Developing wind power on the two Great Lakes bordering New York would entail a set of challenges so expensive as to be uncompetitive with other renewable energy options, a new report concludes.
The New York State Energy Research and Development Authority last week submitted its Great Lakes Wind Energy Feasibility Study and supporting material to the state Public Service Commission, which in 2020 instructed NYSERDA to undertake the study.
NYSERDA recommended shelving the lake wind concept for at least the near term.
The study indicates that modeling shows potential for as much as 2 GW of nameplate wind power capacity in Lake Erie and 18 GW in Lake Ontario.
But it also flags several sticking points:
Lake Ontario is so deep that development there would rely on floating turbine technology, still in its infancy.
Both lakes ice up in the winter.
An entire onshore supporting infrastructure would need to be created, along with points of interconnection for the electricity generated.
Unlike the extensive OSW capacity that the state is developing in the Atlantic Ocean, the Great Lakes are far removed from the densely populated New York City region, where the need for clean energy is greatest.
The construction vessels used to erect offshore wind farms will not fit in the locks that lead to the Great Lakes.
A white paper submitted with the study concludes that wind farms in the two lakes would be substantially more expensive for ratepayers to support than other projects under Tier 1 of the state’s Clean Energy Standard, such as terrestrial wind and solar. That does not include construction of ports, ships and points of interconnection, which would be additional costs for ratepayers to bear.
NYSERDA began conducting the study in February 2021. Some support was offered for the idea of Great Lakes wind during the public input process, but extensive concern was raised about its impact on wildlife and on views from the shore.
Preserving the viewshed would be a significant limiting factor; siting turbines at least 12 miles offshore would limit the potential hosting capacity in Lake Erie to just 200 MW, for example.
There’s also widespread sediment contamination in the Great Lakes, a legacy of the industrial history of the cities along its shores. That contamination is not well-mapped, NYSERDA notes, nor is it known what effect construction would have on the contaminants.
“After completing the feasibility study and considering these various dimensions collectively, NYSERDA recommends that now is not the right time to prioritize Great Lakes wind projects in Lake Erie or Lake Ontario,” the white paper indicates.
But it adds: “Taking no action now does not mean there may not be an opportunity to advance Great Lakes Wind at some point in the future. The resource may become a feasible contributor to New York State’s goals in the future as the state advances toward its mid-century goals.”
An organization advocating for offshore wind buildout said the study made a convincing case.
“While New York needs a serious buildout of renewable energy sources and there is documented potential for wind resources in the Great Lakes, it’s clear from the report that the focus should remain on solar, land-based wind and offshore wind power in the Atlantic. Right now, these are the more critical, substantial and cost-effective opportunities,” New York Offshore Wind Alliance Director Fred Zalcman told NetZero Insider.
There is extensive interest in offshore wind as an emissions-free source of electricity, with the Biden Administration setting a goal of 30 GW installed capacity by 2030.
Just one facility is online in the U.S., producing up to 30 MW off the Rhode Island coast, but a few others are under construction and many more are in some stage of development.
Only one is in freshwater — the 20.7 MW Icebreaker project near Cleveland in Lake Erie — and it is still in development, more than 13 years after it was proposed.
NYSERDA said the Ohio project could eventually help inform New York’s decision-making process on wind turbines in its Great Lakes waters.
A previous proposal to build a freshwater wind farm in New York proved highly contentious. After nearly four years in the review process, developers in early 2019 withdrew their plans for a 108 MW project near Watertown, in the northeast corner of Lake Ontario.
Industry, private developers and state governments from every region of the nation applied for federal funding to create hydrogen hubs consisting of industries or transportation companies interested in switching from carbon-intensive fuels to hydrogen.
Seventy-nine groups offered to invest a total of $157 billion for a chance to qualify for $7.5 billion in federal H2Hub matching grants, according to an unpublicized report now available on the Department of Energy Office of Clean Energy Demonstrations’ website. The report notes that DOE would require about $60 billion were it to approve all of the applications.
The department does not plan to announce or identify those applicants it has discouraged, nor identify those it has encouraged, to file a full application by close of business April 7.
Faced with so many preliminary or “concept” applications, all filed by the Nov. 7 deadline, DOE appears not to have made final decisions on all applications until the end of December, based on the few announcements made by some of the “encouraged” applicants.
And the department is leaving the door open for 46 applicants it has tried to “discourage.” Though their initial applications were determined to be incomplete or not feasible, they are free to file a full application or join with one of the 33 groups DOE has encouraged.
In an effort to explain the process its reviewers used, the department said it favored groups that appeared to have the best chance of creating a working hub — hydrogen production and nearby hydrogen consumption — in the earliest possible time.
“The encouraged concept papers plan to develop all elements critical to a H2Hub: comprising production, end uses and connective infrastructure; demonstrating capabilities to execute a project plan or to attract and hire such capabilities; planning to deploy proven technologies; and indicating commitments to clean hydrogen and meaningful community benefits,” the report noted.
The report also tried to explain why it rejected, or discouraged, some applications.
“The 46 concept papers were discouraged for many reasons, but one of the most common reasons was papers that described concepts focused on only one element of the hub. Concept papers were also discouraged that would depend on technologies unready for commercial-scale demonstrations and projects whose elements were not readily suited to help catalyze a national clean hydrogen network.”
And the report specifically noted that those applicants who have just received an “encourage” review are not guaranteed a win next year.
“An encourage notification simply means that the proposal is on the right path towards submitting a full application. DOE expects significant competition amongst applicants, even if only encouraged applicants proceed.”
Energy Secretary Jennifer Granholm announced the availability of the grants at a September hydrogen conference in Pittsburgh attended by more than 6,000.
The grants, funded by the 2021 Infrastructure Investment and Jobs Act, are the first step toward moving industry and transportation from hydrocarbon fuels to hydrogen, and key to the Biden administration’s goal to decarbonize the economy by 2050.
DOE appears not to have contacted applicants until after Christmas, based on the few news releases issued by the groups that received a “thumbs up” response.
The department contacted the 79 groups that had submitted applications, “encouraging” 33 of them to file full-blown applications by April 7. Those groups officially “discouraged” may still file full applications, the report noted, or they can join the encouraged groups.
A media search Monday indicated the following hydrogen hub applicants had received a positive DOE review:
Hawaii Pacific Hydrogen Hub;
HALO Hydrogen Hub, proposed jointly by Arkansas, Louisiana and Oklahoma;
Western Interstate Hydrogen Hub, proposed by Colorado, New Mexico, Utah and Wyoming;
Pacific Northwest Hydrogen, proposed by Washington state and Oregon;
ARCH2, by West Virginia, Pennsylvania, Ohio and Kentucky; and
FERC last week ordered FirstEnergy (NYSE: FE) to pay a $3.86 million fine and submit annual compliance monitoring reports to the agency’s audit division for the next two years detailing compliance measures and procedures the company has put in place to comply with commission regulations.
The fine and mandated annual report to FERC’s enforcement division are part of a settlement (IN23-2) between the company and FERC auditors and approved by the commission Dec. 30. Auditors determined that FirstEnergy executives had repeatedly lied when asked in 2019 and early 2020 about the company’s expenses for lobbying and governmental affairs.
A subsequent probe made public in June 2020 by the U.S. Attorney for the Southern District of Ohio found that the company funneled more than $60 million through a dark money nonprofit 501(c)(4) corporation, Generation Now, to former Ohio House Speaker Larry Householder (R) between March 2017 and March 2020 for his efforts to pass legislation subsidizing two uncompetitive FirstEnergy nuclear power plants in northern Ohio.
Householder shepherded the passage of H.B. 6 in June 2019, providing a little over $1 billion in public funding over the coming seven years. The legislation was later repealed at the request of Energy Harbor, the new owner of the power plants.
Householder and four associates were subsequently indicted on federal racketeering charges. Householder’s trial in a federal district court is set to begin later this month, though jury selection could delay the start. FirstEnergy pled guilty to wire fraud in a deferred prosecution agreement in July 2021 and agreed to pay a $230 million fine. The company has also fired several top executives, including former CEO Chuck Jones.
FERC auditors determined that not only had FirstEnergy misled the agency about the $60 million in dark money contributions for the passage of the bailout legislation, but that the company had also failed to mention that, between 2010 and January 2019, it had paid over $22 million to two small Ohio companies owned by Samuel Randazzo, a utility lawyer and long-time Ohio lobbyist who became chair of the Public Utilities Commission in 2019.
Gov. Mike DeWine appointed Randazzo Feb. 4, 2019.
Randazzo has not been charged. He resigned from the commission in November 2020, a few days after FBI agents raided his downtown Columbus condominium, leaving with several file boxes. Randazzo’s assets have been frozen.
Massachusetts regulators on Friday denied Avangrid’s request to back out of power purchase agreements for the 1,200-MW Commonwealth Wind project it committed to build off the state’s coast.
Avangrid contends that it cannot obtain financing under terms of the PPAs negotiated with three electric distribution companies, and said it wants to rebid the project under the state’s next offshore wind solicitation.
In October, Avangrid sought to delay for one month the state Department of Public Utilities’ review of the PPAs, which DPU refused. Avangrid said in November that it would continue with the proceeding, then in December asked for dismissal, saying that the PPAs were insufficient to finance the project and that three companies — Eversource Energy, National Grid and Unitil — had refused to meet with it to work on a compromise.
On Dec. 30, the DPU approved the PPAs, saying Avangrid had not made its case and that “the companies have demonstrated that the pricing terms in the PPAs are reasonable for offshore wind energy generation resources.”
Avangrid spokesperson Craig Gilvarg disagreed, saying the company gave the DPU clear evidence that global economic and supply chain bottlenecks rendered the PPAs untenable.
“Avangrid is disappointed in the order issued by the Department of Public Utilities and continues to review the department’s decision while assessing its legal options,” he said via email Tuesday.
Avangrid has an extensive offshore wind portfolio in development worldwide, including the 800-MW Vineyard Wind I project under construction off the coast of Massachusetts.
Gilvarg said the company remains committed to making the Commonwealth Wind project work. “As we assess our options and pursue the best course for the project, we will continue to work closely with our business, labor, industry, environmental and community partners, as well as the incoming Healey-Driscoll Administration, to ensure Commonwealth Wind can move forward, maintain the same urgent timeline, and help Massachusetts meet its nation-leading climate target for 2030.”
Developers of another offshore wind project in Massachusetts, Mayflower Wind Energy, moved in parallel with Commonwealth Wind in the autumn of 2022, seeking to pause DPU review of their PPAs for the same reasons: high inflation, sharp interest rate hikes and supply chain shortages.
Developers of Mayflower, which would deliver 405 MW of wind power, have stopped short of seeking to void the PPAs, saying they would seek to resolve its issues through collaboration. But they emphasized those issues remain unresolved.
In a Dec. 23 DPU filing, Mayflower said that although it was taking a different path from Commonwealth, “Mayflower Wind respectfully must nonetheless agree with much of the factual analysis underlying Commonwealth Wind’s conclusion, especially as Mayflower is subject to these same facts, pressures and realities. … The project and tax equity financing required for the delivery of Mayflower Wind Project, along with the cost of such financing, has changed dramatically and unexpectedly as interest rates have risen sharply, presenting significant challenges to the Mayflower Wind Project’s economics.”
Mayflower also said Commonwealth’s motion to dismiss had disrupted the procurement process and asked the DPU to “allow time for coordinated, meaningful discussion among all interested parties” before making a final decision on the Mayflower Wind PPAs.
But the DPU approved the Mayflower PPAs in the same Dec. 30 order as it approved Commonwealth PPAs.
President Biden on Tuesday named Commissioner Willie Phillips as the acting chairman of FERC, replacing Richard Glick after he departed at noon.
“It is an honor to be chosen by President Biden to lead FERC at such a pivotal moment,” Phillips said in a statement. “The work we do here at FERC is crucial to ensuring consumers have access to reliable, safe, secure and efficient energy services at reasonable cost. I look forward to continuing to work with my fellow commissioners and the FERC staff, as well as to prioritize public engagement, in pursuit of our important mission.”
Glick’s chairmanship officially ended at noon Tuesday, when the 117th Congress adjourned. Biden had nominated him for a second term, but Sen. Joe Manchin (D-W.Va.) refused to hold a confirmation hearing for him. Manchin, however, approved of Phillips’ appointment.
“Willie Phillips is a supremely qualified and reasonable person, and he understands the need to balance affordability and reliability,” he said in a statement. “I look forward to working with acting Chairman Phillips in his new position as we pursue an all-of-the-above energy policy that will enhance our national and economic security.”
The congratulations from Phillips’ colleagues flowed on Twitter after the news broke.
“The commission is in good hands as our nation continues the transition to the clean energy future,” Glick tweeted.
FERC Commissioner Mark Christie said his former colleague in the Organization of PJM States Inc. would “do a great job.” Commissioner Allison Clements chimed in with her own congratulations, saying she hoped the commission would move forward on the many proposed rulemakings issued under Glick. (See FERC’s Work in 2022 Left in Doubt by Manchin.)
Biden was able to make the move, which was first reported by Bloomberg, because the president has the unilateral authority to name a commissioner already confirmed by the Senate as chair.
Phillips becomes the first Black person to helm the regulatory agency and was elevated to the top spot a little over a year after becoming commissioner. He was previously chairman of the D.C. Public Service Commission and has a 20-year legal career that includes working as assistant general counsel to NERC. He holds a law degree from the Howard University School of Law and a bachelor’s from the University of Montevallo.
Phillips is also the first former state regulator to run FERC since Pat Wood III ran the agency in early 2000s under President George W. Bush.
The “acting” designation means Biden is waiting until he nominates a person to fill Glick’s seat to name the permanent chairman. But ClearView Energy Partners said it is likely Phillips will be named the permanent chairman, and that “dealing with FERC gavel on an acting basis may simply be a matter of administrative expediency.”
In addition to Glick’s seat, Commissioner James Danly’s term is set to expire on June 30. Whomever is chosen for the two seats “could change the outlook for policy direction at FERC over the balance of Biden’s term,” ClearView said. “We therefore acknowledge that it is possible but not necessarily probable that a yet-to-be-identified individual may yet be nominated to FERC as chairman.”
Though Clements has been with the commission for a year longer than Phillips, ClearView said Phillips is likely to “draw less direct fire from GOP legislators in both chambers” given his experience and Clements’ more vocal support for the commission’s proposals to review natural gas infrastructure’s impact on climate change as part of its approval process.
The Electric Power Supply Association welcomed the designation, with its CEO, Todd Snitchler, urging Phillips to increase the commission’s focus on reliability as the grid transforms.
“While we recognize the need to address climate change, power outages and cost spikes have devastating consequences; reliability cannot be taken for granted in pursuit of aggressive policy aspirations not aligned with operational realities of the power system,” Snitchler said.
Phillips should “renew a commitment” to FERC’s core mission of ensuring adequate infrastructure, reliable power and well functioning competitive markets, he added.
Ohio regulators cleared American Electric Power (NASDAQ:AEP) of any wrongdoing in its response to severe storms that left more than 240,000 Ohio customers without power for up to two days in June, but said the company should develop a more aggressive vegetation management program on its transmission lines.
About 606,000 AEP Ohio customers lost service between June 13 and 19, including 283,000 who were cut off because of load sheds ordered by PJM.
PJM ordered load sheds to prevent overloads and cascading outages between June 14 and 16 after a storm identified as a derecho downed transmission and distribution circuits and sent dangerous volumes of power onto remaining lines.
Six lines failed on June 14 and 15, causing AEP to shed loads. | Public Utilities Commission of Ohio
Some customers accused the company of racism for cutting power to poor areas of Columbus while continuing service to richer suburbs. But the staff of the Ohio Public Utilities Commission said there was no evidence that the company acted improperly. (See Vegetation Eyed in AEP Ohio Outages Following Storms.)
AEP Ohio was required to take action within 30 minutes after PJM ordered the first of five load shed directives totaling 396 MW at 1:57 p.m. on June 14, PUCO staff said in its report Tuesday.
“After review of AEP Ohio’s actions during the load shed event, it is clear to staff that the company had very little time to communicate to its customers and to react to PJM’s directives in the selection of the circuits that needed a reduction in load,” it said. “The number of customers, the type of customers (residential, commercial or industrial), and the specific location of the customers are not readily available to the operations team and are not considered. The only criterion for selecting those feeds is the amount of load they are carrying.”
Staff said they believed the heat wave alone would not have caused any outages “and that it was only because of the damage caused by the storm that shedding load was necessary.” They noted that temperatures in the Columbus area reached highs of more than 95 degrees Fahrenheit days after the storm, but it resulted in no load shed orders.
Four transmission lines failed on the morning of June 15, including three that failed during the first event. | Public Utilities Commission of Ohio
But while staff said AEP Ohio had complied with state regulations, it said it was concerned about the utility’s transmission vegetation management program, particularly those outages attributed to “grow-in” vegetation — when vegetation comes into contact with lines but is still part of a growing plant.
“AEP Ohio has asserted that although the lines came into contact with trees and limbs that were still intact, it happened only because the storm itself impacted the vegetation in and around the [right of way] enough that the landscape changed,” the report said. “Staff understands this point and can accept that this may be the case. However, it believes that if the trees were in a position that allowed the storm to alter them to the point that they caused a grow-in outage, then perhaps they had not been trimmed enough.”
Although staff concluded that AEP complied with its commission-approved vegetation control plan, they said it “should re-evaluate its approach on its transmission vegetation management plan and move to a more cyclical trimming schedule, similar to its distribution plan.”
Staff also called for the utility to strengthen its community outreach plan for working with emergency responders and community organizations to supplement its own communications. “In both rural and urban centers, emergency responders and community organizations play a vital role in spreading valuable information and services to the communities that they serve,” staff said. “Efforts should be made to capitalize on this important community asset.”
Transparency Criticism
Merrilee Embs, spokesperson for Ohio Consumers’ Counsel Bruce Weston, criticized the report, saying the commission failed to involve the public and the Consumers’ Counsel, as the group and others had requested.
“That public process we called for has not happened despite the motion for an investigation that we, the Poverty Law Center and Pro Seniors filed at the PUCO in July,” she said. “Energy justice for hundreds of thousands of AEP consumers who lost their electricity should be served with a process that is transparent and inclusive of the public and their representatives. While we appreciate today’s PUCO report, it begs questions including why there would be outages from electric wires damaged by trees considering the money that AEP charges consumers for tree-trimming.”
The outages began after a line of storms moved through Ohio on June 13, damaging multiple electric lines throughout the state. Wind speeds reached as high as 90 mph and at least three tornadoes were reported.
Because the majority of the outages were caused by wind, trees or a combination of both, staff said it focused its investigation on circuit inspections and vegetation control for transmission lines.
After the first load shed directives beginning at about 2 p.m. on June 14, PJM issued a second set of load shed orders totaling 170 MW at about 7:30 p.m.
Staff noted that AEP’s system faced unusual strains as power was restored during the hot weather.
“While on hot days [air conditioners] are running throughout the area, they are not all running at the same time; it is staggered throughout the day, which serves to naturally levelize the overall load. But during the restoration period following a large storm outage, on a hot day, large numbers of customers are getting their power turned back on at the same moment. … So, all of their AC units turn on shortly after the power comes on and they run continuously for longer-than-usual periods because it takes time to reduce the temperature down to the level set on the thermostat.”
All customers affected by the two rounds of load sheds were restored by 9:48 a.m. June 15.
But the failure of four transmission lines that morning — including three that failed the day before — caused PJM to order additional load sheds totaling 479 MW.
The last of the affected customers had service restored by 4:51 a.m. on June 16, PUCO said.
PJM backtracked on posting “indicative” results of the 2024/25 capacity auction Tuesday in the face of stakeholder opposition.
During the Dec. 21 Members Committee meeting Senior Vice President of Market Services Stu Bresler said PJM intended to publish the results on Jan. 3, after filing a tariff change request with FERC to address a “mismatch” in the auction results. That submission was filed with FERC on Dec. 23 (EL23-19, ER23-729).
Bresler said the RTO would file the auction results under the existing rules and PJM’s proposed fix to allow stakeholders to evaluate the impact of the proposal before filing comments on it.
“Following consideration of the substantial stakeholder feedback received, PJM will not post indicative results at this time,” a PJM message to stakeholders said. PJM spokesman Jeff Shields said no decision has been made on whether the results will be posted in the future.
Among those options some stakeholders said they hope the commission may consider is permitting auction participants to change their sell offers based on the changes made to the market structure.
Paul Sotkiewicz, president of E-Cubed Policy Associates, said publishing the results could also create unnecessary polarization between groups because of price changes. He urged PJM to refrain from releasing any results until the issue has been settled with the commission.
Independent Market Monitor Joseph Bowring also pushed against releasing the results during the MC meeting, calling them incorrect and irrelevant.
PJM Seeks to Revise Auction Parameters in FERC Filings
Laying out the mismatch that led to the postponing of the auction closing, Bresler said generation included in the calculation reliability requirement for the DPL South locational deliverability area (LDA), which is centered on the Delmarva Peninsula, did not ultimately enter into the auction. Because of a quirk in the functioning of the reliability requirement in small LDAs, the inclusion of that generation elevated the capacity called for by the requirement. When that generation did not offer into the auction, it led to what PJM considers an unjust and unreasonable artificial inflation of clearing prices in that zone.
In its petition to FERC, PJM proposes revising the LDA’s reliability requirement to exclude the generation that did not offer into the auction. The changes would function as an additional factor in the optimization algorithm and be applied prior to the closing of the auction.
“Absent the ability to include this additional factor in the optimization algorithm, PJM would be forced to utilize a materially inaccurate locational deliverability area reliability requirement that does not reflect the actual capacity needs of the particular LDA in question and would result in an unjust and unreasonable outcome” the filing states.
PJM argued to FERC that none of the market fundamentals, such as the amount of supply or load, in the DPL-S LDA had changed since the previous auction and that the increase in clearing prices does not accurately reflect economic realities.
“To be clear, to the extent the LDA is tight on capacity, prices would be expected to separate and be higher than the rest of the RTO. However, in this case, as a result of this confluence of events … the prices become no longer linked to the actual reliability requirements of the LDA and the reliability needs of the LDA are not properly reflected in the auction results,” the filings say.
Should this set of circumstances affect future auctions before a long-term solution is found, PJM’s proposal is to use the same methodology in the filing whenever an LDA’s reliability requirement increases by more than 1% from the prior year due to the inclusion of resources that did not offer into auction.
Without adjustments, PJM said, the algorithm would result in clearing prices approximately four times higher than if those resources were removed from the calculation of the reliability requirement. The requirement increased by 373 MW, or 12%, over the 2023/24 Base Residual Auction (BRA) parameters, while no other LDA deviated by more than 1%.
The figure is calculated for each LDA by combining its internal generation and capacity emergency transfer objective (CETO), which is the amount of imports necessitated by the region’s expected load and anticipated outages. Bresler said the addition of large facilities or intermittent generation into a small LDA — particularly one with a higher winter load that does not align with solar output — can result in the reliability requirement increasing due to the capacity transfers needed for periods when those units are not available.
Even when resources that increase a region’s reliability requirement do not end up offering into the auction, they continue to result in an elevated requirement for imports and so an artificially high clearing price, PJM argues.
“This results in a fundamental mismatch between the actual load requirements and the resource supply stack, which ultimately yields an artificially inflated clearing price that is unjust and unreasonable. More particularly, based on preliminary auction data, PJM estimates that the clearing price for the DPL-S LDA would be more than four times what it otherwise should be if the locational deliverability area reliability requirement is updated to accurately reflect only those resources that actually participated in the BRA,” the RTO’s filings say.
Oregon’s Department of Energy has opened a second round of grants for community renewable and energy resilience projects focused on the state’s rural and disadvantaged communities.
The department said Tuesday it will once again solicit proposals for $12 million in grants of up to $100,000 for planning projects and $1 million for construction projects.
“The Oregon Department of Energy received dozens of applications for outstanding projects across the state in our grant program’s first round of funding,” Director Janine Benner said in a press release. “We’re thrilled to be able to award grants to more projects that will support clean energy and community energy resilience, bolster local jobs and economic development, and create energy cost savings for Oregonians.”
Established by Oregon lawmakers in 2021 to fund projects outside Portland, the Community Renewable Energy Grant Program has a total budget of $50 million to be spent through 2024.
Under the program, grants for planning projects can cover up to 100% of expenses. Construction grants for renewables can cover up to 50% of eligible costs, while those for resilience projects can cover 100%.
“Awards will be made on a competitive basis, and priority will be given to projects that support energy resilience and that serve qualifying communities, including communities of color, low-income communities, tribes, rural areas and other traditionally underserved groups,” ODOE said in Tuesday’s release.
The department in October announced grants totaling $12 million awarded to 21 recipients under the program, after receiving 68 applications representing about $27 million in projects. Among the grant recipients were tribes, local governments, school districts, colleges and a rural electric cooperative. Awardees included:
the Confederated Tribes of Coos, Lower Umpqua and Siuslaw Indians, which received $1 million to help construct two microgrid systems that pair renewable solar and battery storage to provide energy and resilience benefits to tribal buildings.
Wallowa County, which was granted $100,000 to develop a plan for “resilience hubs” in the cities of Joseph, Wallowa and Enterprise in Eastern Oregon. Each hub will pair renewable generation with battery storage and electric vehicle charging.
Jackson County School District, which received about $978,000 to construct a 107.8-kW solar facility with battery storage at an elementary school designated as a critical facility for emergency operations in the event of a natural disaster or other emergency.
High Desert Biomass Cooperative, which will partner with the U.S. Forest Service to use $627,585 for an energy resilience project to expand the capacity and customer base of the cooperative-owned biomass-powered district heating system.
Southern Oregon University, granted $1 million for a resilience project placing net-metered rooftop solar on two campus buildings with battery storage in one building to supply a critical load circuit.
Applications for the latest round of funding are due by Feb. 15 and will be checked for completeness before being advanced to “competitively scored” review, according to ODOE.
The ERCOT grid, tweaked since the disaster of 2021, twice proved its mettle during 2022, meeting record demand during the summer’s sizzling early months and then again during the pre-Christmas winter storm.
That gave Texans a chance to chortle when another state institution, Southwest Airlines, ran into difficulties over the holiday. It also gave Texas Gov. Greg Abbott an opportunity to pause his daily tweets about the southern border and praise ERCOT for not failing during two “extremely cold nights.”
“No Texan has lost any power because of the ERCOT grid,” Abbott tweeted.
Gov. Greg Abbott tweets during the winter storm. | Greg Abbott via Twitter
While there were localized outages at the distribution level, the grid held firm and set a new winter demand peak of 73.96 GW on Dec. 23 that was a 27.7% increase from the previous mark. Demand officially peaked at 69.8 GW during the February 2021 winter storm, but Texas A&M University’s Texas Center for Climate Studies has said demand would have reached 82 GW had not more than 50 GW of generation been unavailable.
ERCOT experienced many of the same issues that plagued it during the deadly 2021 storm, as chronicled by Stoic Energy principle Doug Lewin. The grid operator’s staff underestimated demand during the storm by 4 to 6 GW. Thermal plants again had problems staying on, with almost half the coal fleet offline Dec. 23 and gas plants again facing “fuel limitations” despite the lack of snow and ice.
At times, as much as 12 GW of generation was offline. ERCOT asked for, and received, the Department of Energy’s permission to ignore air quality and other permit limitations and run the grid’s power plants at their maximum output levels in the event of emergency conditions.
Fortunately for ERCOT, the storm, delivering single-digit temperatures but dry conditions, hit right before a holiday weekend, when demand tends to drop. Clear skies and wind gusts in the 40-mph range generated half of energy production at times.
Attention now turns to the Texas State Legislature, which opens its 88th session on Jan. 10 and where lawmakers are waiting to pass judgment on the Public Utility Commission’s proposed market redesign.
Following months of public work sessions, closed-door discussions and a consultant firm’s analysis of six different options, PUC staff urged the commission to adopt a performance credit mechanism (PCM). In public hearings, legislators joined some ERCOT stakeholders in criticizing the concept for being overly complicated, lacking a reliability standard and doing little to attract new baseload generation to Texas. (See Stakeholders Respond to ERCOT Market’s Proposed Redesign.)
The PCM would require load-serving entities to buy performance-based credits from generation resources in a voluntary forward market. The credits are awarded to resources through a retrospective settlement process based on availability during the 30 hours of highest risk, according to their load-ratio shares during those same periods. (See Proposed ERCOT Market Redesigns ‘Capacity-ish’ to Some.)
While generators largely support the PCM and its emphasis on dispatchability, the renewable sector and consumer groups argue it would harm further development of low-cost wind and solar energy.
ClearView Energy Partners, a D.C.-based independent research firm, said in a report that while the PCM is designed to be “resource agnostic,” it would “seem to financially benefit dispatchable conventional resources.” ClearView did allow that some renewables coupled with energy storage could also earn some performance credits.
New ERCOT CEO Pablo Vegas staked out staff’s support of the PCM during the December meeting of the grid operator’s Board of Directors. He said the concept will be critical to “incentivize and retain dispatchable generation” and to meet increased reliability goals.
“Based on our analysis, the performance credit mechanism option strikes a good middle ground that maintains the best parts of the energy-only market while providing new incentives to improve reliability and put steel in the ground,” Vegas said, noting several generators have told lawmakers that the PCM is one of the better options and will result in expected new generation investment.
The Texas Competitive Power Advocates (TCPA), a trade association representing generators, wholesale marketers and retail providers, has said it is prepared to add more than 4.5 GW of additional thermal generation to ERCOT if the PCM is adopted under the “right framework.”
The need to meet growing demand is obvious. ERCOT set an all-time demand peak of 80.04 GW in July, one of the summer’s more than three dozen demand records. Seven years ago, the grid almost peaked at 70 GW. Given ERCOT’s measure that 1 MW can power about 200 Texas homes during peak demand periods, that would mean about 2.1 million homes have been added to the grid during that time.
Vegas and PUC Chair Peter Lake have taken to using Corpus Christi — the eighth largest city in the state at 317,863 residents, according to the 2020 census — as an example of the state’s exploding growth. They say Texas is adding that many people every year, placing additional pressure on developing dispatchable generation resources.
“One of our clear goals this legislative session is to help members understand the resource adequacy challenges that Texas faces in the future,” Vegas said. “The dispatchable gap that is growing between ever increasing load and dispatchable generation is a real issue and is vital. Addressing this issue with clarity will give investors the certainty that they need to build dispatchable generation of Texas needs.”
“Ultimately, we think legislators and/or regulators could approve a new reliability mechanism next year that benefits gas-fired plants, potentially at the expense of renewable resources,” ClearView said. “This could slow deployment of solar and wind in the largest U.S. renewables market.”
Dispatchable generation such as this gas-fired facility are seen as key by some to ERCOT’s market redesign. | WattBridge
The PUC has scheduled a work session for Jan. 12 to discuss the design proposals and stakeholder feedback. A vote is not expected on the proposals during that meeting, but a plan is expected to be adopted later in the month and then passed on to the legislature. The commission also has open meetings scheduled for Jan. 19 and 26.
ERCOT has already made several changes as a result of laws passed during the 2021 session. Generation and transmission facilities have been required to weatherize, and the grid operator’s staff have been conducting compliance inspections, something that didn’t happen after rolling blackouts during a 2011 freeze.
Generators have been required to keep additional fuel sources on site in case of emergencies, and several ancillary services have been added to the energy-only market. At the same time, ERCOT’s price cap was nearly halved, from $9,000/MWh to $5,000/MWh.
During a summer of tight margins and several conservation calls, ERCOT’s conservative operations posture relied on reserves and reliability unit commitments to keep thousands of megawatts in reserve. The grid operator’s market monitor has said that has added hundreds of millions in costs as electricity costs rose more than 70% year-over-year in June.
In December, ERCOT announced a new voluntary curtailment program for crypto miners and other large flexible loads, effective with the new year. It later expanded the program’s scope, designed to reduce power use scare periods, to include loads qualified to provide ancillary services or emergency response service but that don’t have an active obligation to provide those services. (See ERCOT Opens Curtailment Program to Crypto Load.)
FERC and NERC will conduct yet another inquiry into cold weather grid failures after Duke Energy (NYSE:DUK) and the Tennessee Valley Authority cut power to consumers because of insufficient generation during December’s winter storm.
FERC announced Dec. 28 it would conduct the joint investigation with NERC and its regional entities after millions of customers were left without power following the storm’s snow, frigid temperatures and high winds.
Duke Energy’s outage map for North and South Carolina, shared by spokesperson Jeff Brooks on Twitter at 8:24 a.m. Dec. 24. | Duke Energy
“Although most of these outages were due to weather impacts on electric distribution facilities operated by local utilities, utilities in parts of the Southeast were forced to engage in rolling blackouts and the bulk power system in other regions was significantly stressed,” the agencies said.
FERC Chair Richard Glick said the behavior of the bulk power system during the storm shows that the BPS “is critical to public safety and health.”
NERC CEO Jim Robb noted that December’s storm was the fifth major winter event in the last 11 years.
“In addition to the load shedding in Tennessee and the Carolinas, multiple energy emergencies were declared and new demand records were set across the continent. And this was in the early weeks of a projected ‘mild’ winter,” Robb said. “This storm underscores the increasing frequency of significant extreme weather events … and underscores the need for the electric sector to change its planning scenarios and preparations for extreme events.”
Outside of the Southeast, the winter storm prompted conservation calls and emergency alerts in the Eastern Interconnection, while ERCOT and SPP joined TVA in setting new demand records. In PJM, where load hit 135.3 GW on the evening of Dec. 23, calls for conservation limited the peak to less than 129 GW on Dec. 24.
Some 500,000 customers who lost power during the storm across New York had their service restored as of Dec. 28, the New York Public Service Commission reported. The Buffalo area was pummeled by more than four feet of snow and winds as high as 70 miles per hour; more than three dozen deaths were attributed to the storm. Gov. Kathy Hochul called it the “most devastating storm in Buffalo’s long storied history.”
Southeast Struggles
Twitter users complained about being asked to conserve energy while corporate offices — including those of Duke Energy in Charlotte — remained fully lit. | Michael Konen via Twitter
Duke said in a release that it “was forced to interrupt service” to around half a million customers in North and South Carolina the evening of Friday, Dec. 23, and Christmas Eve morning, because of both increased demand from the below-freezing temperatures and “a shortage of available power in the Southeast.” Separately, a high-wind event Dec. 24 left about 40,000 customers without power.
Duke spokesperson Jeff Brooks told WRAL News in Raleigh that generator failures also played a part, along with challenges “in our ability to secure additional power from outside of our service area” because the extreme cold affected neighboring utilities as well.
While the utility reported it was back to normal operations in both states by Dec. 26, its customers — which Duke had thanked for helping reduce demand through voluntary conservation efforts — were less than pleased. Several Twitter users noted that major buildings in downtown Charlotte — including Duke’s own headquarters — appeared fully lit despite pleas for conservation. Others complained they had gotten no notice before Duke cut their power, even those relying on electricity for medical devices.
North Carolina Governor Roy Cooper tweeted that he was “grateful for those who conserved energy” but also “deeply concerned” about the alleged lack of notice for rolling blackouts. He said he had “asked Duke for a complete report on what went wrong and for changes to be made.” The utility is also scheduled to brief the North Carolina Utilities Commission on the outages at a meeting on Tuesday.
TVA Takes ‘Full Responsibility’ for Outages
Meanwhile, TVA said in a statement on Wednesday that it would “take full responsibility for the impact we had on our customers” and promised a “thorough review” of the holiday outages.
The utility acknowledged that it had ordered local power companies to reduce consumption by 5% on Dec. 23 and again on Dec. 24 by up to 10%. The Dec. 23 curtailment lasted two hours and 15 minutes, while the Christmas Eve cuts lasted more than five hours. TVA said that during the 24-hour period that began on Dec. 23, it “supplied more power than at any other time in its nearly 90-year history,” providing 740 GWh. The utility set its highest winter peak power demand, at 33.4 GW, at 7 p.m. the same day.
Electricity generation by energy source for Tennessee from Dec. 20-28, showing a significant drop in coal generation in the early morning of Dec. 23, along with smaller drops in gas and hydro resources. | EIA
Dec. 23 also marked “the first time in TVA’s 90-year history that we’ve had to direct targeted load curtailments due to extreme power demand.” While TVA did not mention generation outages in its statements, data from the Energy Information Administration showed that output from coal plants in Tennessee dropped significantly during the same period, from 4.5 GW the morning of Dec. 23 to a low of 1.4 GW Christmas afternoon.
As with the Duke outages, considerable criticism ensued in TVA’s service territory over the lack of warning. Nashville Mayor John Cooper said on Twitter that Nashville Electric Service “received only an eight-minute warning from TVA” on Dec. 23 about the coming blackouts. Fifty Nashville residents were without service at one point, according to local media, along with 226,000 in Memphis, where Mayor Jim Strickland said the utility was “not as reliable as they said they were.”
DOE Grants ERCOT’s Emergency Request
Battling some of the same problems that almost brought down its grid during February 2021 — thermal outages and derates, forecasts that underestimated load, gas supply issues — ERCOT went so far as to ask for help from the federal government as temperatures dipped into single digits in Texas’ northern regions.
New ERCOT CEO Pablo Vegas sent a letter to U.S Energy Secretary Jennifer Granholm on Dec. 23 requesting permission to ignore air quality or other permit limitations and run the grid’s power plants at their maximum output levels during Energy Emergency Alerts level 2 (load management procedures in effect) or EEA3 (firm load interruption is imminent or in progress) conditions. Vegas cited “natural gas delivery limitations” in saying the grid operator might not be able to avoid curtailing firm load.
He said about 11 GW of thermal generation were offline or derated, compared to 4 GW of wind and 1.7 GW of solar resources. Vegas said ERCOT “understands the importance of the environmental permit limits.”
“However, in ERCOT’s judgment, the loss of power to homes and local businesses in the areas that may be affected by curtailments presents a far greater risk to public health and safety than the temporary exceedances of those permit limits that would be allowed under the requested order,” Vegas wrote.
The Department of Energy agreed an emergency existed and quickly granted the grid operator’s request that same day (202-22-3).
“The DOE order was a tool to have at our ready should we need it, which we did not,” ERCOT spokesperson Trudi Webster said in an emailed statement. “ERCOT had sufficient generation to meet demand … and had additional tools left to deploy should additional generation been needed.”
Staff used all available import capacity on the DC ties, deployed additional capacity enrolled in emergency response service, suspended charging by energy storage resources, and directed load resources providing responsive reserve service to curtail demand. Online reserves exceeded 11 GW at times.
ERCOT’s average hourly demand peaked at 73.96 GW during the morning of Dec. 23, smashing a six-year-old December record of 57.9 GW.
The grid operator’s final seasonal resource adequacy assessment had projected demand to peak this winter at 67.4 GW, although models upped that to nearly 71 GW as the storm approached. (See ERCOT Says ‘Sufficient’ Capacity to Meet Winter Demand.)
Austin-based Stoic Energy consultant Doug Lewin said poorly insulated homes led to the “crazy high” demand. He pointed out that FERC and NERC identified energy-efficient homes as one of the fixes after the ERCOT grid came within minutes of collapsing during the 2021 February winter storm. “Lots more work to do,” he said.
Demand officially peaked at 69.8 GW during the 2021 storm, but Texas A&M University’s Texas Center for Climate Studies has said demand would have reached 82 GW had not more than 50 GW of generation been unavailable.
At one point on Dec. 23, more than 77,000 Texas customers were without power, according to PowerOutage.us. The cold front’s wind gusts reached 40 miles per hour at times and accounted for most of the localized outages. They also resulted in wind production that provided nearly half of ERCOT’s fuel mix.
Average prices that were still settling below -$1.00/MWh as late as 5 p.m. Dec. 22 went as high as $4,084.62/MWh during the interval ending at 7 a.m. Dec. 23. By 9:15 that night, prices dropped back into the triple-digit range, with a high of nearly $140/MWh on Dec. 24.
SPP Calls EEAs, Sets Demand Mark
SPP set a new mark for winter demand when load peaked at 47.1 GW on Dec. 22, smashing the previous record of 43.7 GW set during the February 2021 storm.
Forecast wind chills for the morning of Dec. 23. | National Weather Service
The persistent cold led to tightening reliability conditions in SPP’s 14-state Midwestern footprint and forced it to declare two EEA1s (all available generation resources in use) on Dec. 23 that lasted for more than four hours.
The grid operator called the first EEA1 at 8:27 a.m. CT and ended it at 10:00 a.m. SPP issued the second EEA1 at 5:20 p.m. as load exceeded staff’s forecast and generation dropped off heading into the evening peak. The RTO called off the alert at 8:20 p.m.
SPP also extended a previously issued conservative operations advisory for its Eastern Interconnection balancing authority footprint from 12 a.m. CT Dec. 25 to noon Dec. 25.
ISO-NE Handles Christmas Eve Capacity Deficiency
An unexpected generator outage and a reduction in imports from other regions led to a somewhat tense Christmas Eve for ISO-NE.
ISO-NE headquarters in Holyoke, Mass. | ISO-NE
The New England grid operator was forced into a series of actions to respond to the Dec. 24 capacity deficiency, going into its Operating Procedure 4 for the first time since Labor Day 2018.
The problems weren’t closely connected to the worst-case scenario that ISO-NE has laid out in recent years, where an extended cold snap challenges energy supply. The weather wasn’t especially cold on the Saturday, and demand was only very slightly above its predicted level at the peak hour.
Instead, it was unplanned outages and reductions at multiple generators, including an unidentified “large generating station” that pushed the grid operator into action. ISO-NE spokesperson Matt Kakley said the grid operator won’t release information on which specific units were knocked out or reduced.
In total for the day, New England unexpectedly lost 2,150 MW of generation and neighboring regions under-delivered energy by about 100 MW compared to the grid operator’s morning plans — and 1,100 MW less than what had cleared in the day-ahead market.
According to ISO-NE’s report on the deficiency, it first declared an abnormal conditions alert at 4 p.m. Dec. 24., with escalating actions coming subsequently until peak load had passed and the conditions eased by 6:30.
While the system was briefly strained, ISO-NE said, “only a small amount of day ahead cleared export transactions were curtailed and no emergency purchases were scheduled.”
Along with the warnings of an imminent energy shortage, the skyrocketing real-time wholesale prices (to over $2,000/MWh) at the peak hour raised eyebrows in New England, with one commenter noting that in the ISO-NE app, the whole region was colored a bright Christmas red.
MISO South Dodges Emergency
MISO managed to avoid an emergency in its South region despite issuing a maximum generation warning during the fierce cold blast Dec. 23.
MISO issued a maximum generation warning around 9 a.m. ET for the South as the storm intensified into a bomb cyclone and lifted the warning before 1 p.m. MISO said its South region was facing higher than forecasted load and significant generation outages.
MISO systemwide load and fuel mix on Dec. 23 | MISO
MISO South remained in conservative operations mode and under a cold weather alert until Dec. 26. The storm also forced MISO Midwest into conservative operations overnight into Dec. 24. MISO’s conservative operations instructions request members defer or cancel generation or transmission maintenance and return facilities to service as soon as possible.
The grid operator issued a cold weather alert for its South region ahead of the frigid weather on Dec. 20. On Dec. 22, central Mississippi and Arkansas recorded low temperatures around 10 degrees Fahrenheit.
Entergy Texas said its crews restored damage from “strong winds and gusts that swept across Southeast Texas” on Dec. 22.
