Page 411 – RTO Insider

October 3, 2022November 11, 2023

Maryland: State Met 2020 GHG Emission Goal, but Behind on 2030

Maryland surpassed its greenhouse gas emission-reduction goal for 2020, according to the final data released by the state Department of the Environment.

According to the data, presented to the Maryland Commission on Climate Change during its quarterly meeting Sept. 27, emissions were down 30% below 2006 levels, beating out its aim to reduce GHGs released by 25% over the same period. Even accounting for the pandemic, which lowered expected pollution from motor vehicles, it is projected that emissions would have declined by 26% over the same period, still meeting the goal.

The most significant declines were in the energy sector, credited to the shift from coal to natural gas and renewable power generation. According to the department’s Vimal Amin, electricity-use emissions fell from approximately 43 MMT of carbon dioxide equivalent in 2006 to about 19 million in 2020.

“Two-thirds of our reductions from [2006] to [2020] have come from the electricity sector, and the reductions here are due to a combination of reduced electricity consumption, as well as changes in the generation mix, namely from replacement of coal-fired generation with natural gas and renewables,” Amin told the commission.

Despite the progress, Mark Stewart, climate change program manager for the department, said in-state clean energy generation lags behind being on track to meet the state’s Greenhouse Gas Emissions Reduction Act goals for 2030. One of the principal causes has been a backlog in reviews for new resources in PJM’s interconnection process.

“There’s been a backlog of projects receiving approval from PJM for connection to the grid, and a lot of these projects are renewable energy,” he said. “That PJM backlog has prevented the development of some projects. They’re working on a new system to fast-track some of those projects that are most ready to be implemented, so we’re optimistic that some of that backlog will be relieved within the next couple of years.”

The decline in energy sector emissions has left transportation as the state’s largest source of GHGs, at 35% of 2020 emissions, the majority of which is on-road vehicles. Amin noted that while the sector has also been seeing a general decline, the drop off going into 2020 is attributed to the COVID-19 pandemic.

The state is also currently lagging behind its 2030 goal of having about 800,000 electric vehicles registered in the state, which Stewart partly attributed to the pandemic reducing the inventory of new EVs on the market.

“On-road gasoline consumption is the biggest single source of emissions in Maryland, so we know the transition to zero-emission vehicles is a key component of the current climate plan and of future climate plans for Maryland,” he said.

Commission Reviews Federal Laws and Funding

The commission also evaluated the impact of the federal Inflation Reduction Act and Infrastructure Investment and Jobs Act on state emission goals, as well as how state and partner organizations are coordinating the use of federal funds.

William Ellis, vice president of government and external affairs at Pepco, said two provisions of the IIJA aim to provide resources for utilities to improve grid resilience under climate change. The utility is preparing concept papers that will allow for them to make applications once the submission period opens.

“It’s helping us to just think through and evaluate concepts related to those two topic areas. Some of the things that we’re thinking through are … undergrounding infrastructure, hardening our substations that could be impacted by climate change, as well as just creating a stronger and more resilient grid aimed at reducing outages through automation of controls, as well as enabling greater renewable penetration on the grid,” he said.

State Department of Transportation Deputy Secretary Earl Lewis Jr. noted that authorization of federal funds for the National Electric Vehicle Program was granted last month, allowing the state to go ahead with its work on installing EV charging stations at regular intervals along 23 identified alternative fuel corridors. (See FHWA Beats Sept. 30 Deadline for Approving States’ EV Charging Plans.)

“We’re working to expand Maryland’s robust electric vehicle charging infrastructure that currently has 1,266 charging stations and 3,475 charging outlets as of Aug. 31, 2022,” he said.

The state has also invested $436 million toward its ZEV program, bus pilots and electric bus procurements, with the first buses expected to arrive next year and a goal of converting half of its 700-bus fleet by 2030, Lewis outlined.

Maryland Energy Administration Chief of Staff Christopher Rice said his agency has been working with outside organizations to support their applications for federal aid, such as a $9 million carbon-capture entity paired with a cement factory; Montgomery County seeking 13 hydrogen fuel cell buses for $14.9 million; and a $22.9 million project with the Department of Labor to train workers for offshore wind installation and to upgrade Sparrows Point for OSW deployment. (See related story, Md. County’s Electric School Buses to Provide Synch Reserves for PJM.)

Stewart said that even with the new federal funds, the state’s shift to a goal of reducing emissions by 60% by 2031 under the Climate Solutions Now Act of 2022 leaves a gap in the trajectory of GHG reductions. One of the act’s provisions includes a 20-year global warming potential (GWP), rather than the prevailing 100-year model, which emphasizes GHGs that have a concentrated impact in their first few years after being emitted, most notably methane.

“The IRA did not end up being quite as ambitious as what we modeled last year as federal action, indicating that if we pair state [and] federal action under this framework, we’ll still have a lot of ground to cover to hit 60%,” Stewart said.

October 2, 2022

Ariz. Regulators Probe CAISO on EDAM, Heat Wave Operations

p.p1 {margin: 0.0px 0.0px 0.0px 0.0px; font: 11.0px ‘Helvetica Neue’; color: #000000}

Arizona regulators say CAISO’s proposed extended day-ahead market could be a good opportunity for utilities in the state if issues of governance and resource adequacy are satisfactorily resolved.

“Independence of the governing structure is something that will be critical for Arizona,” said Arizona Corporation Commission (ACC) member Justin Olson. “If the CAISO can get that worked out where we have an independent governing structure, and they can address the resource adequacy policies in California, then the CAISO becomes a very attractive market for Arizona utilities.”

Commission Chairwoman Lea Marquez Peterson expressed similar views.

“An independent governance structure will be essential to my support,” Marquez Peterson said.

The comments came during a special ACC meeting on Sept. 21, where CAISO gave a presentation on its proposed extended day-ahead market.

CAISO runs the Western Energy Imbalance Market (WEIM), a voluntary, real-time market that was launched in 2014. Arizona utilities participating in WEIM include Arizona Public Service, Salt River Project and Tucson Electric Power (TEP), which joined in April.

CAISO is exploring an expansion of WEIM through an extended day-ahead market (EDAM). The ISO has been gathering stakeholder feedback on its plan and released a revised EDAM straw proposal in August. (See CAISO Updates EDAM Straw Proposal.)

In August 2021, an enhanced governance framework was approved for WEIM, in which decisions on certain issues are made through the joint authority of CAISO’s Board of Governors and WEIM’s Governing Body. The five members of the board of governors are nominated by the California governor and confirmed by the state Senate. The five members of the WEIM Governing Body are chosen through a stakeholder process, according to Stacey Crowley, CAISO’s vice president of external affairs.

Now, the WEIM’s stakeholder-run Governance Review Committee (GRC) has proposed extending the joint authority model to EDAM, Crowley said. GRC is asking for feedback on what types of decisions should be made through the joint authority.

Marquez Peterson said she’d like to see the joint authority widely applied.

“Ensuring that our voices are heard, and that we have the broadest extent of joint authority — that’s the direction I’d like to encourage,” she said.

Consequences Considered

Resource sufficiency is another issue being hammered out in the EDAM straw proposal. EDAM is not intended as a way for participants to bolster energy supplies when their own resources fall short, said CAISO COO Mark Rothleder. Instead, participants have more options for buying energy, potentially saving money.

The straw proposal would require EDAM participants to pass a day-ahead resource sufficiency evaluation (RSE).

“What exactly [do] you anticipate would be the policy if somebody does not have that day-ahead resource sufficiency?” Olson asked Rothleder.

Rothleder said two possible consequences are being discussed. One of those is a surcharge for failing to meet sufficiency requirements. In addition, he said, stakeholders are weighing whether there should be an “ultimate consequence” for resource insufficiency.

“If things go really bad, should you be able to still rely on those transfers, potentially impacting somebody else?” Rothleder said. “Potentially, the answer is ‘no.’ If you get in that position, and you’re not sufficient on your own, you shouldn’t be able to still rely on those transfers at the same level, or the same level of priority, as someone who did pass.”

Marquez Peterson asked what happens if CAISO is insufficient.

“If we are insufficient, we will follow the consequences,” Rothleder said.

Heat Wave Response

Rothleder also discussed CAISO’s response to the heat wave that scorched California from Sept. 5-9. Rolling blackouts were narrowly averted during the record-setting event, in which CAISO saw demand reach an all-time record of 52,061 MW on Sept. 6. (See California Runs on Fumes but Avoids Blackouts.)

Since the state’s rolling blackouts in August 2020, California has added more than 6,000 MW of capacity, including about 3,700 MW of battery storage. That capacity helped CAISO handle increased loads during the heat wave, Rothleder said. In addition, he said, coordination with other agencies has been improved.

And a few other factors worked in CAISO’s favor, Rothleder said. The heat wave hit the Pacific Northwest a bit earlier, taking some of the pressure off when high temperatures arrived farther south. Hydroelectricity was more available than usual for the time of year. And although temperatures in Arizona reached 107 or 108 degrees, the heat there wasn’t considered extreme, he said.

“This is very alarming to say the least,” Marquez Peterson said. “Without a moderate weather event in Arizona, California ratepayers would have been at public health and safety risk.”

In response to a question from Commissioner Sandra Kennedy, Rothleder acknowledged that CAISO was receiving emergency assistance from Arizona utilities and paying prices above $1,000/MWh.

Sam Rugel with TEP described the situation as “excellent for the ratepayers.”

“Being in the EIM, we were exporting throughout the day, day and night, into the Cal ISO market, in real time,” Rugel said. “And that does roll back to the ratepayers.”

But Rugel said the situation raises questions about resource adequacy.

“As much as this helps the neighbors … they should not be in this situation,” he said.

Regional Markets Explored

The ACC opened a docket last year for the purpose of investigating regional planning, markets and collaboration among load-serving entities in the Western Interconnection.

As part of its research, ACC heard a presentation in August from SPP on its Markets+ proposal, a program under development that will include a day-ahead market in the West.

In September, SPP announced that four Arizona utilities — Arizona Electric Power Cooperative, Arizona Public Service, Salt River Project and Tucson Electric Power — plan to support the next phase of Markets+ development. (See 4 Arizona Entities Commit to Developing SPP’s Markets+.)

ACC’s Utilities Division expects to file a report on regional planning and markets issues by the end of October.

October 2, 2022

Road Tests Show Kenworth Fuel Cell Semi Stacks up to Diesels

A more than year-long test of 10 hydrogen-fueled semitrucks demonstrated that the vehicles can perform roughly equally with their 5-year-old diesel equivalents.

However, the maker of the trucks is staying mum about future testing and manufacturing plans.

The test runs at the Port of Los Angeles were financed by part of a $41 million Zero and Near-Zero Emissions Freight Facilities grant awarded by the California Air Resources Board, with the port as the prime applicant. The grant is part of California Climate Investments, a state initiative funded by billions of cap-and-trade dollars.

The Port of Los Angeles has set a goal of producing net-zero carbon emissions from its short-haul trucks by 2035.

A Kenworth truck manufacturing plant in the Seattle suburb of Renton made the trucks. Kenworth is owned by PACCAR, which is based in the Bellevue, Wash.

“We clearly showed that hydrogen is a viable clean fuel capable of powering commercial transportation for customers, matching diesel performance in range and power, with quick refueling for minimal downtime and smooth, quiet operation,” Joe Adams, Kenworth chief engineer, said in a Sept. 22 press release. The test runs ended in August

Toyota Motor North America and Kenworth joined forces to design and build the hydrogen-fueled semis. The trucks are Kenworth T680s built with Toyota hydrogen fuel cell electric powertrains, with water being the only emissions. The trucks went through initial tests at a PACCAR facility in Mount Vernon, Wash.

The Kenworth T680 FCEV truck — dubbed an “Ocean” — was supposed to work comparably with a 2017 diesel engine driving about 200-350 miles a day. The T680 FCEV has a range of more than 300 miles when fully loaded to 82,000 pounds.

The 10 test trucks normally worked one-day hauls around the Port of Los Angeles in the greater Los Angeles area. Toyota Logistic Services, UPS Total Transportation Services and Southern Counties Express were other freight carriers using the trucks.

The trucks frequently handled multiple shifts and ran 400 to 500 miles per day. Swapping out the hydrogen fuel cells took 15 to 20 minutes, according to the press release.

“Hydrogen infrastructure is still in its infancy, so hydrogen fuel is more expensive than diesel to fuel the truck,” PACCAR spokesperson Jeff Parietti said in an email. “We would expect the costs to come down as scale of production/distribution increases. Preventative maintenance is primarily a series of fluid replacements and inspections. So there is the opportunity for reduced maintenance costs over diesel.”

In the press release, Andrew Lund, Toyota chief engineer for zero-emission advanced product planning, said: “The potential for this technology as a replacement for higher-emission powertrains is real and supports both regulatory and society initiatives to combat climate change while helping us achieve our own goals of carbon neutrality.”

PACCAR and Kenworth do not have a prospective price tag for an individual T680 FCEV truck.

In a 2021 interview, port officials said the purchase price for a new diesel semi is $110,000 to $120,000, roughly $350,000 for a battery-powered semi and an estimated $1 million for a hydrogen-fueled semi.

In an email to Net Zero Insider, PACCAR declined to discuss its next testing and manufacturing plans.

October 2, 2022

Stakeholders Not Sold on JTIQ Projects’ Cost-Sharing Plan

MISO and SPP stakeholders expressed their consternation Friday over the RTOs’ proposed cost allocation for their interregional transmission planning initiative designed to ease overloaded generator interconnection queues.

The discord arose during a workshop over allocating costs for the grid operators’ Joint Targeted Interconnection Queue (JTIQ) study.

MISO and SPP plan to assign 90% of the $1 billion JTIQ portfolio to interconnection customers and the remaining 10% to an aggregate of their load. The RTOs said they will allocate a fixed, per-megawatt charge to interconnection customers that affect a facility in the neighboring region to pay for the portfolio. (See MISO, SPP Propose 90-10 Cost Split for JTIQ Projects.)

The RTOs are proposing a 5% distribution factor (DFAX) impact threshold on a neighboring system before interconnection requests are considered in a JTIQ-affected system zone and therefore, subject to transmission-cost sharing.

“We want to ensure the cost related to these JTIQ projects … are certain and reasonable,” Clint Savoy, SPP’s manager of interregional strategy, said during the workshop. He said the RTOs continue to believe that a 5% DFAX results in the most equitable cost allocation among interconnecting generation along their seam.

Stakeholders responded by saying MISO and SPP haven’t provided enough analysis that the 5% criterion is the best route.

The staffs said when they employed a 10% distribution factor, generation eligible to share in transmission costs dropped by nearly 60%. When the factor was increased to 15%, eligible generation plummeted by about 80%, making network upgrade costs untenable for the remaining interconnecting generation.

“If you make the zone too small, you could potentially, I think, incent siting generation outside of the zone,” Savoy said.

Some stakeholders repeated calls for an 80-20% split between generation and load assignment. They said load stands to benefit more than the 10% portion of JTIQ transmission costs.

North Dakota Public Service Commission Chair Julie Fedorchak said the 90-10 generation-load cost-allocation split is almost moot because generators will bake their JTIQ upgrade costs into customer bills.

“Those costs will ultimately be paid by the load,” she said.

MISO and SPP are also proposing another regional study for generation projects that: either have a 10% or greater DFAX impact on the neighboring system or who affect a certain number of the neighboring RTO’s substations, based on voltage rating. The RTOs said the study is necessary to monitor new local constraints caused by the incoming generation not covered by the major JTIQ transmission projects. When that happens, the host RTO plans to coordinate with the other RTO and transmission owners to “formulate a mitigation plan to alleviate the identified localized constraints.”

Clean Grid Alliance’s Natalie McIntire said stakeholders have “discomfort” with the cost-allocation proposal because MISO and SPP cannot provide an understanding of the overall costs that new generation will shoulder.

“It’s hard to know how all of these pieces will fit together and whether the result is going to be workable for interconnection customers and will result in viable projects,” she said.

Savoy said though he knows stakeholders would prefer a predicted range of costs, that’s “impossible” to provide at this point.

“This is an incremental step forward. We can’t give you complete cost certainty,” he said. However, Savoy said the JTIQ allocation should lower interconnection customers’ costs and asked stakeholders to at least give the RTOs a chance to improve the process.

David Kelley, SPP’s director of seams and market design, said interconnection customers splitting the costs of larger, “backbone projects” that allow mass interconnections is preferrable to the grid operators’ current affected system study process, where often high-priced network upgrades are designated to individual generation projects.

“We have to come up with a way to fund the transmission needed in this area,” Kelley said. “Basically today, we have an area that generators cannot develop in.”

“We are in agreement that the status quo sucks,” National Grid Renewable’s Rafik Halim said.

Invenergy’s Arash Ghodsian said he was supportive of the initial design but asked for a better explanation of the assumptions of proposed cost assignments’ mechanics.

October 2, 2022December 27, 2023

Report Faults Top Firms on Emission Incentives for CEOs

Many large emitters of greenhouse gases incentivize their executives insufficiently or not at all to reduce those emissions, a corporate watchdog group says in a new report.

The practice of linking executive compensation to progress on environmental, social and governance metrics is growing, with just over half of all S&P 500 companies reporting such a linkage in 2021, the nonprofit As You Sow said in “Pay for Climate Performance.”

The report focuses on the 47 U.S. companies on the Climate Action 100+ list, an investor initiative pressing for change by the world’s largest greenhouse gas emitters. It assigns the companies letter grades based on their inclusion of a climate metric in their 2021 CEO pay package; inclusion of measurable climate metric and measurable pay; and inclusion of climate metric in the long-term incentive plan.

Twenty-five of the companies had no explicit link of emissions to executive pay and got an F, while 17 got a D. Marathon Petroleum, Valero Energy, Southern Co. and American Electric Power got C’s.

Xcel Energy (NASDAQ:XEL) got the one and only B.

“Xcel Energy received a B for linking CEO pay to emissions-reduction performance in its long-term incentive plan, with a measurable amount of pay related to achievement of reduction goals,” the report’s authors wrote.

To get an A, a company would have to align its goals and incentives to the 1.5-degree Celsius warming target of the Paris Agreement. None of the 47 did this, the report found.

Other findings highlighted by the authors:

- - At most companies offering climate-based pay incentives, the sum involved was a small fraction of the overall compensation package and thus of negligible value as an incentive.
  - Company proxy reports were short on transparent disclosure, making it difficult to distinguish effective CEO pay links; transparency would increase by linking quantitative climate metrics to measurable pay.
  - Discretion is rarely used to alter CEO pay for financial metrics and should be equally rare with climate metrics.
  - Where climate incentives are dwarfed by financial performance metrics, emissions reductions will not be a priority for the CEO.
  - Climate incentives should be framed as quantitative metrics such as “reduce GHG emissions by 30% by 2030 over a 2021 baseline” rather than qualitative measures such as “progress efforts in support of the energy transition” or “demonstrate leadership.”

The report’s authors also give advice to investors hoping to drive climate progress at a company: “When considering the quality of the compensation and climate link, investors need to concurrently consider the quality of the company climate transition plan and its alignment with CEO pay. Investors should also pay particular attention to the interaction of compensation design and the rigor of the climate metric. A facile understanding of the nuances of compensation or the company-specific transition plan can result in the addition of a metric intended to appease shareholders that inflates pay and nothing more.”

As You Sow calls itself an organization “dedicated to increasing environmental and social corporate responsibility while increasing company value.” The nonprofit, formed in 1992, “envisions a safe, just and sustainable world in which environmental health and human rights are central to corporate decision-making.”

October 2, 2022

AEP Accepts Lower Price for Kentucky Operations Sale

American Electric Power and Liberty Utilities, a subsidiary of Algonquin Power & Utilities, said Friday they have struck an amended sale agreement that cuts the price of AEP’s Kentucky operations by $200 million and extends the timeline to close the deal.

Liberty will now acquire AEP’s Kentucky operations at a reduced $2.646 billion through a purchase of all Kentucky Power’s and AEP Kentucky Transco’s stock. The original deal had Liberty paying a $2.8 billion sale price. (See PSC OKs Sale of AEP’s Kentucky Operations to Liberty Utilities.)

AEP expects to net approximately $1.2 billion in cash from the sale. It said the reduced revenue means that it will likely record a pre-tax loss ranging from $180 million to $220 million in the third quarter.

Liberty and AEP said they will close on the sale in January. The transaction was earlier slated to close by mid-2022. FERC must still approve the sale.

“This sale will provide significant benefits to customers in eastern Kentucky to help offset volatile fuel prices and support economic growth,” retiring AEP CEO Nick Akins said in a news release. “It also will support AEP’s ability to invest in projects throughout our regulated businesses that will enable the move to a clean, more reliable and resilient energy system.”

AEP CFO Julie Sloat, who will succeed Akins on Jan. 1, said that the new timeline will not affect AEP’s planned equity needs or its operating earnings guidance.

October 2, 2022December 27, 2023

Maryland County’s Electric School Buses to Provide Synch Reserves for PJM

Montgomery County Public Schools (MCPS), in Maryland, is expanding its partnership with a company electrifying its bus fleet to use the vehicles as a distributed energy resource on the PJM wholesale electricity market, DER software provider Voltus announced on Wednesday.

MCPS and Highland Electric Fleets entered into a contract last year to electrify the county’s 326 diesel school buses. Voltus said its software will allow the buses to provide wholesale synchronized reserves, improving grid stability and increasing the school system’s cost savings.

“By connecting Highland’s customers to electricity markets that value them, Voltus is unlocking the power of electric vehicle fleets,” said Dana Guernsey, Voltus’ chief product officer. “We’re thrilled to demonstrate the value that electric school buses can provide to support grid reliability. … We aim to help Highland accelerate the transition to 100% electric school buses by layering on ancillary services and other value streams, which make adopting electric school buses the profitable choice.”

The company says it has a 2,600-MW portfolio across all nine U.S. and Canadian wholesale power markets. The resources include small-scale residential clients to major manufacturers and data centers.

Under the $1,312,500 four-year contract Highland and MCPS entered last year, Highland will provide the school buses, install charging infrastructure, assist in training drivers and mechanics, and pay for the electricity, maintenance and repair costs. (See Schools’ ‘Budget Neutral’ Bus Deal Could Accelerate BEB Growth.)

“Partnering with Voltus allows us to offer another value stream to school districts, further lowering the cost of upgrading to electric and also supporting increased renewable energy penetration by making the bus batteries available to utilities and wholesale electricity markets when they’re not being used to transport students,” said Ben Schutzman, vice president of fleet operations at Highland.

October 2, 2022June 14, 2023

ERCOT, Texas PUC, Gas Industry Agree Valuable Lessons Learned

AUSTIN, Texas — ERCOT staff and state regulatory representatives agreed the electricity and gas industries have learned valuable lessons from the February 2021 winter storm, lessons that are now being put into place to winterize and protect critical facilities in the supply chain.

“One of the big lessons we learned coming out of [Winter Storm] Uri was we can’t be stagnant,” Thomas Gleeson, the Public Utility Commission’s executive director, said during the Texas Reliability Entity’s Extreme Events Resiliency Workshop on Sept. 20-21.

Texas RE staff moderated a series of discussions on grid resilience topics with industry experts during the two-day event.

Gleeson chairs the Electric Supply Chain Security and Mapping Committee, which was created by legislation following last year’s storm to prevent mistakenly shutting down critical gas infrastructure during a load shed. The group completed the map’s first version in April, easily beating its Sept. 1 deadline. It identified 65,000 facilities, 60,000 miles of electric transmission lines and 21,000 miles of gas transmission pipeline.

While the mapping committee met in private because it is dealing with critical infrastructure, it did hold two public meetings.

“The goal [of the open meetings] is to rebuild public trust. We need to be out there talking to folks about what we’re doing, why the map has to stay secure and private,” Gleeson said. “It’s important for us to explain the work that we’re doing to ensure to Texans that we are providing them with the best grid that we can.”

Working on a separate path, PUC staff developed expanded weather preparation rules for generators and transmission utilities to ensure reliability during both summer and winter weather events. The PUC adopted those rules on Thursday.

Natalie Dubiel, an attorney for the Texas Railroad Commission, thanked the mapping committee for its work, which started a six-month clock for the regulatory body to adopt its own weatherization rules. The RRC, which oversees the state’s natural gas and oil industries, had its rule in place Sept. 19, beating its deadline by almost six weeks.

“The rule is fairly dense,” Dubiel said. “We did want to get it in place before that timeline just to give our operators a chance to prepare for this upcoming winter, particularly given that this is a whole new area of jurisdiction that the Railroad Commission did not have.”

Rule 3.66, as it’s known, applies to gas supply chain and pipeline facilities. Their operators must implement “weather emergency preparation measures” by Dec. 1 each year that ensure sustained operations during a weather emergency and correct weather-related forced stoppages that prevented sustained operation because of previous weather emergencies.

Dubiel said the RRC broadened the definition of energy emergency to cover more than just load-shed events.

“There may be times the grid is constrained and demand is high. We want gas flowing,” she said.

David Kezell 2022-09-21 (RTO Insider LLC) FI.jpg

“We’re better prepared than we were last year,” said ERCOT’s David Kezell, who joined the grid operator as its first director of weatherization and inspection last October.

ERCOT developed an inspector training program, hired inspectors and sent them out into the field before last winter to check on generators that failed during the 2021 storm. Kezell said market participants demonstrated “high levels of compliance” last winter. Going forward, inspections will occur before both the winter and summer seasons for generation resources and transmission facilities.

“This really is a team effort. … Where the rubber meets the road is in the facilities and the people that are doing the work,” he said. “We’ve got a new structure in terms of state law. The actual technicians have to do a good job of doing their job, so we applaud them for the effort that they’re going through.”

Cold Weather Standard Nears Approval

Mark Henry, Texas RE’s director of reliability services and registration, said he expects the NERC Board of Trustees to approve the EOP-012-1 (extreme cold weather preparedness and operations) standard during its October meeting, with FERC approval then coming before year-end.

The standard passed NERC’s membership on its second attempt earlier in September. The standard, part of NERC’s Project 2021-07 (extreme cold weather grid operations, preparedness and coordination) in response to the mass outages caused by the February 2021 winter storm, was posted for comment in May. (See “Updates on Standards Projects,” NERC Board of Trustees/MRC Briefs: Aug. 17-18, 2022.)

“There’s a little bit more bite and specificity to [the standard],” Henry said.

The standard revises some requirements instituted after the 2019 cold weather event involving MISO and SPP. It adds freeze-protection criteria to freeze-protection systems; a five-year review of minimum temperatures, cold-weather plans and freeze-protection measures; and corrective action plans for freezing events.

It will take effect April 1, 2023.

Work continues on a second standards authorization request for the 2023/24 winter, Henry said. This phase of Project 2021-07 would set requirements for identifying cold-weather critical components and systems for each generating unit and implementing freeze-protection measures; determining the generating capacity that can be relied upon during “local forecasted cold weather”; and protecting critical natural gas loads from load shed.

Early Projection for Mild Winter

ERCOT’s in-house meteorologist, Chris Coleman, promised his audience they will eventually see a respite from one of Texas’ hottest summers on record. Winter is coming, he said, but it has a greater potential to trend warmer than colder.

The potential of a third-straight La Niña winter is one reason why. Coleman said that since 1950, there have been 26 La Niña winters in Texas. Fourteen of those have fallen in the warmest third of all winters, but three have fallen in the coldest third.

Chris Coleman 2022-09-21 (RTO Insider LLC) Alt FI.jpg

“There is some correlation between La Niña and the unlikelihood of a cold winter,” he said. “There’s no correlation between La Niña and a winter with an extreme cold event.”

It can happen, though. Since 1894, Dallas has had 14 winters where the temperatures have reached 5 degrees Fahrenheit or lower. Two of those occurred during La Niña.

“When I say it’s going to be a warm winter, there could still be a day or two, or a week or two, that’s extremely cold,” Coleman said. “You can get some pretty dramatic changes in the winter.”

June through July was the second hottest period for Texas, topped only by 2011. Those months were also the 39th driest on record — 2011 is No. 1 there too — and the fifth driest this century. Austin has recorded 68 100-degree days this year, San Antonio 58, Dallas 47 and Houston 22. One more 100-degree day in Austin would move 2022 into second place for days over the century mark, behind only 2011.

“If you’re getting close to records, you might as well just break the record,” Coleman said. “In fact, I get upset when it’s 99 degrees. ‘Just give me that 100. It’s not like it feels that much different.’”

September 29, 2022

NJ BPU Approves Easement Plan for 1st OSW Project

The New Jersey Board of Public Utilities (BPU) on Wednesday approved an easement sought by the state’s first offshore wind project, Ocean Wind 1, to run transmission onshore through Ocean City to a substation, removing a key obstacle to the project.

With little comment, the five-member board unanimously approved an order that said developer Ørsted had demonstrated that the easement for transmission to run underground across land developed with money from the state Green Acres program was “reasonably necessary” to the construction and operation of the wind project. Green Acres funds are awarded to develop parks and open space. The order also granted the project a series of consents needed to obtain environmental and other permits.

The BPU’s approval, in the face of opposition from Ocean City’s governing body and residents, opens the way for Ørsted to seek easement and permit approval from the New Jersey Department of Environmental Protection (DEP), which is needed for the project to get federal backing. Ocean City had asked the BPU to delay the project while an administrative hearing and environmental studies of the cable route are conducted.

However, the project still needs the BPU’s approval in a second case, in which the developer needs permission to run transmission on land owned by Cape May County and that government’s consent on permit approvals.

The Ocean City case was first test of a controversial law enacted in July 2021 that allowed offshore wind developers to site power cables and equipment on public land regardless of local or state government opposition. The outcome of the case could provide a roadmap for other projects facing similar opposition in the future.

The reasonably-necessary standard was set out in the law, which specifically prohibited municipal and county governments, and state agencies, from preventing the placement of offshore wind equipment if the BPU gave its approval. (See NJ Lawmakers Back Offshore Wind Bills.) Several speakers at public hearings into the easement argued that the law effectively disenfranchised local officials and removed their authority to make decisions on issues that would affect their residents.

Ørsted is seeking a 30-foot-wide easement running the length of the island on which the city is located, which is about 8 miles long. A 275-kV line will connect Ocean Wind’s turbines, about 15 miles offshore, to the PJM grid at a substation sited on a now closed coal-fired power plant in neighboring Upper Township.

Without the law in place, and the BPU’s power to override local authorities, the project would have needed Ocean City’s consent for several permit approvals, including Waterfront Development, Wetlands Act of 1970, Coastal Area Facilities Review Act, Flood Hazard Area Control Act and Freshwater Wetlands Protection Act, and a Tidelands License, among other permits, according to the order.

Those permits are required for the DEP to “issue a federal consistency determination, which is a prerequisite for Bureau of Ocean Energy Management’s (BOEM) approval of the project’s construction and operations plan,” according to the order.

The 1,100-MW Ocean Wind project, which was approved in 2019, was the first of three approved offshore wind farms by the state so far. The BPU has also approved the 1,148-MW Ocean Wind 2 and the 1,510-MW Atlantic Shores, and the state expects to hold a third solicitation, for 1,200 MW, in the first quarter of 2023. (See related story, NJ Seeks Stakeholder Input for 3rd OSW Solicitation.)

The BPU’s ruling came the day before it holds two online hearings on another easement for an underground transmission line from the Ocean Wind 1 project across land owned by Cape May County. In that case, Ørsted’s petition says Cape May officials have not responded to its efforts to secure approvals.

Public Opposition

Although the Ocean Wind project is strongly supported by government officials and embraced by environmentalists, Ocean City opposes the project, as do local residents, who say the nearly 100 turbines will tarnish their ocean view. Also opposed are commercial fishermen, who say it will hurt their ability to fish, and tourism interests, who fear fewer visitors will come to enjoy a shoreline with turbines on the horizon. (See Ørsted NJ Wind Project Faces Local Opposition.)

The board’s approval Wednesday in the Ocean City case followed two public hearings into the easement application and an online session in which Ørsted and the city presented oral arguments. Speakers in the two hearings opposed to the easement focused as much on their concerns about the project as a whole, and offshore wind in general, as on the details of the easement and how it would affect the community.

Mike DeVlieger, a former Ocean City councilman, said that “overwhelmingly our community is against this, and it’s not even close.” He added that “this presents medical concerns; it can present environmental concerns.”

But environmentalists argued that the threat of climate change is so serious that radical action was needed, and any potential disruption would not reach an unacceptable level.

Dorothy F. McCrosson, solicitor for the city, argued that Ocean Wind 1 could avoid the conflict with Ocean City if it opted to send the transmission through nearby Egg Harbor instead. In that scenario the beach and wetlands would not be disturbed and the streets would not be excavated.

She said the alternative route would present no disruption to Ocean City, but Ørsted had dismissed it earlier because it would be more expensive.

But attorney Gregory Eisenstark, representing Ocean Wind 1, said that once the construction was complete, there would be minimal disruption because the lines would be underground. He argued that the main reason that the city opposes the project “has to do with Ocean City’s overall objection to offshore wind.”

He argued that under the reasonably-necessary standard set out in the law, the route chosen by Ørsted just had to be a reasonable one. “It doesn’t have to be the best one. It doesn’t have to be the lowest-cost one.”

September 29, 2022

ISO-NE Weighs in on FERC’s Proposed Interconnection Changes

ISO-NE repeated a familiar refrain on Wednesday while presenting its initial take on FERC’s interconnection Notice of Proposed Rulemaking: give us flexibility and make sure our region’s particular needs can be met.

The rulemaking is intended to help free up what FERC commissioners see as a backlog slowing the development of new generation and in turn threatening reliability. (See FERC Proposes Interconnection Process Overhaul).

But in a presentation to NEPOOL’s Transmission Committee on Wednesday, ISO-NE made clear that it sees its own interconnection challenges as less daunting than what some of the other, larger RTOs are facing.

“New England does not currently suffer interconnection queue backlogs to the same extent as other regions,” said Al McBride, the grid operator’s director of transmission strategy and services.

ISO-NE is still readying its formal comments, but in the preliminary ideas presented to stakeholders, McBride emphasized that the proposed changes to the interconnection process for RTOs are “expansive” and would involve trade-offs about how grid operators spend their time.

In recent years, McBride noted, ISO-NE has integrated its interconnection planning with the Forward Capacity Market, launched the Elective Transmission Upgrades project, and adopted clustering procedures which let projects be evaluated together.

Those changes shouldn’t be overwritten by whatever comes out of the NOPR, the grid operator is arguing.

“It will be important to explain that it will be preferable to retain some aspects of these enhancements under allowances for regional differences, which is consistent with the NOPR,” McBride said in his presentation.

For example, the NOPR calls for a new cluster study process, which in some ways clashes with what ISO-NE is already doing.

Another point of the NOPR, which is likely to be among its most contentious, is that the proposed rule would carry with it new firm deadlines for interconnection studies and penalties for transmission providers if they aren’t met. Those new features would replace the existing “reasonable efforts” standards.

ISO-NE is wary of the proposed new penalties for several reasons: McBride warned that adding a punishment could introduce the potential for litigation or administrative processes that could distract and divert resources away from conducting the actual studies at the heart of the interconnection process.

And he also noted that sometimes delays aren’t the fault of ISO-NE.

The deadline for comments to FERC on the NOPR is Oct. 13, with reply comments due on Nov. 14.

NEPOOL counsel also published draft stakeholder comments on the NOPR last week, with the theme the same: allow for flexibility.

“NEPOOL urges the Commission to allow for variations from the pro forma procedures and agreements in any ISO/RTO compliance with and implementation of the final rule, to the extent justified under the independent entity variation standard,” the comments read.