The city of Lubbock joins San Antonio and Austin as municipalities in ERCOT’s competitive retail market. The more than 107,000 LP&L customers will be able to begin choosing their power providers in January.
That is a big change from the West Texas city’s previous experience with “alley-by-alley” competition that existed until 2010, said Matt Rose, LP&L’s public affairs and government relations manager, this year.
During the Gulf Coast Power Association’s fall conference in October, Rose recalled when LP&L and Xcel Energy subsidiary Southwestern Public Service (SPS) both had distribution facilities on either side of alleys.
“Depending on who you wanted to go with, you chose and then you got hooked up on one side in the alley or the other,” he said.
In 2010, LP&L bought SPS’ infrastructure and LP&L became more of a traditional municipality, serving all the customers in its footprint as a vertically integrated utility. Faced with spending about $700 million to build more generation, LP&L reached a decision point in 2014.
“We said, ‘We have a choice. We can build a power plant, stay in the Southwest Power Pool and operate as we have the past 100 years. Or we can take a look outside Lubbock.’ We could see that these transmission lines for ERCOT are really one county north, east and south of us,” Rose said, alluding to ERCOT’s transmission system.
LP&L said in 2015 it intended to transfer its load to ERCOT, beginning a process that culminated with the Public Utility Commission’s approval three years later. The process involved paying SPS $77.5 million for early termination of a power contract that would have cost the utility more than $17 million a year through 2044. (See Texas PUC OKs Sempra-Oncor Deal, LP&L Transfer.)
The utility successfully transitioned 70% of its load to ERCOT in 2021. The remaining 30% was moved into ERCOT in what LP&L said was a “seamless migration,” beginning early Dec. 9 and concluding midmorning Dec. 11.
Now, rather than choosing a provider on one side of the alley or the other, LP&L consumers can select from more than 85 retail providers during a six-week “shopping” window that begins Jan. 5. The utility then will begin migrating the customers to their chosen providers in March and become a transmission and distribution entity.
“This has been an interesting and a fun experience, but Lubbock was able to do this because Lubbock is uniquely situated,” Rose said. “We were ending all business in the Southwest Power Pool in order to move to ERCOT, and that allowed us the liberty to go pursue this.”
A newly published Berkeley Lab study finds that sale prices temporarily decrease for property located within a mile of newly announced and newly built utility-scale wind projects.
The conclusion runs counter to earlier studies published by the lab, some of which were compiled by some of the same researchers but relied on limited sales data.
During a webinar Dec. 13, one of the authors said vastly more real estate transaction data is available now than a decade ago, many more large-scale wind turbines have been erected, and the methodology for analyzing the information has evolved.
The bottom line: Shortly after a commercial wind turbine site is announced, houses located within a mile begin to sell for less than those three to five miles away from the same site. Over the next nine years, the difference grows to 11% on average, then gradually declines until the disparity is statistically insignificant.
“We see a dipping of values after the announcement of the project that kind of bottoms out right around the ending of construction and the beginning of operation,” said Ben Hoen, a research scientist at Lawrence Berkeley National Laboratory.
Hoen, Eric J. Brunner, Joe Rand and David Schwegman are the authors of “Commercial Wind Turbines and Residential Home Values: New Evidence from the Universe of Land-Based Wind Projects in the United States,” which was published this month in the journal Energy Policy.
To reach their conclusions, the researchers took CoreLogic’s database of more than 260 million U.S. residential property transactions from 2005 through 2020 and cross-referenced it with the 72,000 towers listed in the U.S. Wind Turbine Database.
Wind turbines are proliferating nationwide. | Lawrence Berkeley National Laboratory
After applying a rigorous set of filters and conditions, they were left with 496,000 transactions within five miles of a turbine rated at more than 600 kW; those transactions occurred no more than four years before and 10 years after the turbine was announced.
The greatest price impacts were seen in the 20,331 properties within a mile of a turbine that had been announced or built.
That is vastly more data than some of the previous studies. A 2009 report described by Berkeley at the time as “major” analyzed not quite 7,500 transactions in total.
That study and other studies found no statistically significant impact on sale prices.
But more recent studies in the EU and southern New England did show a negative impact on sale price of houses near wind projects.
“This was a curious finding for us,” Hoen said, “given our past work of not finding statistically significant impacts.”
A key factor is Europe is that the population density is much greater than in the United States, the authors said. It is harder to site a wind turbine away from people there. Similarly, the housing price impacts recorded in Massachusetts and Rhode Island were greatest in the more densely populated eastern portions of those states.
Finally, the authors emphasize that in their own analysis for the new study, the greatest price impact was seen in counties that were part of, or adjacent to, metropolitan areas with population greater than 250,000.
Wind power’s impact on home prices is not just a statistical curiosity. It can be a significant factor in building support for a project.
“Property values remain one of the top concerns for local communities that are considering hosting a wind energy project, or have a wind energy project in their midst,” Hoen said. “Often, a home is a family’s most valuable asset, and therefore protecting [it], and protecting its value, is of extreme importance.”
Because a geographically identifiable group of residents has been shown to be impacted economically by wind power projects, it may be possible to directly compensate them, the authors write.
And because the impacts of a project have been shown to begin well before any wind turbines are erected, it may be possible to do a better job explaining the actual impacts of the towering equipment, rather than leave it to speculation. Better line-of-sight photo simulations or location-specific audio simulations might help ease the concerns of nearby residents and the people who buy their homes.
Hoen said the analysis found no variation by size. The largest wind turbines had the same effect on prices as their smaller cousins.
Nor, he said, was there any attempt with this study to analyze the positive impacts of wind power generation, such as job creation or tax revenue.
A bill introduced in the U.S. House of Representatives by Democrats on Dec. 13 would grant FERC numerous new authorities over interregional transmission in a bid to spur large projects and increase the flow of renewable energy across state lines.
The 210-page Clean Electricity and Transmission Acceleration (CETA) Act, introduced by Reps. Sean Casten (D-Ill.) and Mike Levin (D-Calif.), would add six new sections to the Federal Power Act, many of them directing FERC to issue new regulations for how it can site new interregional projects. Most significantly, it would require the commission to solicit plans from grid operators and other transmission providers identifying interregional transmission projects every three years.
The bill details the criteria for how FERC would evaluate the plans and the projects they identify. The commission would be required to issue its solicitation within a year and a half of the bill’s enactment.
FERC also would gain explicit siting authority over interstate transmission lines with capacities over 1 GW, if the commission finds they enable the use of renewable energy, increase reliability and reduce congestion, among other provisions.
The bill also would set new cost allocation rules for any transmission facility “of national significance,” defined as a new line that has a capacity of 1 GW or more; any transmission connecting offshore generators; and upgrades that increase an existing line’s capacity by 500 MW or more. Costs would be allocated “to customers within the applicable transmission planning region or regions in a manner that is roughly commensurate with the reasonably anticipated transmission benefits,” the bill says.
Many of these projects would qualify for a 30% investment tax credit established by the bill. To carry out all its new responsibilities, FERC would be allowed to establish a new Office of Transmission.
“The biggest challenge facing the United States’ ability to meet its climate goals is the lack of capacity of our electrical grid to connect clean energy generation to the new demand that comes with economy-wide electrification,” the House Sustainable Energy and Environment Coalition (SEEC), made up of 93 Democrats, said in a press release. “CETA aims to inclusively and efficiently support the buildout of transmission lines to transport the electricity from its generation source to the homes of the American people.”
The release included statements of support from former FERC Chair Richard Glick, Grid Strategies’ Rob Gramlich, Americans for a Clean Energy Grid, the American Clean Power Association and several environmental organizations.
“The CETA Act is an important step in addressing some of the most pressing issues around transmission capacity and the diverse technologies that can deliver solutions at speed and scale,” AES said in a statement. “We commend the efforts of the SEEC caucus on this thoughtful bill, which aims to reduce bottlenecks and improve planning of and connection to the transmission system.”
The bill also would incentivize development of solar, wind and geothermal resources on public lands and establish a production goal for such resources of at least 60 GW by the end of 2030. It would direct the Department of Agriculture, in consultation with the Department of Energy, to identify priority areas for solar and wind.
Finally, CETA would codify President Joe Biden’s goals for offshore wind deployment, directing the Department of the Interior to issue permits for a cumulative of 30 GW by 2030 and 50 GW by 2035. It also would establish an Offshore Renewable Energy Compensation Fund in the Bureau of Ocean Energy Management “to compensate eligible ocean users for damages experienced as a result of the development of an offshore renewable energy project through a claims-based process and to provide grants to eligible recipients to mitigate future damages from such projects.”
With Republicans in control of the House, the bill has virtually no chance of passing as drafted. And the increased authority it would grant to FERC is likely to draw some opposition from states both red and blue, along with their utilities.
The permitting reform debate has been on apparent hiatus for months, as the House battled over the speaker position and the debt ceiling. Several bills have been introduced in both houses, but none has been viewed as a starting point for party negotiations. The last hearing by the Senate Energy and Natural Resources Committee on the subject was held in July. (See Members of Congress Debate Transmission Permitting.)
NYISO stakeholders continued their criticism of the ISO’s effort to improve its demand response programs, saying its recent “issue discovery” report inadequately addressed their concerns and that its proposal to allow demand-side resources (DSRs) to participate in the day-ahead market is hollow.
During the Dec. 6 Installed Capacity/Market Issues Working Group (ICAP/MIWG) meeting, NYISO presented findings from its Engaging the Demand Side (EtDS) report, a response to stakeholders’ request that the ISO investigate whether rules could be improved to reflect DSR’s “evolved … capabilities while keeping participation options for these resources simple.”
The report recommended investigating a day-ahead-only addition to the DER participation model that it said could increase participation opportunities for DSRs that can operate for longer than the four hours required by the special case resource (SCR) program but cannot participate in the dispatchable DER model, which requires daily bidding and scheduling in the energy market. The report rejected requests to expand the SCR model.
Historical enrollment in NYISO’s EDRP and ICAP/SCR programs by MW | NYISO
Stakeholders representing demand response providers expressed reservations about the feasibility and cost implications of the proposals, repeating concerns expressed at previous meetings. (See Providers See ‘Mixed Signals’ on Demand Response in NYISO.)
“I am very disappointed in this report and the outcome of this yearlong process of analysis and engagement with the stakeholders,” said Amanda De Vito Trinsey, a partner at Couch White, representing the City of New York and large industrial, commercial and institutional energy consumers.
Jay Brew, managing director of Stone Mattheis Xenopoulos & Brew, who represents Nucor Steel Auburn, said he felt NYISO did not appreciate the risks their recommendations could pose to SCRs. “I’m generally disappointed with the level of effort here,” he said. “It would seem to me you’d want to be enhancing demand response as much as possible, particularly peak load response, as opposed to seeing the SCR program wither and die.”
SCRs are DSRs capable of being interrupted or curtailed by the ISO for at least four consecutive hours each day, and they act as installed capacity suppliers.
A DER can be a DSR, a generator or storage resource of 20 MW or less, or a facility of up to 20 MW composed of two or more technology types behind a single point of interconnection.
The report recommends exploring market rules that would enable SCRs to participate in the day-ahead market and allowing them to submit bids or receive schedules without re-evaluation in the real-time market. These DSRs could be able to register with energy durations of two, four, six or eight hours.
The ISO said it hasn’t decided whether day-ahead only DSRs should be allowed to aggregate, as dispatchable DER and SCRs can.
Telemetry
NYISO requires DER aggregations to provide telemetry on a six-second basis, or in real time for aggregations of at least 100 kW.
Stakeholders said this requirement could be financially burdensome, particularly for smaller SCRs.
Aaron Breidenbaugh, senior director of regulatory affairs at aggregator CPower Energy Management, said the proposal would be uneconomical for SCRs below 5 MW.
“We’ve seen the numbers for our customers that range between $10 [thousand] and $30,000 for telemetry,” he said.
“And certainly, the vast majority of existing SCR resources are below five MW.”
Breidenbaugh also questioned the ISO’s commitment to incorporating stakeholder input.
“I think [the report] is misrepresenting this concern. … The issue we have with respect to telemetry isn’t just for small customers, it is more pronounced with smaller customers, but this is a big barrier for all sizes,” Breidenbaugh said.
Expanded SCR Program Rejected
Stakeholders had urged expansion of the SCR program, saying many SCRs are now capable of operating for longer than the four-hour minimum requirement and can respond in less than the minimum 21-hour notice they now receive.
But ISO staff said the program requires extensive manual processes, making expansion impractical. Expanding the SCR model also would continue reliance on out-of-market actions, contrary to the need for more grid adaptability due to increased penetration of intermittent generating resources and storage, staff said.
Rules allowing SCRs to have multiple energy duration limits and startup/shutdown times would require the ISO “to call on them individually like DER,” staff said in the presentation. “NYISO would no longer be able to call SCRs to activate based on load zones.”
NYISO proposed using its existing DER participation model software instead of modifying the SCR program, saying it adds flexibility and cost efficiency to grid operations.
“Adding the stakeholder-requested flexibility to these processes is expected to affect the ability of NYISO grid operators to respond to system conditions quickly and efficiently,” the report said. “Making the requested modifications to the SCR program would require grid operators to understand the unique operating characteristics of individual SCRs to determine which resources are best positioned to respond to a given set of conditions.”
The ISO recommended maintaining the SCR program for the time being due to its simplicity, acknowledging that the DER model is more complex. “The NYISO does not intend to eliminate or modify the SCR model at this time, providing existing and future DSRs flexibility to choose the participation model that best fits their operating characteristics,” the report said.
ISO staff also rejected stakeholders’ request to eliminate the ISO’s proposed 10-kW minimum size for individual DER participation, which they have called discriminatory and counterproductive. (See Clean Energy Groups Protest NYISO DER Proposal.)
Staff said eliminating the threshold could significantly increase the number of small DER seeking to enter New York markets, increasing administrative costs. Staff also noted that software automation being developed for Order 2222 compliance that could help will not be in place until at least 2026.
Stakeholder Feedback
Stakeholders at the ICAP/MIWG meeting criticized the EtDS report, the ISO’s project prioritization process and what they called a lack of clarity on next steps.
De Vito Trinsey said the ISO was simply going through a “check the box” exercise rather than making a genuine effort to enhance demand-side participation.
Julia Popova, NRG Energy’s manager of regulatory affairs, concurred, questioning why ISO staff’s only recommendation was to explore the development of a day-ahead DER enhancement. “This issue seems to address only one issue among many that were raised [in previous conversation], so why was this the winning issue?” she asked.
Francesco Biancardi, a market design specialist with NYISO, responded, “We’re trying to find a path that both addresses external stakeholder feedback and addresses NYISO’s concerns regarding reliability and market efficiency. So a day-ahead demand response enhancement seemed like a good way to check all those boxes.”
De Vito Trinsey asked the ISO to explain why it hired a consultant to examine only small-scale residential DERs and not anything else within the demand-side program.
James Sweeney, a senior attorney with the ISO, responded that the consultant was hired because ISO staff did not have the bandwidth to study a group of resources that were not originally part of the EtDS project and which they were not experts in.
These specific concerns were compounded by stakeholders’ belief that the ISO failed to heed the warnings expressed previously.
“The assumption [from NYISO] is that moving demand response, particularly large customers, to the DER model will go smoothly,” Brew said, “and that seems to disregard the repeated comments that were raised by others regarding DER participation.”
Breidenbaugh had a similar view, saying, “If you’re holding [this day-ahead recommendation] as the principal outcome of this Engaging the Demand Side effort, you’re essentially ignoring all of the input that you got from stakeholders during this process.”
MISO this week promised five months of additional stakeholder discussion on its Order 2222 compliance plan before it attempts a second filing with FERC to take care of the commission’s concerns.
FERC allowed MISO an extension until May 10 to hold additional discussions with stakeholders before proposing a new Order 2222 effective date and deciding whether it can handle multinodal aggregations. The conversations largely will take place in MISO DER Task Force meetings.
During a Dec. 11 DER Task Force meeting, Managing Assistant General Counsel Michael Kessler said MISO is in the process of evaluating whether multinodal aggregations might be possible within the footprint.
Kessler also said while FERC appeared to agree MISO needs its new market platform in place before it can handle offers from DER aggregations, it must land on a closer go-live date. The RTO plans to reveal a new date and its reasoning behind it to stakeholders at the April meeting of the task force.
“We’re going to have a busy run for the next few months,” said DER Task Force Chair Zac Callen, who also is an economic analyst with the Illinois Commerce Commission.
MISO’s DER Program Manager Paul Kasper said creating bidding parameters under a multinodal aggregation will be “technically intensive.” He also said MISO will need coordination with distribution utilities to answer FERC’s questions about MISO’s proposed reliability reviews for aggregations and coordination protocols between MISO, distribution utilities and aggregators.
MISO originally said it would handle a new go-live date and multinodal aggregations in a filing separate from FERC’s other, less-intensive clarifying questions on MISO’s compliance plan. However, the grid operator since decided to make a single filing to satisfy the commission’s asks.
FERC this week refused a MISO interconnection agreement for a Michigan solar farm while Commissioner Mark Christie used the order to point out what he called a defect in the MISO tariff.
The commission said MISO is free to file another generator interconnection agreement for EDP Renewables’ Eagle Creek solar farm in the future (ER23-2443-001).
Currently, the parties to the failed GIA are embroiled in a dispute over how to divvy up ownership interests in the interconnection facilities and network upgrades necessary to accommodate the 120-MW solar farm.
Only transmission owner Michigan Public Power Agency (MPPA) executed MISO’s GIA. Michigan Electric Transmission Co. (METC), Wolverine Power Supply Cooperative and generation developer Eagle Creek declined to execute the GIA, which would have split ownership 33.33% apiece among METC, MPPA and Wolverine. The three jointly own the Styx-Murphy 345-kV transmission line, which will need to be extended into a new 345-kV station to connect the solar generation. The line is located on METC’s transmission system, and METC said it believes it should have sole ownership over the interconnection facilities and upgrades.
FERC ruled that while MPPA and Wolverine also are legitimate transmission owners with rights to the line, MISO’s GIA is inapplicable because it was written for multiple transmission facilities while the Styx-Murphy line is a single transmission facility, albeit jointly owned.
When it filed the GIA with FERC, MISO said Eagle Creek couldn’t sign the GIA because the final ownership interests of the network upgrade will affect how much it ultimately owes.
Ordinarily, MISO interconnection customers are responsible for all costs associated with network upgrades to accommodate their generation. When the network upgrades are rated 345 kV and above, interconnection customers can receive a 10% reimbursement.
However, METC operates under a circa-2007 grandfathered arrangement where interconnection customers might be eligible to be fully reimbursed when their projects are designated as network resources or have entered capacity contracts with a network customer. Those costs are covered by the load in METC’s transmission pricing zone.
FERC provided guidance to MISO when it refiled the GIA. It said Eagle Creek should pay for MPPA’s and Wolverine’s proposed combined ownership share of 66.66% of costs, with the 10% reimbursement due after commercial operation. Eagle Creek also initially should fund METC’s 33.33% ownership share and be eligible for the 100% reimbursement.
Christie wrote separately to disagree with METC’s exemption to the usual interconnection costs in the MISO tariff. He said while he agreed with the order because it follows the current tariff, interconnection customers should bear the cost of network upgrades necessary for their projects, not load.
“In 2007, the commission likely made a mistake by accepting the carve-out, which on its face appears to be unduly discriminatory and preferential and, most importantly, unfair to consumers, who should not have to pay a developer’s interconnection costs,” Christie wrote.
If NERC’s latest proposed cold weather standard fails another ballot round, the ERO’s Board of Trustees may have to take matters into its own hands, Chair Ken DeFontes warned at the board’s quarterly meeting Dec. 12.
DeFontes reported “with great disappointment” that EOP-012-2 (Extreme cold weather preparedness and operations) received only a 58% segment-weighted vote in favor in the ballot round that closed Nov. 30, short of the two-thirds required for approval.
NERC Board Chair Ken DeFontes | NERC
EOP-012-1 was approved by FERC in February with the stipulation that more work be done. (See FERC Orders New Reliability Standards in Response to Uri.) The commission identified several shortcomings in the standard and ordered NERC to submit a revised version for approval within a year.
Industry stakeholders have rejected EOP-012-2 before; the first time the standard went to a vote in July, it received only a 44% segment-weighted vote in favor. (See Industry Cool on Revised Winter Weather Standard.) But DeFontes warned that the latest rejection meant NERC was in danger of missing FERC’s February deadline.
DeFontes said the board still wishes for the standard to pass through NERC’s normal stakeholder process. To that end, NERC staff attending this week’s meeting of the Standards Committee will request the committee authorize another posting in January with a shortened comment period.
However, if the committee does not approve the posting, or if the standard fails to pass yet again, DeFontes said “the board will have no other choice but to invoke” its authority under section 321 of NERC’s Rules of Procedure to approve a standard without a successful ballot.
In the event that the board determines a ballot pool has failed to approve a proposed standard that addresses a FERC directive, section 321 allows the board to direct the Standards Committee or NERC management to develop a draft standard without stakeholder input. The standard must then be posted for a 45-day public comment period. After the comment period, the board can modify the draft standard in accordance with comments received and file it with FERC, with an explanation for the board’s decision.
“We continue to hope that our stakeholders will rise to the occasion once more and address these important reliability issues promptly, and [that] we will not have to invoke this special rule,” DeFontes said. “However, in the end, NERC must do what it needs to do, and that includes using all of the procedural tools that are available.”
DeFontes added that he would direct staff to “tentatively schedule a special call for the board to invoke the [section 321] rule,” because if the Standards Committee does not authorize the posting or the standard fails to pass the ballot, the board must make its decision “as soon as practicable.”
Trustee Sue Kelly and Vice Chair George Hawkins both expressed support for DeFontes’ position. Kelly said failing to fulfill FERC’s directive is a “situation that I just do not think is tolerable,” while Hawkins assured DeFontes that he had the board’s full support.
“Maybe this goes without saying, but [I want] everyone to understand that this is a unanimous, very powerful statement of all of us. … We are all supportive of you and your statement as board chair,” Hawkins said.
Standards Actions
While EOP-012-2 remains in limbo for now, the board did approve two other standards at the meeting.
CIP-012-2 (Cybersecurity — communications between control centers) was developed under Project 2020-04 following a January 2020 directive from FERC to refine CIP-012-1. The new standard adds requirements for actions to be taken in the event of loss of communications, NERC Vice President of Engineering and Standards Soo Jin Kim told the board.
The board also approved WECC regional standard VAR-501-WECC-4, which governs performance criteria for power system stabilizers in the Western Interconnection. The existing standard mandates that WECC review it at least once every five years to determine if any updates are needed; the regional entity’s Standards Committee developed several minor vocabulary and grammar changes as part of this review.
Trustees then voted to adopt NERC’s 2024-2026 Reliability Standards Development Plan, endorsed by the Standards Committee in October. Kim explained that the RSDP incorporates “certain administrative changes due to [FERC] Order 901,” which directed NERC to develop standards to improve the reliability of inverter-based resources. (See FERC Orders Reliability Rules for Inverter-Based Resources.) The changes were needed to allow “certain high-priority projects to be elevated” to fulfill FERC’s order, Kim said.
Finally, trustees approved NERC’s new working capital and reserves policy. The ERO’s Finance and Audit Committee adopted the policy recently in response to a FERC order in October authorizing NERC to expend unbudgeted funds from its operating reserves up to 5% of its business plan and budget without FERC approval, or to redirect budgeted funds without approval from certain program areas up to the same threshold (FA11-21).
Under the new policy, NERC must submit an informational filing to FERC if the amount drawn from reserves or redirected is between 3 and 5% of its budget; if the amount is less than 3%, no filing is needed.
Reliability Assessment Communication Questioned
A review by NERC staff of the ERO’s recently released Winter Reliability Assessment, and a preview of the upcoming Long-Term Reliability Assessment, prompted trustees to ask whether the organization is doing enough to communicate the grid’s growing risks to policymakers and the public.
Released last month, NERC’s winter assessment warned that much of North America faces elevated or high risk of energy shortfalls during extreme weather conditions, largely because of growing demand, uncertainty around the performance of solar and wind generators, and concerns about the natural gas system’s ability to serve both domestic heating and electric generation needs in extremely low temperatures.
Previewing the LTRA, which is set to be published this week, Mark Olson, NERC’s manager of reliability assessments, said risks to the grid are likely to continue rising over the coming decade. By 2028, he said, most regions of the North American grid will face a risk of energy shortfalls in extreme conditions, with MISO and a significant chunk of SERC Reliability at risk of shortfalls in normal peak conditions.
Following these reviews, Trustee Jane Allen asked NERC CEO Jim Robb if the ERO’s management is “confident that … the messages [in these reports] are getting to the right people.” She suggested that NERC might have more success getting “the attention of the people who need to address this” by being more explicit about the implications of inaction.
Robb told Allen that NERC’s outreach at the moment is focused on “those immediate actions that can alleviate the pressure.” He said a significant challenge in this area is “that the solutions are slow to bring to bear because most of these are structural issues,” and he praised the REs for “doing God’s work” by communicating with state and provincial governments that can help to implement the needed solutions.
Responding to Robb, Kelly returned to Allen’s point, urging management to consider whether other communication strategies could help get the needed information out.
“We say all these things, but we don’t necessarily do what lawyers would call the parade of horribles — [what ensues] if you don’t do something,” Kelly said. “Winter Storm Elliott provides a perfect example, [with] rolling blackouts; Winter Storm Uri, people freeze; these are the consequences of inaction. … If we could, perhaps, just do a little bit on what happens when we don’t do what we need to do … at least in the more popular press or [among] policymakers … it might help get the message out a little bit more.”
Level 3 Alert Results
Darrell Moore, NERC’s director of situational awareness and personnel certification/credential maintenance, provided an overview of results from the ERO’s first-ever Level 3 alert, issued in May to gather information on registered entities’ preparations for extreme cold weather. (See “ERO to Issue First Level 3 Alert May 15,” NERC Board of Trustees/MRC Briefs: May 10-11, 2023.)
Moore said replies to the alert were reassuring for the most part, with “an overwhelming majority” of generator owners reporting that more than 90% of their facilities would be capable of operating at their extreme cold weather temperatures. However, many utilities indicated that freezing conditions “remain a reliability issue for generators,” with concerns about improper heat tracing, frozen instrumentation and control valves, and lack of fuel supply in critical conditions.
Asked by Robb about the usefulness of the Level 3 alert, Moore said the ERO considered the previously unused process a success both in informing utilities of needed cold weather preparations and gathering information on their progress.
“One of the things that this alert has allowed us to do was get a greater understanding of what some of the entities are doing with their essential actions … and it’s allowing us to dig a little deeper … for some of the unfavorable responses that we receive,” Moore said.
NERC Chief Engineer Mark Lauby told trustees that the organization will likely issue another Level 3 alert in the next few months focused on IBRs.
Electricity restructuring is often discussed as a binary — either a state uses market forces, or it does not — but a recent webinar from the Energy Choice Coalition dove into all the complexities it has led to since it started in the 1990s.
While individual states all have their own unique mix of rules, the R Street Institute’s paper, “Electric Paradigms: Competitive Structures Benefit Consumers,” puts them into three categories: 18 traditionally regulated, 19 with a hybrid system of wholesale competition and no retail, and 14 (including D.C.) with both wholesale and retail competition.
“We wanted to diagnose that as sort of a basic fact about the current system,” Michael Giberson, R Street senior fellow and the report’s co-author, said on the webinar. “And then we wanted to see for each of these three systems, how does the evidence stack up in terms of how they’re serving customers.”
The report dives into details around how markets have been viewed as saving or costing money for customers; how they have impacted reliability; and their environmental outcomes. It summarizes numerous other studies from both sides of the argument.
“Restructuring, when done well, has done well,” the paper says. “Restructuring likely benefits reliability, reduces emissions and unleashes efficiencies at the wholesale level that get passed along to consumers when retail competition is allowed to work.”
How emissions have declined in the different organized markets | R Street Institute
Most of the change in recent years has come from states joining MISO and SPP but not deregulating their retail sides. That trend is ongoing in the West with discussions around market alternatives, but Meghan Nutting, Sunnova Energy executive vice president of government and regulatory affairs, said technological change has made generation monopolies at the retail level functionally nonexistent.
“Because of rooftop solar, and because of other technologies and alternatives that consumers have, it means they don’t have to rely solely on their monopoly generation provider for electricity,” Nutting said. “And so, the more that regulators and the more that our government structures try to support and protect those former generation monopolies, that’s just protectionism of individual companies at this point, because there is competition within their market.”
Retail competition has seen pushback in some states like New York and Massachusetts because retailers were offering higher prices than the standard offers from the utilities, which for the most part in restructured states were left as providers of last resort (POLR) for mass-market customers. Only Texas eliminated the utilities’ POLR role in its market, which even then is only inside ERCOT and only required of investor-owned utilities (leaving out Austin, San Antonio and other cities served by municipally owned utilities).
The paper says that critics of those higher-priced contracts have identified “valid problems” with the markets that can be fixed with better rules, such as improved licensing processes and oversight. It calls on states to move to “better paradigms” — i.e., those in hybrid states moving to full restructuring.
“When moves to a better paradigm are impossible at present, policymakers should seek out improvements within existing structures,” the paper says. “Importantly, even policymakers in fully restructured states have opportunities to improve competition within that paradigm as well.”
Moving toward more competition takes “significant decisions away from utilities and regulators” and places them in the private sector. Regulators are ostensibly supposed to make decisions that take into account the interests of consumers and other groups, but the paper notes that process can be corrupted in ways the market cannot, citing recent scandals with traditionally regulated utilities influence peddling, bribing officials and intimidating journalists.
“What we’re seeing is competition within these spaces that exists already, protectionism for the incumbent, and then inadequate regulation in place of markets that would allow consumers to drive the outcomes that would likely be better,” Nutting said.
Regulators have to make sure that utilities do not give into the economic incentive of investing in higher-cost resources to earn higher returns, while markets outright offer the opposite incentives, said Lynne Kiesling, director of Northwestern University’s Institute for Regulatory Law & Economics.
“If I come in with a lower-cost technology, and I’m competing in a market against higher-cost technologies, I’m going to earn more profit, because I’m lower-cost,” Kiesling said. “And that incentive is very, very powerful, and it benefits both producers and consumers.”
The paper highlighted how that effect of markets can influence environmental outcomes, as they have favored natural gas plants and renewables over coal.
“An earlier study found that reductions in natural gas prices and the growth of wind power both contributed to the decreased use of coal plants in RTOs, with a resulting reduction in carbon emissions,” the paper says. “The effects pushing emissions down were weaker in SPP, which researchers speculated was caused by the ways in which monopoly-owned generators — dominant in SPP — respond to market incentives as compared to non-utility generators.”
Natural gas prices have had major impacts on markets in other ways, with the report suggesting that the outcome of lower prices in retail markets depends on a state’s access to cheap supplies of the fuel.
A soon-to-be-published study in The Energy Journal has found mixed results with retail competition’s prices — finding they have gone higher in four of the five restructured states in New England while falling in Pennsylvania and Texas, the R Street paper says.
“Both Pennsylvania and Texas were well positioned to access cheap natural gas resulting from advanced drilling techniques like fracking,” the paper says. “New England, on the other hand, has limited ability to bring in domestically produced natural gas and must resort to importing expensive liquefied natural gas to run natural gas generators during periods of high gas demand.”
The Maryland Energy Administration (MEA) has $22.5 million it’s planning to use to make low-income homes more energy efficient and put solar panels on their roofs. It just wants to make sure none of the money is spent on new appliances or systems powered by fossil fuels.
The MEA, along with Gov. Wes Moore (D), announced Dec. 11 the money will be available through two long-standing programs — the Energy Efficiency Equity (EEE) Grant Program and the Solar Energy Equity (SEE) Grant Program — but with some new requirements and opportunities for 2024.
EEE will offer $19.5 million for energy-efficiency upgrades that “generate significant reductions in energy use and pass on the benefits of the savings” to Maryland’s low- and moderate-income residents, according to the MEA website.
But in a significant shift, the program will prioritize “electrification and zero-emissions technologies,” according to the funding announcement.
“Therefore, beginning in [fiscal 2024], the replacement of existing fossil fuel equipment (e.g., HVAC, water heater) with new fossil fuel equipment is ineligible for funding via the program, even if the proposed new equipment has a higher efficiency rating.”
Upgrades to existing fossil fuel equipment will be funded provided they increase system efficiency, the announcement says.
Extra funding also will be available to pay for additional upgrades that support electrification, such as the installation of new electrical panels or circuits.
The application deadline is Feb. 16.
The Solar Energy Equity (SEE) Grant Program will have $3 million to pay the full cost — up to $25,000 — of installing solar panels on the roofs of homeowners in LMI or “overburdened” communities, which are defined as areas that historically have suffered from high levels of air or water pollution or other environmental impacts.
To qualify for the program, a household already must have participated in a state-funded weatherization or energy efficiency program, such as EEE. Up to $5,000 of a $25,000 grant can be used for roof repairs or mold remediation.
The program also allows homeowners to choose either owning the rooftop panels outright or enrolling in a leasing program in which state funds are used to pay off a 20-year leasing contract so the homeowner has no further payments on the system.
Households that go for an ownership option will be allowed to sell the solar renewable energy credits (SRECs) generated by the system, with the proceeds to be used for system maintenance and insurance.
Solar owners earn one SREC for every 1,000 kWh of power their panels produce; the current value of an SREC in Maryland is about $52 to $56, according to the Flett Exchange, an online platform for SREC sales.
The application deadline for the SEE program is Feb. 22.
MEA Administrator Paul Pinsky framed the programs as an integral part of the state’s march toward a 60% reduction in greenhouse gas emissions from 2006 levels by 2031, a target set in the Climate Solutions Now Act (CSNA) of 2022, and Moore’s goal of a 100% clean energy grid by 2035.
Pathways to Electrification
Both Moore and Pinsky stressed that the funding for the two programs is aimed at ensuring an equitable energy transition in which no communities or households are left behind.
The funding for both programs will go through nonprofits or local governments but is set up to reach a range of communities. For the EEE program, Maryland is divided into five regions, each of which is allocated a certain amount of the $19.5 million, based on population, with a 25% carveout for funding to groups that previously have not been awarded grants from the program.
For example, the Western region of the state — including Frederick, Washington, Allegany and Garrett counties — has been allocated just under $1.9 million, with $484,203 earmarked for first-time applicants.
The EEE ban on new appliances powered by fossil fuels appears to be a careful step toward reducing natural gas use in Maryland, in the absence of direct state-level legislative action on the issue. In November 2022, Montgomery County, Maryland’s most populous county, passed a law requiring the electrification of all new residential and commercial construction, with exemptions for certain businesses, such as restaurants. The new rules are scheduled to go into effect by the end of 2026. (See Montgomery County, Md. Passes Building Electrification Law.)
The CSNA also required the Maryland Department of the Environment to develop building performance standards for commercial buildings of 35,000 square feet or more, with the goal of cutting GHG emissions from these buildings 20% below 2025 levels by 2030 and reaching net zero by 2040.
The proposed regulations are scheduled to be released Dec. 15.
High levels of self-scheduled exports out of CAISO’s balancing area to support stressful conditions elsewhere led the ISO to declare Level 1 energy emergency alerts in late July, the Department of Market Monitoring explained last week.
The alerts, issued for July 20, 25 and 26, were not related to bad weather conditions in California, but actually in areas to its north and south, said Ryan Kurlinski, senior manager of market and policy analysis with the DMM.
Typically, during peak net load hours in the summer months, power flows from the Northwest into the rest of the system. But this July saw relatively low hydro conditions in the Northwest compared with relatively high ones in California. This was coupled with extremely high temperatures in the Southwest that lasted even after peak net load hours, leading to record demand there.
“What we saw this year was a significantly different pattern from previous years,” COO Mark Rothleder said. “What we saw was a higher level of exports and demand outside of our system, and for a large period of time, we could support that demand, but there were times … where we could not.”
When the EEA was declared on July 20, CAISO operators had not yet identified exports they were unable to support in the hour-ahead market. As solar began ramping down, there was still relatively high demand across the system between 6 and 8 p.m. Throughout the day, CAISO had sufficient bids from its contracted capacity to cover its own requirements, but beginning around 8 p.m., “the addition of the exports required CAISO to rely on bids from resources not contracted to serve CAISO load,” Kurlinski said.
While the ISO was close to being unable to deliver exports that had received hour-ahead market schedules, operators ultimately did not curtail any load.
On July 25 though, CAISO was unable to award several thousand megawatts of self-scheduled exports between 6 and 9 p.m.
“I’m calling that the first significant market issue impacting WEIM [the Western Energy Imbalance Market] in this period,” Kurlinski said. “CAISO did not give hour-ahead market awards to all exports that wanted to self-schedule in the hour-ahead market.”
Each of the three real-time markets have a load forecast that the market solves for, and operators frequently adjust this load above the forecast, particularly during net peak load in the hour-ahead and 15-minute markets to cover any uncertainty over available supply. Uncertainty materialized quickly on July 20, Kurlinski said, and by July 25, operators began dramatically increasing the load adjustment.
“These large hour-ahead market load adjustments contributed significantly to the large quantity of exports attempting to self-schedule out of CAISO that did not receive hour-ahead market awards,” Kurlinski said, but “CAISO operators did actually end up allowing a decent portion of these exports to tag … and ultimately flow to other balancing areas.”
Not enough supply could prevent the hour-ahead market to self-schedule exports, but the load adjustment can also be supplied by advisory WEIM transfers flowing into CAISO’s balancing area. If the transfers don’t flow into CAISO in the five-minute market, however, the ISO may not have enough supply to meet load requirements and self-scheduled exports in the hour-ahead market.
“This concern arose on July 25, and my understanding is that it prompted the CAISO balancing area to start limiting the WEIM transfers into its area in the hour-ahead market,” Kurlinski said. From 7 to 8 p.m., the ISO put a 4,000- to 5,000-MW load adjustment into the market, and while much of it was supported by WEIM transfers in the hour-ahead market, almost no five-minute transfers flowed into CAISO.
On July 26, CAISO started strictly limiting WEIM transfers into its balancing area during peak hours, which marked the second significant issue.
The limit significantly impacted transfers in other WEIM areas, such as in Arizona, where transfers to CAISO from Arizona Public Service decreased to zero at one point.
Observations and Lessons Learned
Rothleder shared observations that could help the ISO prepare for any similar conditions in the future, should they arise.
“Between the 20th and the 25th, we took the learnings and the observations, and we applied that [in the 7 p.m. hour] on the 26th,” Rothleder said. “This is what triggered us to limit the amount of transfers the California ISO was relying on from others when we were clearing that hour-ahead scheduling process.”
Limiting transfers, he said, helped reduce uncertainty and increase confidence in the ability to serve load. He also highlighted that the load adjustment aided in dealing with additional uncertainty.
Unusual conditions led to the issuing of the EEA, but all things considered, Rothleder emphasized that it was a successful summer overall for the ISO.
“It’s unprecedented that we would be a net exporter in a summer period, but this past July, we saw periods where we were a large net exporter supporting other parts of the West as they were approaching 96% of their record load outside of the ISO,” he said.
While CAISO did enter a few EEA watches and declared the Level 1 alert, it did not have to issue any flex alerts or experience any load-shedding events.
“The system is becoming more complicated, and we’re seeing flow patterns that are significantly different from historical patterns, and this highlights really the need for that coordination and awareness of the constraints that may arise earlier,” Rothleder said. “That’s why we believe things like the Extended Day-Ahead Market provide the vehicle for that strong coordination, awareness and insurance.”
