The first offshore wind lease auction in the Gulf of Mexico drew minimal interest and extremely low bids.
Soon after it opened Tuesday morning, the U.S. Bureau of Ocean Energy Management announced it was over.
Two $5.1 million bids were submitted in the first round for one of the three lease areas up for grabs. RWE Offshore US Gulf submitted the sole bid in the second round: $5.6 million for rights to the 102,480-acre OCS-G 37334, south of Lake Charles, La.
Two 100,000-acre lease areas off Galveston, Texas, drew zero bids.
The wind energy lease areas offered in Tuesday’s auction are shown. | BOEM
BOEM had prequalified 15 companies to participate in Tuesday’s auction, some of them already major players in the burgeoning U.S. offshore wind market.
The Biden administration put a positive spin on the situation later Tuesday.
Interior Secretary Deb Haaland did not mention the auction in a news release, focusing instead on the larger picture — President Biden’s push for clean energy and a clean energy economy.
BOEM Director Elizabeth Klein focused on the positive, saying: “Today’s lease sale represents an important milestone for the Gulf of Mexico region — and for our nation — to transition to a clean energy future. The Lake Charles Lease Area will have the potential to generate enough electricity to power about 435,400 homes and create hundreds of jobs.”
Challenges
The nation is very late to offshore wind development — U.S. waters host just 42 MW of the more than 60 GW of installed capacity operating worldwide.
But the Biden administration and some states are rushing to catch up, and hope to bring dozens more gigawatts online in the next several years as a climate protection measure.
In the past year, this effort has run into major complications with inflation, interest rates and supply chain constraints. Projects contracted but not yet underway off the Northeast coast say they need more money to proceed; bids for the next round of projects apparently are coming in quite high.
The Gulf of Mexico has another set of problems, BOEM noted in a 2020 report: weaker winds and a softer seabed than exist on other parts of the Outer Continental Shelf, plus the annual threat of hurricanes.
Despite all this, some had expected big things from Tuesday’s auction.
Others were not surprised by the results.
Washington, D.C., research firm Clearview Energy Partners said in a note to clients Tuesday that the macroeconomic trends hammering the offshore wind industry probably diminished interest among developers.
It also cited factors specific to the Gulf of Mexico:
State solicitations have been a strong driver of offshore development in other parts of the country; there have been none in the Gulf states.
Production of clean hydrogen with wind energy may be a key motivating factor for its development in the Gulf, but the IRS still has not issued guidance on the clean hydrogen tax credit in the Inflation Reduction Act.
Electricity in the region is relatively cheap, and the return on offshore wind investment potentially is negative.
That said, there is movement on other fronts. Louisiana is pursuing wind power development in state waters and is in negotiation with multiple developers.
Construction close to shore eliminates some time-consuming federal oversight. And the waters off Louisiana’s coast already are dotted with oil rigs, so wind power development there may not see the fierce opposition that has erupted in places such as beachfront New Jersey resort communities.
Clearview said the two areas off Texas could yet attract interest.
“We note that project developers could file applications for noncompetitive leases in the two areas in the future. In this context, we wouldn’t rule out the prospect that some developers decided it’s ‘not now’ rather than ‘not ever.’”
Trade group Business Network for Offshore Wind had a similar take on Tuesday’s auction.
“Today’s auction results show the important role state public policy plays in offshore wind market development,” CEO Liz Burdock said via email.
“The network remains fully committed to offshore wind in the Gulf and to supporting our members forming the robust supply chain that is already instrumental to building out a new American energy industry. Gulf expertise in offshore construction is unparalleled, and their innovative solutions will continue to drive the U.S. and global offshore wind industry forward. We congratulate RWE and the state of Louisiana, which is positioning itself as a regional leader and building upon [its] strength as a major national supplier, and we look forward to helping solidify the state’s market.”
BNOW last week published a report exploring in greater depth the opportunities and challenges for wind energy development in the Gulf of Mexico.
History
Tuesday’s auction was lackluster compared with BOEM’s three most recent efforts.
RWE got the rights to its patch of water for $54.64 an acre.
Leases auctioned last year topped out at more than $10,000 an acre. Some winning bids were considerably less than $10,000, but all were much, much more than $54.
In February 2022, developers submitted $4.37 billion in winning bids for six lease areas totaling 488,000 acres off the New York-New Jersey coast — the most lucrative energy auction ever in federal waters, for oil, gas or wind.
The May 2022 wind auction off the Carolinas was a more restrained affair — two bids totaling $315 million for two leases totaling 110,000 acres.
In December 2022, the first Pacific wind energy auction drew $757 million in bids for five lease areas totaling 373,268 acres off California.
Pennsylvania regulators last week unanimously approved a policy statement that offers proposed guidelines for when electric distribution companies (EDCs) can use storage as distribution system resources.
In a joint statement during the Aug. 24 commission meeting, Pennsylvania Public Utility Commission (PUC) Chair Gladys Brown Dutrieuille and Vice Chair Stephen DeFrank said technological advancements have allowed batteries to become viable energy resources and nonwire alternatives when planning the grid.
“Electricity distribution systems are changing quickly. Distribution energy resources are interconnecting at an almost exponential pace. Electric vehicle adoption continues accelerating. Data centers are establishing themselves in various EDC territories, demanding remarkable amounts of power,” the statement reads. “These factors, among others, have significantly altered the dynamics of managing the distribution grid. It is apparent that energy storage may offer EDCs a tool to better manage these new dynamics. Energy storage can provide grid stability through services such as peak demand shifting, supplemental power, restoration and voltage support.”
The policy statement said the majority of the comments the PUC has received urged against a narrow definition of when storage could be used at the distribution level, in large part owing to the still-evolving technology. The commission encouraged EDCs to implement storage when it can be cost-effectively used to “maintain or to increase the reliability or the resilience of the electric distribution system.”
The commission also declined to adopt a specific cost-effectiveness test and instead take a more individualized look at projects, saying EDCs may consider storage in cases when expense is similar to other traditional upgrades. Potential benefits include peak demand shifting, supplemental power, restoration and voltage support, Dutrieuille and DeFrank said.
The policy statement follows two rounds of comments regarding the role storage can play on the distribution grid starting in December 2020, with over 30 commenters participating.
Utilities argued that storage could be used to provide capacity in regions far from transmission or that experience concentrated peaks in load, voltage support for distributed energy resources (DERs), reducing or delaying the need for transmission upgrades and to support derated facilities in a constrained area. Storage could also be used to provide reactive control and to mitigate short-term peaks on individual lines from electric vehicle charging or electrification.
Trade groups representing generators, including the Solar Energy Industries Association (SEIA) and PJM Power Providers, as well as the Industrial Energy Consumers of Pennsylvania, argued that states with structured markets like Pennsylvania should impose parameters on the use of storage on the distribution grid when the asset would be owned by a public utility. They argued that the storage would effectively compete with the energy, capacity and ancillary services sold into competitive markets.
Duquesne Light commented that cost and value should be differentiated, arguing that some cost-benefit tests may not capture the value of improved resiliency, clean energy delivery, reduced outages and less need for new infrastructure on private property. It said value should instead be compared to the cost and value of alternative solutions.
SEIA said EDCs should be required to compare the value of their proposals with those of private developers to determine if contracting with third parties could provide more cost-effective solutions, including existing portfolios of behind-the-meter storage. Consumer groups said storage should only be installed when benefits outweigh costs and that most issues would be best addressed by traditional distribution upgrades.
Stakeholders have 30 days to comment on the PUC’s proposed guidelines.
PUC Approves 3 Transmission Projects
The commission also approved three transmission proposals from Mid-Atlantic Interstate Transmission (MAIT) to improve reliability in two regions and to interconnect a new 53.6-MW solar generator.
The company sought to construct a five-breaker ring bus at the Cly Substation in York County and construct 0.3 miles of new 115-kV line to loop the existing Middletown Junction-Roundtop 115-kV and the Middletown Junction-Smith Street 115-kV lines into the bus. It said the $942,000 project would increase reliability and reduce the potential for load loss.
Under the existing conditions, MAIT said, a single bus going offline could cut power to the distribution transformer and the 4,814 customers it serves. The project would prevent a single stuck breaker from disrupting more than two components in the new ring bus.
The company was approved to spend $665,000 to construct a 0.01 mile 115-kV bypass line on the Mansfield-Niles Valley line in Tioga County. The project would serve as an alternate feed to prevent a stuck breaker or maintenance from causing an outage for the 289 Penelec customers and around 6,381 Wellsboro Electric customers the line serves.
The commission also approved a 0.09 mile loop connecting the Hunterstown-Lincoln line to MAIT’s proposed Riley Substation in Adams County, which would serve the 53.6-MW solar generator being planned by Adams Solar.
NYISO last week raised a caution flag on a solar developer’s request for FERC to waive certain interconnection queue procedures, which the ISO said could have marketwide implications (ER23-2559).
Oxbow Hill Solar — a 140-MW utility-scale solar project to be built in Madison County, in rural Central New York, by Cypress Creek Renewables — completed NYISO’s interconnection studies for large facilities and joined Class Year 2021 after accepting its cost allocation. It was expected to be operational by the end of 2026, but because of “circumstances beyond its control,” the developer failed to meet a subsequent regulatory milestone to finalize its siting and interconnection agreements, so it requested an extension to Aug. 11, 2024.
In comments filed with the commission Thursday, NYISO did not take a position on the request, but, citing Order 2023 and FERC’s prior emphasis to adhere to deadlines, the ISO highlighted the importance of milestones in the interconnection process and expressed concern that granting the waiver without limits could negatively impact other projects in the queue.
Both FERC and NYISO have sought to unclog its interconnection queue, with Order 2023 setting penalties on projects that fail to progress through the queue and the ISO streamlining portions of its study processes. (See “FERC Order 2023,” NYISO Previews New York City PPTN.)
The ISO acknowledged that granting Oxbow’s one-time request might not pose an immediate threat but argued that prolonged delays could increase the potential for adverse impacts. It did support Oxbow’s request for FERC to act by Oct. 30, and it said if the commission approves the waiver, its requested deadline was acceptable.
Oxbow said it was on track to submit its siting and interconnection permits on time, but a directive from the New York State Energy Research and Development Authority, which tightened energy deliverability requirements for obtaining renewable energy credits, halted its progress.
A solution to NYSERDA’s concerns was identified, but Oxbow worried the delays would force it “all the way back to the first step of the NYISO’s extensive interconnection process,” where it would be placed into a new class year and be operational significantly later.
Oxbow said the waiver will not harm other market participants, is limited in scope to mitigate potential negative impacts and will remedy a “concrete issue” while helping New York achieve its climate and energy goals.
Many Benton County, Wash., residents believe they do not have a voice in the fate of a controversial renewable energy project proposed for a large site south of the city of Kennewick.
They say that’s because the recommendation on whether to proceed with the Horse Heaven Hills Clean Energy Center rests with a board of state government appointees who are aligned with Democratic Gov. Jay Inslee’s climate change agenda, which includes pushing for alternative power sources.
That belief was evident Wednesday at a public hearing for the project before the Washington Energy Facility Site Evaluation Council (EFSEC), a board of representatives from several state agencies.
“The outcome is predetermined,” said Dave Sharp of Tri-Cities C.A.R.E.S. (Community Action for Responsible Environmental Stewardship). Kennewick is one of the three interconnected Tri-Cities that also include Pasco and Richland.
“Odds of being denied are slim,” said Pam Manelli of Tri-Cities C.A.R.E.S.
Barbara Buckmaster, a farmer at the foot of the Horse Heaven Hills, said, “People are mad and they are angry. They do not want their skyline to look like an industrial site. … Let the community decide what is best for us.”
“Final approval should rest with Benton County,” said local resident Samuel Dechter.
Developers of solar and wind farms and other alternative energy sources in Washington can pick one of two paths to obtain government approval. One path is getting approval from the host county, while the other is to earn a good recommendation from EFSEC, which then goes to Inslee, who makes the final decision. Individual developers have been selecting paths based on which presents the best chances for approval of a project.
Inslee has been crusading against global warming for at least a couple decades, even basing his short presidential candidacy on combating climate change. In 2016, the state’s Ecology Department developed regulations calling for the state to rely on 100% carbon-free power by 2045. A major plank of achieving that goal is solar and wind power. In 2019, the Legislature passed legislation ingraining that goal into law.
Heavy Opposition
The carbon-free power target has sparked a surge of solar farm proposals in Washington.
With the Horse Heaven Hills project, Colorado-based Scout Clean Energy has proposed building up to 224 wind turbines — about 500 feet tall — on 112 square miles of mostly private land. About 294 acres of that land also would hold solar panels, and the project will also include battery storage. The project has a combined nameplate capacity of 1,150 MW, roughly the same as the Columbia Generating Station (CGS), a commercial nuclear reactor just north of the Tri-Cities.
If built, the wind project would be the second in Benton County. Richland-based Energy Northwest, which owns and operates CGS, operates 63 wind turbines several miles to the southeast of the northern face of the Horse Heaven Hills. Completed in 2007, that site covers about eight square miles and produces about 96 MW.
Energy Northwest’s turbines are not controversial, but they cannot be seen from the Tri-Cities. Scout’s turbines would be visible, a major factor in Benton County residents opposing the project. The location is also a nesting area for ferruginous hawks. Last year, the Washington Fish and Wildlife Commission downgraded the status of ferruginous hawks from threatened to endangered. (See Climate, Turbines Help Land Hawk on Wash. Endangered List.)
Up to 69 of the proposed turbines would be too close to the nesting areas, which need a two-mile buffer zone from the structures, Trina Bayard, director of bird conservation at Audubon Washington, said at Wednesday’s hearing.
“It’s too close to our homes. It’s too close to ferruginous hawks,” Manelli said.
Overall, 18 people spoke against the project on Wednesday and three supported it as a job creator. Supporters cited the economic benefits from building and operating the turbines.
“It’ll provide family-wage jobs,” said Rylan Grimes of the local chapter of International Brotherhood of Electrical Workers.
Editor’s Note: An earlier version of this story said 118 people spoke against the Horse Heaven Hills project.
Stakeholders Defer Vote on Generation Deactivation Issue Charge
VALLEY FORGE, Pa. — PJM’s Markets and Reliability Committee voted to defer a decision on an issue charge that would create a new senior task force to investigate changes to the generation deactivation process.
PJM and the RTO’s Independent Market Monitor are jointly sponsoring the problem statement and issue charge. (See “PJM and Monitor Present Generation Deactivation Issue Charge,” PJM MRC/MC Briefs: July 26, 2023.)
The scope includes discussion of the triggers for when PJM can offer a reliability-must-run (RMR) contract to a generator seeking retirement, the compensation for RMR resources and the timing of when a resource owner must notify the RTO of its intent to retire a unit.
Following feedback from the initial first read in July, the issue charge was revised to break out the discussion of resource compensation into its own phase to be considered prior to the other elements.
Presenting the proposal, PJM’s Paul McGlynn said the current compensation structure lacks clarity, as resources that opt not to use the formula rate for determining RMR compensation instead make FERC filings that can offer differing interpretations on cost recovery.
McGlynn envisions an additional RMR contract trigger for a resource that would create a shortfall in black start capability in a region if it were to retire.
PJM is seeking to lengthen the 90-day notice generators are required to provide before a desired deactivation date because the timeline leaves little time for planners to make necessary upgrades to ensure that the grid can remain reliable without the resource. Advanced knowledge of deactivations will be increasingly important given the scale of retirements PJM expects to see over the next decade, McGlynn said.
Stakeholders discussed PJM’s change to the issue charge, stating that expanding use of RMR contracts to maintain resource adequacy would be out of scope for the task force. Cost allocation for RMR contracts under the existing transmission violation trigger and changes to the capacity market also are listed as out of scope.
GT Power Group’s Tom Hyzinski said considering whether RA should be a rationale for offering an RMR contract could offer an additional tool if a large number of generators simultaneously decide to deactivate.
“We don’t want to approve an issue charge that prevents things from being discussed that need to be discussed,” Hyzinski said.
McGlynn said the RTO is already looking into improving the capacity market’s ability to ensure resource adequacy.
PJM Senior Vice President of Market Services Stu Bresler said there are backstop provisions in the tariff that allow additional capacity to be procured outside of the Base Residual Auction (BRA) cycle if the RTO falls below its targets.
Whether the process should preclude interactions with the capacity market was discussed at length both during the July meeting and on Thursday, with several stakeholders concerned the task force and its solutions could be fragmented from market changes being considered in other forums.
Paul Sotkiewicz, president of E-Cubed Policy Associates, said several areas of the issue charge were ambiguous and could lead to procedural arguments distracting from core issues. He and other stakeholders suggested amendments to clarify that language in the issue charge, which were adopted by PJM and the Monitor.
Vistra’s Erik Heinle said the revisions had improved the issue charge from its first read but that he believes the first phase should be RMR compensation and timing.
Monitor Joe Bowring said he would support breaking the issue charge into two separate stakeholder processes, with his focus being primarily on compensation.
Peak Market Activity Credit Changes Endorsed
Stakeholders endorsed tariff revisions to address the amount of credit market participants must maintain to satisfy their peak market activity (PMA) requirement, which is their highest exposure in the past year. (See “First Read on Peak Market Activity Credit Activity Proposal Expected in August,” PJM MRC/MC Briefs: July 26, 2023.)
The changes include redefining the PMA surplus and shortfall parameters, introducing minimum exposure and minimum transfer amounts to the tariff language and increasing the PMA reset from occurring semiannually to weekly. The reset reconciles over- and under-collateralization that occurs as energy prices and demand fluctuate.
The revisions also increase the number of permissible early payments from 10 to 13 to provide more flexibility, and the rolling invoice period was increased from three weeks to four.
PJM’s Yong Hu said staff had backcast numerous solutions and believe the proposal is optimal.
Denise Foster Cronin of the East Kentucky Power Cooperative (EKPC) said the utility had concerns with PJM’s initial proposal but that stakeholders and PJM were able to produce a strong compromise.
Bresler said because the proposal was endorsed by the Risk Management Committee (RMC) on Aug. 22 without objection, it would normally have been a consent agenda item for the MRC; however, staff are aiming to implement the tariff revisions before winter.
PJM Provides First Read on Reserve Certainty Issue Charge
PJM gave a first read of an issue charge and problem statement that seeks to address several areas of the reserve market, largely to address a decline in the response rate since the two tiers of reserves were consolidated in a market overhaul implemented Oct. 1. (See “PJM Seeks Stakeholder Process on Reserve Certainty,” PJM MRC/MC Briefs: July 26, 2023.)
Since presenting the issue charge to the MRC in July, PJM has revised the timeline laying out the order in which it seeks to address each of the work areas and added more education on the topics. The bulk of the immediate needs would be initiated upon approval of the issue charge, with an expected duration of six to nine months, followed by discussion on the longer-term items expected to take 12 to 18 months. Also, several changes were made to the work areas.
The immediate needs are reserve performance and penalties, aligning the offer structure with fuel procurement, deployment, and ensuring that procurement reflects system need. Longer-term needs include the eligibility requirements for reserve resources and incentivizing flexibility to meet system needs.
Bowring said he think the out-of-scope portion of the issue charge — which would allow PJM to prevent discussion of changes that could impact the RTO’s “ability to maintain reliability and compliance with NERC standards” — should be more specific and could be used by PJM to curtail discussion.
Bowring said PJM has previously made such assertions in response to participants, including the IMM, who disagreed with PJM’s approach.
“No one will propose changes that they believe will reduce reliability or compliance with NERC standards. The issue is how best to maintain reliability and compliance. There are multiple paths to those objectives. The ability to discuss options should not be arbitrarily limited,” he said.
The declining reserve response rate led PJM to increase its reserve requirement by 30% in May, overriding stakeholder objections. The Monitor at the time objected that the change was not needed and not supported by the data. PJM’s Donnie Bielak said the issue charge is intended to produce a permanent solution that is more satisfactory for stakeholders. (See “Stakeholders Reject PJM Synch Reserve Manual Change; RTO Overrides,” PJM MRC/MC Briefs: May 31, 2023.)
Duke Energy Progress (DEP) and the North Carolina Eastern Municipal Power Agency (NCEMPA) filed a settlement with FERC on Thursday that would end a dispute over the latter using batteries to shave its peak demand (ER22-682).
Duke serves the power agency under a power purchase agreement in which the utility buys energy, capacity and reserves to meet the municipals’ demand. It charged the agency for capacity based on a 12-coincident-peak method.
NCEMPA members started shaving those peaks using behind-the-meter battery storage systems, which led to a dispute at FERC over their impact on Duke’s ability to recover its costs.
Duke believed that NCEMPA could figure out when its members’ demands were going to hit one of the 12 coincident peaks, thus dispatching batteries to avoid the capacity charges, so it filed changes to its agreement to adjust how the agency was charged for capacity to account for the batteries.
FERC in an order early last year found that Duke had failed to show its proposal was just and reasonable and set the matter for hearing and settlement judge procedures. (See FERC Orders Negotiations in Duke-Muni Contract Dispute.)
The filed settlement would resettle transactions between the two starting on Jan. 1, 2023, expressly saying no refunds would be issued for 2022. NCEMPA would be able to keep its batteries and other “energy injection devices,” but they cannot exceed 1.75% of its total capacity plus 25 MW. Any batteries or storage devices that NCEMPA uses during peak demand periods can be made subject to that cap.
The two also agreed to a new supplemental capacity charge arrangement for certain interruptible loads whose consumption might not be apparent at the monthly system peak used for calculating capacity charges.
FERC trial staff supported the settlement, saying it would solve the issues in the case in a fair and reasonable way that is consistent with the public interest. The settlement would allow NCEMPA and its members to manage their power use through energy-storage devices while addressing DEP’s concerns about their impact on its revenues, they said.
The uncontested settlement would resolve all the issues FERC set for hearing and promote consistency and predictability through 2027 with a new PPA. Duke and NCEMPA asked FERC to approve the settlement without modification or conditions.
EV Charging Pilot
Duke Energy on Monday announced it was launching a pilot program in its North Carolina utilities to offer customers a flat rate for 800 kWh/month of electricity to charge their cars.
The utility is working with Ford, General Motors and BMW to launch its “EV Complete Home Charging Plan.” Customers will pay just $19.99/month in Duke Energy Carolinas and $24.99/month in DEP for 800 kWh, which the utility said is about twice as much as the average consumer would use for their cars.
The pilot will use software in the cars themselves to track monthly demand, avoiding the expense of installing a separate meter.
“The average EV owner is already saving about $1,000 per year on fuel costs compared to a traditional vehicle; a predictable monthly subscription charge on top of that is going to ensure predictable savings when charging,” Kendal Bowman, president of Duke’s utility operations in North Carolina, said in a statement. “Beyond cost savings, EV charging at home tends to be convenient because drivers can leave the house with a fully-charged vehicle and lessen the number of trips to public charging stations.”
In what is becoming an almost daily occurrence, ERCOT on Sunday issued another appeal for voluntary conservation as the Texas grid operator continues to manage tight conditions during a brutally hot summer.
The ISO called for the market’s consumers and businesses to reduce their usage between 4 p.m. and 9 p.m. (CT). As it has since late last week, ERCOT warned of the potential to enter emergency operations because of high demand paired with expected low wind and possibly low solar generation during the evening hours when the sun sets.
The conservation call marked the fourth straight day, and seventh overall, the grid operator has asked for voluntary conservation this summer. Temperatures reached a record 109 degrees Fahrenheit in Houston and broke triple digits throughout much of the rest of Texas.
“What we’re seeing are conditions that are more tight than what we have seen on any other day this summer,” ERCOT CEO Pablo Vegas told the Public Utility Commission during an open meeting Thursday. “At this time, it’s a high likelihood that we expect to be in emergency operations this evening.”
That did not happen. The grid operator deployed its newest ancillary service, ERCOT Contingency Reserve Service (ECRS), and non-spin reserve service to close the gap between supply and demand. Pop-up rain showers in the Houston area also lowered temperatures and with it, demand — but not before an hourly average peak of 84.24 GW, more than 1 GW from a record.
ECRS dispatches resources that can respond within 10 minutes of deployment instructions and can operate for at least two straight hours. It also was deployed Friday and Saturday along with non-spin and responsive reserves; energy storage regularly supplied more than 1.2 GW of energy as well.
“Thank you to Texas residents [and] businesses for your conservation efforts, which along with additional reliability tools, helped us to get through a tight peak time,” ERCOT tweeted Thursday night, a message it has repeated several times since.
Vegas told the commission the ISO has seen a “very different profile” for wind energy, with an afternoon production of about 6 GW that is several GW lower than normal during summer months. He said the thermal dispatchable fleet has been operating at or near normal forced-outage levels.
“It’s really the combination of the very high heat, the very high demand and the low expected output of wind during the solar ramp,” Vegas said.
Temperatures are expected to cool slightly in Texas this week. ERCOT’s six-day forecast predicts demand to stay below 79 GW for the rest of the week.
The grid operator’s record for hourly average demand remains 85.44 GW, set Aug. 10. It has broken last year’s high of 80.15 GW 193 times this summer.
ERCOT staff had projected a summer peak of 82.7 GW in its final pre-summer assessment. That mark has been exceeded 98 times this summer.
Texas regulators and ERCOT stakeholders last week celebrated a year-long study of aggregated distributed energy resources (DERs) that’s resulted in two virtual power plants (VPPs) qualified and able to provide dispatchable power to the state’s grid.
The Aggregate Distributed Energy Resources (ADERs) pilot project tested how consumer-owned, small energy devices, such as energy storage systems, backup generators, controllable electric vehicle chargers and smart thermostats and water heaters, can be aggregated virtually and participate as a resource in the wholesale electricity market (53911).
Eight aggregations (ADERS), totaling 7.2 MW, participated in the pilot project. Two ADERs with customers using Tesla Electric Powerwall storage systems have completed required testing and could provide energy and ancillary services through the third quarter. One is linked to Oncor’s distribution system in North Texas, the other to CenterPoint Energy’s system in Houston.
The other six ADERs are being commissioned.
CenterPoint Executive Vice President Jason Ryan, who chaired the 20-person task force, told the Public Utility Commission during its Thursday open meeting that the pilot project shows Texas is a leader in VPP implementation.
“I’m not talking about just the leader among states in this country, but really in the world. It really changes how customers are using the distribution grid,” he said.
“Every one of those customers, by investing in whole-home backup and then being participatory in the grid, is providing additional reliability services from a private investment and taking off the socialized value of the reliability standard. The growth of this pilot is also an incredibly important data point,” Tesla’s Arushi Sharma Frank said. “You have to be able to see a resource. It needs to be visible in the system, it needs to be visible to ERCOT, it needs to be visible to the distribution service providers operating the local system and it needs to be understood to be a part of wholesale price formation.”
She said the exchange of granular information between the consumers, ERCOT, distribution providers and other market participants has been invaluable.
“All of these things happening in nine months is progress on top of progress on top of progress of the kind that is taking the RTOs years to implement years,” Frank said. “Hopefully in the three years that this pilot progresses, the information that Texas will have collected on three disparate systems — retail energy distribution service, and the wholesale grid — will be incredibly valuable to the National Labs. You’ll be in the opposite position where instead of the National Labs coming to help you, you will be going to the National Labs and helping them figure out how to monetize DERs and put them into wholesale price formation.”
Frank said in a report that the project’s first phase allowed Tesla to “demonstrably assess” ADERs’ viability as providers of energy and reserves. However, Tesla also discovered the costs associated with maintaining a qualified scheduling entity (QSE) and servicing telemetry can be challenging on a small scale. She called for an increase in current QSE caps, noting ADERs’ break-even point of 15-20 MW is above that cap.
In a memo, PUC commissioner Will McAdams directed the task force and ERCOT to create a plan for the pilot’s second year, following the project’s principles.
“We would like to understand what performance metrics would need to be met to unlock expansion of grid services or size caps,” he said.
ERCOT Evaluating RMR Options
ERCOT CEO Pablo Vegas told the commission it may resort to issuing reliability must-run (RMR) contracts to ensure it has enough capacity to meet demand this winter.
The grid operator issued a market notice last week that said while it had determined a gas plant’s announced suspension would not create a reliability issue, it was conducting additional analysis to determine whether there’s a need for additional capacity from dispatchable resources for the upcoming season.
ERCOT pointed to increasing system demand and a continued reliance on variable output from renewable resources as creating the need for more analysis. It promised a decision by early October as to whether the resource would be able to suspend operations or be extended an RMR contract.
“We are looking at more broadly the needed capacity as we get into this winter season,” Vegas told the PUC. “There have been multiple units that have indicated a cease operations and mothballing status or retirement.”
Asked whether staff would evaluate a demand-side solution, Vegas responded affirmatively.
“If we move down this pathway, the requirement would be to evaluate any sort of capacity options, including the load-side,” he said. “Effectively, we would be seeking the most cost-effective solution or to close a risk if we identify one on capacity.”
Travis Kavulla, NRG Energy’s vice president of regulatory affairs and a former Montana state commissioner, tweeted that this would be the first time RMR, normally used for local reliability issues, would be used for system resource adequacy.
“This kind of creates a ‘Hotel California’ situation,” he said, referring to resources’ ability to leave. “Only CAISO has used RMR powers for this purpose.”
ERCOT said its reliability assessment of the Barney Davis 1 unit near Corpus Christi indicated it is not required to support transmission system reliability. The unit, which has a summer maximum sustainable rating of 292 MW, plans to indefinitely suspend operations on Nov. 24.
Any RMR contracts must be approved by the board.
ISO Prioritizes Market Changes
Vegas also shared development timelines for ERCOT work initiatives as a result of recently passed legislation that he called The Big Five: a reliability standard, a dispatchable reliability reserve service (DRRS), the performance credit mechanism (PCM), a multi-step floor to the operating reserve demand curve (ORDC) and real-time co-optimization (RTC).
“Those five initiatives together make up a suite of changes that are going to help to drive reliability and make changes to the market constructs that are designed to improve both operational flexibility as well as long-term resource adequacy,” Vegas said.
ERCOT will work with consultants to update a previous value-of-lost-load study and to perform a review of its cost of new entry metric, currently valued at $105,000/MW-year after a 2012 analysis. Commission staff plan to file a proposed rulemaking on a reliability standard based on the ISO’s study; the PUC will take up the proposal in January.
ERCOT has considered a reliability standard since a 2011 winter event and has long operated with a 13.75% target reserve margin based on a 0.1 loss-of-load expectation and a traditional dispatchable generation fleet. The PUC opened a docket (54584) earlier this year to evaluate and establish an appropriate reliability standard.
The grid operator’s staff has proposed a three-part framework that considers the duration and magnitude of a loss-of-load event besides the occurrence’s frequency. It’s intended to better quantify risks associated with an LOLE when intermittent resources comprise a large percentage of the generation fleet.
The commission already has approved the ORDC’s changes but it still must endorse a document that formalizes the two price floors. Staff will make the software changes in November and must file reports on performance metrics and DRRS’ effects in 2024 and 2025, respectively. (See Texas PUC Approves ERCOT’s ORDC Modifications.)
ERCOT staff and stakeholders will resume their work on RTC and energy storage resources’ state of charge, work delayed by the disastrous 2021 winter storm. The Real-time Co-optimization + Batteries Task Force will meet Sept. 8 with a 2026 deployment target. (See “Staff, Stakeholders Get Serious on RTC, Energy Storage,” ERCOT Technical Advisory Committee Briefs: Aug. 22, 2023.)
ERCOT also is developing a “framing document” outlining PCM decision points for the PUC. Vegas said staff will take the commission’s feedback and prepare a strawman proposal for a series of workshops with stakeholders and PUC work sessions. ERCOT and the market monitor will perform a cost-benefit analysis before the Texas Legislature next meets in 2025, after which protocols will be drafted.
Vegas said he expects it will take another two years to implement the PCM. The market construct would retroactively reward dispatchable generation that meet performance criteria during the tightest grid periods with incentive payments.
Asked whether RTC, a market tool that procures energy and ancillary services every five minutes, will still be needed when the PCM is deployed, Vegas said efficiency, reliability and market transparency are key factors.
“We should always be looking at the combination of tools we have to incentivize the goals of the ERCOT grid,” he said.
The DRRS is a non-spin ancillary service that supports system reliability and mitigates the use of reliability unit commitment. It is open to resources capable of running for at least four hours at their high sustained limit; being online and dispatchable no more than two hours after being called on; and with the dispatchable flexibility to address inter-hour operational challenges.
ERCOT plans to move nodal protocol revision requests through the stakeholder process this fall to codify the DRRS’ sub-type. Upon approval early next year, staff will make system changes and begin offering the service by Dec. 1, 2024.
PUC Rules Against SWEPCO
The commission gave Southwestern Electric Power Co. (SWEPCO) until Sept. 8 to explain why and how the recovery of carrying costs alone is tied to and adequately accounts for the PUC’s determination on the prudence of a recently retired coal plant (53931).
The order is related to SWEPCO’s application to reconcile fuel costs. An administrative law judge in July found the retirement decision to be prudent after the utility reached a partial settlement agreement resolving all other issues.
SWEPCO’s parent company, American Electric Power, announced the 580-MW Pirkey plant’s retirement in 2020. The unit, which sits in SPP’s Texas footprint, stopped operating in March. In May, the Texas commission rejected the utility’s application to build 237 MW of accredited renewable capacity at the Pirkey site. (See Texas PUC Rejects SWEPCO Application for Renewables at Pirkey.)
The PUC plans to take up the matter during its Sept. 28 open meeting.
The commission also denied SWEPCO’s rehearing request of its May denial of renewable resources at Pirkey, saying that their acquisition is not in the public interest (53625).
In other proceedings, the PUC:
Gave El Paso Electric Co. until Sept. 23 to advise the commission what it intends to do with its application for proposed electric vehicle-ready pilot programs and tariffs following a recent law that addresses the operation of public EV charging stations and goes into effect on Sept. 1 (54614).
Overturned an ALJ’s decision approving Wind Energy Transmission Texas’ interim wholesale transmission rates following appeals by Texas Industrial Energy Consumers and Steering Committee of Cities Served by Oncor (55029).
The American Clean Power Association (ACP) askedFERC last week to hold a technical conference on capacity accreditation, arguing that the commission’s rules need to keep pace with technology and the evolving grid.
The petition filed Aug. 22 is not ACP’s first attempt to get FERC to address the issue, with the commission in February rejecting a complaint the organization filed against ISO-NE alleging its capacity accreditation rules failed to account for natural gas’ performance issues in the winter. (See FERC Denies RENEW Northeast Complaint.)
“Grid operators and FERC have been addressing these issues primarily on a regional basis, but the clean energy industry believes it’s time for FERC to look at many of these issues more broadly,” ACP Vice President of Markets and Transmission Carrie Zalewski said in a statement. “Today’s petition provides an opportunity for FERC to hold open discussions that can identify the best possible capacity accreditation methods so that the reliability contributions of all resources — including renewables and storage — can be accurately accounted for.”
A central pillar of system planning and electricity market design, capacity accreditation is one of the most critical areas FERC needs to address on a holistic basis, ACP argued. Some regional differences are to be expected, but ACP said the methods should share common goals and general approaches.
Capacity accreditation methods vary widely, and they are often applied inconsistently within and across resource types, making it more difficult to accurately assess national and regional resource adequacy and to make efficient investment decisions, the organization said. With different regions taking on the issue on their own, and FERC’s ex parte rules, the commission has not been able to take a broader look at the issue, which could help its decisions.
“That constraint will continue to bind policy development going forward, because many regions are actively considering changes to their resource accreditation processes as the resource mix continues to evolve,” ACP said.
A technical conference on capacity accreditation would develop a record to foster informed decision-making on the various initiatives likely to arise over the next several years, it said. And a universal framework would not stop the regions from moving ahead on their own.
The industry has different ways of accrediting capacity, including effective load-carrying capability (ELCC), marginal reliability improvement (MRI) and measuring a resource’s output during certain peak load intervals.
All of the capacity accreditation techniques include four fundamental design characteristics.
The technique can use a deterministic metric (reflective of only one set of conditions) or probabilistic (a value based on analytical simulations across hundreds or thousands of potential conditions).
Grid operators can also use a prospective/forward-looking assessment, a retrospective assessment based on past performance or a combination that uses a prospective method at first, then adjusts retrospectively based on performance.
The third design characteristic is whether to use an average contribution, in which all resources of the same technology count the same, or a marginal contribution, in which individual resources are measured in comparison to others using the same technology.
The fourth design element is whether fuel assurance is required for individual units or handled probabilistically by unit, unit type or systemwide.
“Because capacity accreditation is increasingly being acknowledged as a critical aspect of our energy system, significant attention is now being focused on this topic in various ISO/RTO stakeholder working groups,” the petition said. “However, at present, there is no focused, coordinated discussion occurring at the federal level, either at the commission or at the North American Electric Reliability Corp.”
The industry would benefit greatly from a universal discussion around the issue, with a technical conference educating stakeholders, allowing for open discussion with FERC staff and hopefully helping to foster consensus and consistency among regions, ACP said.
ERCOT stakeholders last week endorsed the charter and leadership for a task force that will report directly to the Technical Advisory Committee and provide recommendations on real-time co-optimization (RTC) and energy storage resources’ (ESRs) state of charge (SOC).
The Real-time Co-optimization + Batteries Task Force (RTC+B) will coordinate and review ERCOT and market activities to mitigate risks and support the RTC+B program’s implementation. Its responsibilities include managing timelines, providing a forum for analysis or policy decisions and reviewing nodal protocol revision requests (NPRRs).
Battery issues unrelated to RTC are out of scope. However, ERCOT will make time available after the group’s meetings should stakeholders want to continue to explore storage.
ERCOT’s Matt Mereness, who has volunteered to chair the task force, said he simply forklifted the charter from the previous stakeholder group that produced NPRRs and other rule changes to guide staff’s implementation of RTC.
“We said, ‘What does it look like to remove implementation risk?’ And so structurally, everything is the same,” he said during TAC’s Aug. 22 meeting.
Mereness also chaired the RTC Task Force that took a first look at the market tool that procures energy and ancillary services every five minutes. Using the approved NPRRs, the new group will develop business requirements for RTC and single-model batteries and review a SOC concept for batteries. (See “RTC Stakeholder Group to Form,” ERCOT Technical Advisory Committee Briefs: July 25, 2023.)
Key policy issues include parameters for ancillary service proxy offers, triggers for initiating off-cycle security-constrained economic dispatch (SCED) executions, allowing real-time updates to current market offers and in the future with RTC, and evaluating a framework for periodic analysis comparing RTC and the ORDC.
A vendor will start developing the SOC for batteries involved in RTC in January. The task force plans to deliver its completed work in 2026.
Faced with a December target to gain ERCOT Board of Directors approval of its work, the RTC+B group will move quickly. It has already scheduled a Sept. 8 meeting to nominate a vice chair and review the RTC task force’s previous work and the sequence of activities necessary for implementation.
“We do think it’s important that we get real-time co-optimization done as quickly as possible, given that it’s planned to save enormous amounts of money for the market when it’s implemented,” Mereness said.
The RTC Task Force was disbanded at the end of 2020 following the initiative’s completion. The disastrous and deadly February 2021 winter storm and the ensuing drain on staff resources postponed the initiative until recently.
SOC Transparency
In a split vote, TAC approved one of two ERCOT revision requests (NPRR1186) designed to improve the grid operator’s awareness, accounting and monitoring of an ESR’s SOC before the RTC+B project goes live.
As approved by the Protocol Revisions Subcommittee (PRS) earlier in August, the measure adds definitions and telemetry requirements related to SOC information that date back to 2018 and introduces a requirement that qualified scheduling entities (QSEs) representing an ESR telemeter the next operating hour’s ancillary service (AS) resource responsibility. It also specifies that QSEs are expected to manage the SOC to ensure that each ESR has sufficient energy to meet its AS responsibilities and that the day-ahead market (DAM) process should begin to respect the AS award limits for ESRs based on duration requirements.
ERCOT has held three workshops on NPRR1186, and it has been the subject of conversation during two PRS meetings. Still, it was discussed for 90 minutes before TAC voted on it.
Storage developers Eolian, Plus Power and Jupiter Power filed comments opposing it, saying it would disincentivize longer-duration ESRs that could diversify energy supply and help manage the growing evening ramp’s variability because “administratively applied withholding requirements” will limit the resources’ ability to provide multihour AS products.
The joint commenters suggested modifying the measure by adding a variable to the calculation of AS, eliminating the ESRs’ obligation to stop discharging energy while deployed to provide certain AS, and ensuring compliance obligations address ERCOT’s SOC monitoring goals and mitigate unintended consequences.
After TAC endorsed the NPRR in a 22-3 vote with five abstentions — with the consumer and retail electric provider segments providing the pushback — Eolian said it would appeal the approval to the ERCOT board when it meets Thursday and request ERCOT be directed to resubmit new NPRRs to separate out system coding issues from the determination of SOC parameters and related compliance obligations.
Eolian said the board should give market participants a chance to work with ERCOT to define “actual reliability issues” and determine how to solve them without creating dangerous unintended consequences.
“Failure to do so will certainly create a chilling effect in the ERCOT market by discouraging the development and construction of longer-duration ESRs in ERCOT, which will be to the detriment of grid resiliency and reliability, as well as all ERCOT consumers,” the developer wrote.
Staff pointed out that AS market products work as mechanisms that maintain reliability, not as standalone economic products, and that ESRs create a duration issue. They agreed to review how other grid operators are addressing duration issues.
“There needs to be some perspective on what’s on the system now versus what was on the system 10 years ago,” said ERCOT’s Kenan Ögelman, vice president of commercial operations.
New ORDC Price Floors Set
The committee endorsed another binding document request (OBDRR048) that sets two price floors for the operating reserve demand curve (ORDC) in a move to retain and incent new dispatchable thermal generation.
Price adders of $20/MWh and $10/MWh will come into play when operating reserves hit floors of 6,500 MW and 7,000 MW, respectively. ERCOT analysis has indicated the floors would have increased revenues to generators by about $500 million during the 2020 and 2022 pricing years. Thermal generators would have received 80% of those revenues.
The Texas Public Utility Commission approved the ORDC revisions, designed as a bridge to the PUC’s proposed performance credit mechanism market structure, this month. (See Texas PUC Approves ERCOT’s ORDC Modifications.)
Stakeholders approved the OBDRR in a 22-7 vote, with one abstention. All six members of the consumer segment voted against the measure over concerns the structure guarantees revenues and prevents customers from responding.
The Texas Industrial Energy Consumers’ John Hubbard said the organization still opposes the change and that it has filed a notice of appeal.
The OBDRR was separated from TAC’s combination ballot, which passed unanimously. The combo ballot included seven NPRRs, three revisions to the Nodal Operating Guide (NOGRRs), two additions to the Resource Registration Glossary (RRGRRs) and a change to the Planning Guide (PGRR). If approved by the board, these changes would:
NPRR1164: require that resource entities identify whether a resource has the potential capability, even if unverified, to be called upon or used during a black start emergency or if it has the capability for isochronous control. It would also require resource entities and transmission service providers to identify if a breaker or switch has a synchroscope or synchronism check relay and would define the terms black start-capable resource, isochronous control capable resource, synchroscope and synchronism check relay.
NPRR1171, NOGRR250: clarify various reliability requirements for distribution generation resources (DGRs) and distribution energy storage resources (DESRs) seeking qualification to provide AS and/or participate in SCED.
NPRR1173: account for Texas standard electronic transaction processing options for municipally owned utility or electric cooperative service areas in the protocols.
NPRR1174: establish a process allowing QSEs or congestion revenue right (CRR) account holders to return overpayment settlement funds to ERCOT.
NPRR1175: strengthen market entry qualification and continued participation requirements for ERCOT counterparties like QSEs and CRR account holders, classify information in the background check as protected information, modify application forms for QSEs and CRR account holders and add a new background check fee to the grid operator’s fee schedule.
NPRR1185: add a provision for recovery of a demonstrable financial loss arising from a verbal dispatch instruction to reduce real power output.
NPRR1189: changes NPRR1136’s gray-boxed language to align it with existing requirements for AS that resources can only provide fast-response service if awarded regulation service in the DAM for that resource.
NOGRR215: allow new remedial action schemes to only address actual or anticipated violations of transmission security criteria when market tools are insufficient and clarify the procedures for retiring schemes.
NOGRR249: specify methods for transmission operators to receive electronic communication of system operating limit exceedances.
RMGRR174: update language to reflect the current practice of posting regional transmission plans and geomagnetic disturbance assessment plans and update data sets.
RRGRR033: add data to the resource registration glossary pursuant to NPRR1164.
