator facilities and natural gas infrastructure as the leading cause of the power outages that left some Texans in the dark and cold for almost four days. (See FERC, NERC Share Findings on February Winter Storm.)
State lawmakers and regulators responded to the storm by taking a more aggressive response to weatherization, requiring generators and transmission service providers (TSPs) to comply with mandatory reliability standards for winter weather and imposing financial penalties if they don’t. (See “Weatherization Rule Published,” PUC Workshop Takes First Stab at Market Changes.)
FERC Chair Richard Glick, in discussing the joint inquiry with NERC last month, noted that the two regulators proposed similar requirements after a previous winter event in 2011. However, “that recommendation was watered down to guidelines that few generators followed,” he said.
This time, it will be different, Jeff Billo, ERCOT’s director of forecasting and ancillary services, said during Thursday’s virtual workshop.
“Previously, we really didn’t have any mandatory reliability standards from a weatherization standpoint,” he said, adding that there will be “substantial fines.” Penalties can range as high as $1 million/day.
“Future inspections will be very different than they have been in the past,” Billo said.
The Public Utility Commission’s draft rule directs generators and TSPs to file compliance statements, signed by a senior-level officer, attesting to their actions. ERCOT staff will follow up with on-site inspections. With about 800 resource units to inspect, Billo said ERCOT is taking a “risk-based” approach and will focus on those generators that failed during the winter storm. That will likely include wind farms and solar fields, Billo said.
The grid operator’s staff are currently developing an online compliance form that will be distributed before the Dec. 1 response deadline. ERCOT is required to file a report with the PUC by Dec. 10.
“If we have 800, 900 units to look at, we don’t want [response] emails in formats we’ll have to sort through in eight or 10 days,” Billo said.
ERCOT used to inspect about 80 units a year, Billo said. The increase has forced the grid operator to create a weatherization director’s position and hire additional staff to meet the load. In the meantime, staff will rely on support from contractors to meet a Dec. 24 inspection deadline.
The commission will add temperature requirements to its reliability standards next year, following a detailed weather report due early next year.
ERCOT meteorologist Chris Coleman told his virtual audience that the La Nina ocean patterns are similar to last year’s and that a majority of forecasts are pointing to a colder-than-normal winter. While much of the cold air may be concentrated in the Midwest, he said, “The potential is there for a polar vortex for ERCOT a time or two.”
Winter is coming, but despite the forecasts, this winter is statistically likely to have less extreme weather than last year. | Texas REColeman said this winter will likely be a dry one, welcome news to those who remember February’s ice and snow. He said his preliminary data indicate the coming season will be similar to the mild winter of 1999-2000, pointing out that extreme winters are historically followed by milder ones.
“Statistically, when you have a cold, extreme winter, at least some, if not more, of those winters were followed by some extreme cold, though not as extreme” as the previous winter, Coleman said.
The meteorologist’s final forecast will be released in November.
Generation Owners Share Tips
Andrew Valencia, Lower Colorado River Authority’s (LCRA) senior vice president of generation and the man who will sign the utility’s compliance statement, was among several market participants and industry experts who shared their insight during the workshop.
He said a power plant is only as good as its weakest link, noting subsystems and major equipment are typically designed for specific minimum temperatures that may or may not be consistent. The highest temperature rating sets the entire plant’s rating, but that can be a moot point when sub-zero temperatures hit.
El Paso Electric’s performance during the winter storm led to a social media meme. | LordOfTheBrohirrim via iFunny.com“There’s no way to test freeze protection until you have cold weather,” Valencia said. “Until you can experience those temperatures, there’s no way to functionally test it.”
He said activating temporary heat sources, frequently checking equipment and adding staff are among hundreds of procedure provisions necessary required to maintain operations.
LCRA begins its winter preparations in the fall with meetings to review written procedures and checklists for each site. Supply inventories and equipment are checked and senior leaders tour each site to verify preparations.
“That’s the best time to work on it. You don’t need the preparation measures, and you have time to work on the protection,” Valencia said.
El Paso Electric’s Kyle Olson said the utility invested $4.5 million in freeze protection systems after losing generation, much of it built before 1980, during the 2011 winter event. The utility also added a gas unit designed to withstand ‑10 degrees Fahrenheit, chose simple cycle turbines over combined cycle, and installed dual-fuel capability on new additions.
The utility wound up meeting demand that was almost 37% above normal. Being part of WECC and separated from ERCOT helped, as one social media meme was quick to notice.
“The heat tracing money paid off,” Olson said, citing $19 million in customer savings during the February storm. “In a city where summer temperatures reach 105 [to] 110, people aren’t constantly thinking about winter protections.”
