Page 358 – RTO Insider

January 2, 2023

Passage of the IRA Reshapes US Clean Energy Transition

The biggest clean energy story of 2022, hands down, was the passage of the Inflation Reduction Act, rising improbably and miraculously from the ashes of President Joe Biden’s Build Back Better Act of 2021.

The IRA and its $369 billion in clean energy funding, builds on the foundation laid by 2021’s Infrastructure Investment and Jobs Act, which included another $62 billion in funding for clean energy initiatives that began rolling out this past year.

The full impact of the two laws will likely be incremental, unfolding over the next five to 10 years, but 2023 will be pivotal as the Biden administration continues to push forward with its clean energy agenda, and private industry and finance make decisions about adding their own dollars to the billions in clean energy grants, tax credits and other incentives contained in the two laws.

The administration’s focus will be on delivery. In a series of appearances at recent energy conferences, National Climate Advisor Ali Zaidi has called on corporations and private investors to get off the sidelines and put steel in the ground. “For folks in the private sector, the time to make decisions is now. Boards can’t commission study committees; they’ve got to greenlight capital projects,” Zaidi said in a keynote address for a Resources for the Future conference in October.

But implementing the IIJA and IRA also raises complex issues as federal and state agencies hash out the details of legislative language and the intent of the lawmakers who crafted it. Other headwinds include inflation, Russia’s war on Ukraine and the lingering effects of the COVID-19 pandemic on clean energy supply chains.

The NEVI Example

While the IIJA and IRA are both trimmed-down, compromise versions of the original bills Biden and Democratic leaders hoped to pass, getting the laws through a deeply divided Congress was an extraordinary achievement. The often-tense negotiations, in particular for the IRA, required a fine balance between the Democrats’ progressive wing and the swing votes of conservative Democrats Sen. Joe Manchin and Sen. Krysten Sinema, now an independent.

What matters now, with the 2024 presidential election already on the horizon, is the impact the laws will have on the way the U.S. produces and consumes energy and how such changes are perceived by individual consumers. Will the IIJA and IRA deliver new, cleaner technologies, emission reductions and cost savings — as well as the sense of urgency and mission that is required to curb the mounting impacts of climate change?

The IIJA’s National Electric Vehicle Initiative (NEVI) provides an early look at the complexly layered issues that will likely surface as each new program is rolled out. With $7.5 billion from the IIJA, the goal of NEVI is to create a national network of 500,000 EV chargers over the next five years, with 150 kW DC fast chargers located along interstate highways, as well as in rural, tribal and disadvantaged urban communities.

The law provides millions in yearly allocations to individual states, which must submit plans to the Federal Highway Administration, showing how they will use the funds and identifying the specially designated routes and other locations where chargers will be installed. A joint effort of the Department of Transportation and the Department of Energy, the first guidelines for NEVI were announced in February, followed by more detailed technical standards in June.

As required, all 50 states, the District of Columbia and Puerto Rico submitted their plans by an Aug. 1 deadline, which were approved by the FHWA, also on deadline, by the end of September. (See US Completes Review of State EV Charging Plans.)

But many state plans raised a range of concerns about the program’s requirements, such as the mandate for the EV chargers to be located every 50 miles on key interstate and state highways, with charging stations installed no more than one mile off these roads. Highways running through remote or rural regions simply may not have the electric distribution system needed for the high-powered fast chargers or the traffic needed to make the installation of fast chargers pencil out.

Utilities have warned that building out the poles and wires in remote areas will need to occur in stages over several years. Making sure chargers are installed in areas where potential EV owners may live in multifamily apartment houses or other affordable housing is another area where many states are still developing policies and plans.

Installation of the first NEVI-funded charging stations should start this year, but Biden’s vision of a seamless, national network of chargers that will make topping up EV batteries as easy as stopping at a gas station, and banish drivers’ range anxiety, will likely encounter more than a few bumps and detours.

Implementing the IRA’s wide range of tax credits and other incentives could be even more complex, as states and industry stakeholders wait for the federal guidelines needed to put the cash incentives for electric vehicles, heat pumps and other energy efficiency technologies in consumers’ hands.

The Internal Revenue Service ran up against a year-end deadline for issuing guidelines for the IRA’s EV tax credits, without providing detailed guidance on domestic content requirements called for in the law. Manchin quickly called for a hold on the incentives and threatened additional legislation to ensure the IRS follows the letter of the law.

In other words, both sides of the aisle have major stakes in the IIJA and IRA, and the amount of money and scope of the programs involved almost ensure that mistakes will occur, and individuals and businesses will try to game the system.

Federal and state agencies face steep and slippery learning curves in the months ahead, and a small army of whistleblowers and gadflies will be watching their every step.

Inflation, COVID and the War in Ukraine

Even before the IRA was passed, congressional Republicans were talking up plans for whittling away at some of its provisions following November’s midterm elections, in which they had hoped to regain control of both the House and Senate. But, with the Democrats holding the Senate and the GOP winning only a slim majority in the House, efforts to slow or sideline implementation of the IRA will be limited to general political sniping and oversight hearings.

At the same time, the combined effects of inflation, Russia’s war in Ukraine, and the lingering impacts of the COVID-19 pandemic, could present additional obstacles to the implementation of the laws, and Biden’s clean energy agenda in general.

COVID-19 was an early trigger for inflation as factory closings and the resulting production slow-downs hit supply chains, not only in clean energy, but across the economy. After years of steady decreases, prices for solar panels and storage started to inch up, and installations slowed down. According to figures from Wood Mackenzie, solar installations in 2022, estimated at 18.6 GW,fell about 23% from 2021, with new utility-scale deployments falling 40%.

The war in Ukraine triggered a worldwide “dash to gas” as both European and Asian countries faced the immediate and potentially disastrous cutoff of their supplies of Russian natural gas, looking instead to the U.S. to keep their economies fueled and their consumers warm through cold winters. With mounting pressure from Republicans to “unleash” U.S. fossil fuels through increased leasing on public lands and approval of new or unfinished pipelines, the Biden administration and congressional Democrats have had to walk a fine line balancing the immediate needs of U.S. consumers and overseas allies with the impacts of climate change.

Biden and other energy leaders worldwide argued that the short-term need to boost natural gas production should not be used to slow or stop the global move to clean energy, which would provide the best defense against both inflation and Russia’s weaponization of vital energy supplies.

While inflation is nosing down, price increases and supply chain challenges could continue to slow critical clean energy projects. Biden’s goal of installing 30 GW of offshore wind by 2030 prompted a surge of activity last year with the Bureau of Ocean Energy Management holding a series of high-profile offshore lease auctions for sites on both the Atlantic and Pacific coasts.

The auction of six sites in the New York Bight, a curve in the New York-New Jersey coastline, produced record-breaking bids totaling $4.37 billion. At the same time, states up and down the Mid-Atlantic coast are expanding port facilities and drawing in new OSW manufacturers, all vying to become major hubs for offshore construction and operations.

For example, New Jersey’s ambitious plans for a purpose-built offshore wind port could cost between $500 million and $550 million and could create up to 1,500 manufacturing, assembly and operations jobs, according to figures from the state’s Economic Development Authority. (See NJ to Expand Wind Port with Land Purchase.)

But the economics of developing and financing these offshore wind projects — and building the necessary transmission — remain uncertain. The West Coast sites will require floating turbines, which will present another level of technical and financial challenges.

PPAs and Supply Chains

The Massachusetts Department of Public Utilities ended the year with Friday’s approval of contracts, called power purchase agreements, for the 1.2 GW Commonwealth offshore wind project and the 804 MW Mayflower project, despite petitions from both project developers to allow them to renegotiate due to rising costs, as reported in The New Bedford Light.

Following the DPU decision, Craig Gilvarg, a spokesperson for Commonwealth developer Avangrid, said, “The current Power Purchase Agreements do not allow the company to secure the significant financing needed to construct this critical project, and thus the project cannot proceed under these contracts.”

A joint project of Shell New Energies US and Ocean Wind, the Mayflower project will move forward, but the developers have signaled their current plans will focus on completing only an initial 400 MW.

Building out domestic supply chains for offshore wind, electric vehicles, batteries, solar panels and other technologies was yet another major flash point in 2022 — and an easy target for Republican criticism of the clean energy sector’s dependence on China and Russia for critical minerals, including lithium, cobalt and uranium.

Biden has promoted “Made in America” initiatives as a top priority in the IRA’s manufacturing and clean technology tax credits, and the auto industry, in particular, has responded with a series of announcements on plans for new factories and for the retooling and expansion of existing facilities for EV and battery production.

But building out an extensive U.S. clean energy supply chain, especially for critical minerals, will take years, billions in private investment and a willingness by all stakeholders to tackle the essential issue of permitting reform.

Both parties know reform is critical, but whether they will put politics aside and hammer out a deal could be one of the biggest stories of 2023.

January 2, 2023December 30, 2023

Climate Still on Washington Agenda After Landmark Legislative Sessions

Washington’s 2023 legislative session will seem less revolutionary on the climate front compared with the last two years, which saw the passage of landmark — and controversial — bills to reduce the state’s carbon emissions.

Still, a healthy number of environmental bills are in the works for 2023.

“Biggest thing is to focus on implementing the things we said we’re going to do,” Sen. Joe Nguyen (D) from Seattle, the new chair of the Senate Environment, Energy and Technology Committee, told NetZero Insider.

“There’s a lot of enthusiasm among House and Senate Democrats to keep momentum going,” said House Majority Leader Joe Fitzgibbon (D) of West Seattle.

One of the greatest challenges facing lawmakers will be deciding how to divvy up revenue generated by the state’s new cap-and-trade program, passed by the Democrat-controlled legislature in 2021 along party lines. Lawmakers that year also enacted a low-carbon fuel standard and implemented a soft goal for the state to taper off sales of gasoline-powered cars by 2030. That was followed last year by Gov. Jay Inslee’s mandate that all cars sold in the state be emissions-free by 2035.

The cap-and-trade program’s first carbon allowance auction is scheduled for Feb. 28. The auction — one of four to be held this year — will offer 6.185 million allowances at a minimum allowed bid of $22.20 per allowance. Entities will be able to bid on blocks of 1,000 allowances.

Under auction rules, the highest bidder would get first crack at the limited number of allowances, the second highest bidder would get second crack, and so on. The auction ends when the all the designated allowances are bid upon. Then, all the successful bidders will pay the same price per allowance as the lowest successful bid.

The number of auctioned allowances will decrease over time to meet the state’s decarbonization goals set for 2035 and 2050. Companies will be allowed to trade allowances among themselves.

The auctions are expected to raise $500 million to $1 billion a year, depending on who is calculating. Democrats and Republicans expect to decide in the upcoming session how to spend that money, according to Gov. Jay Inslee, Nguyen, Fitzgibbon, and Rep. Mary Dye of Pomerory, ranking Republican on the House Environment and Energy Committee.

In the upcoming session, Senate Republicans want to introduce legislation to suspend the cap-and-trade program if gas prices get too high for too long. Democratic leaders say this bill won’t stand a chance of getting out of committee. Senate Republicans also plan to introduce a bill to track the effects of the state’s new low-carbon fuel standard on gasoline prices. Nguyen said such tracking is already in the existing low-carbon fuel standards law.

Land Use Bill Revived

Climate bills related to land use planning, salmon and tree planting will also come into play this year.

The 2023 session will likely see the revival — and passage — of House Bill 1099, which would add climate considerations to city and county land use planning.

The bill, introduced last year by Rep. Davina Duerr (D), would have made this change to Washington’s Growth Management Act, which regulates long-range land use planning for Washington’s city and county governments. It would have required local governments to review and, if needed, revise their comprehensive plans and development regulations every eight years.

Duerr’s bill would have required climate change to be considered in land use and shoreline planning for the 10 largest of Washington’s 39 counties and in cities of 6,000 residents or larger. The 10 largest counties cover Puget Sound, Spokane, the Yakima River Valley and the Washington-side suburbs of Portland.

Last March, Senate and House Republicans used parliamentary maneuvering to kill the bill on the final day of the session. (See Sponsor Plans to Revive Stalled Wash. Land Use Bill.)

Inslee and Dye want to introduce legislation to plant large numbers of trees along Washington’s rivers and streams to provide shade for migrating salmon. Water temperatures exceeding the lower 70s seriously threaten the health of the fish. “This is a major, major threat,” Inslee said in an interview.

The concept of cooling streams with extra shade has been around for decades, but Inslee and Dye said the measure needs to be tackled with much greater volume than before. Both speculated that cap-and-trade money could be used for the effort.

Duerr has introduced a bill (HB 1078) to establish “tree banks,” designated area where trees would be planted to replace those cut down to develop properties.

Republican Plans

While the ranks of Washington’s Republican lawmakers will be slightly thinner this year after last November’s election contests, they still plan to push bills that would deviate from the Democrats’ policy goals.

Sen. Curtis King of Yakima, ranking Republican on the Senate Transportation Committee, has introduced a bill (SB 5092) to provide tax breaks to residents buying hybrid vehicles. Hybrids provide an affordable steppingstone for lower-income people who cannot afford electric vehicles in the next few years, he said.

However, Inslee and Fitzgibbon believe boosting hybrids is an inadequate step in the state’s push to switch to a predominately EV market. “Hybrid vehicles were a great solution for lowering emissions 20 years ago, but we need to be moving faster in reducing emissions and focus limited incentive dollars on truly clean vehicles,” Fitzgibbon said.

Inslee said the cheapest all-electric car — the Chevrolet Bolt — costs about $25,000, making such vehicles more affordable.

Republicans also want to introduce a bill regulating the recycling of wind turbine blades and parts from solar farms. Fitzgibbon said Democrats are open to recycling power industry materials but wondered why the GOP’s plans don’t include recycling parts from natural gas plants and hydroelectric dams. Both sides speculate that the disposal and recycling of batteries will surface in this session.

In the 2022 session, House Republicans introduced a bill (HB 1822) to allocate some cap-and-trade revenue to create an Office of Puget Sound Water Quality to provide help and supervision to municipal sewage treatment plants on the sound to trim amount of nitrogen-laden nutrients, which decrease the oxygen needed by fish. That bill never made it out of the House Environment and Energy Committee and Dye plans to revive it in 2023.

January 2, 2023

‘Monumental Progress’ for OSW in New York in 2022

Wind power development off the coast of the Northeast U.S. continued to advance in 2022.

Extensive progress outweighed setbacks that arose, as construction on the first projects began or continued and several additional gigawatts of offshore wind (OSW) inched through various stages of the planning and approval process.

On the other side of the ledger, a developer moved to cancel agreements it said were no longer viable for a 1,200-MW wind farm off the Massachusetts coast, although it said it remained interested in developing the project under other terms.

On the whole, particularly in New York, it was a “banner year” that saw “monumental progress,” said Fred Zalcman, director of the industry group New York Offshore Wind Alliance.

“Looking forward to 2023, New York needs to build on this fantastic progress by awarding new contracts, with associated economic development, that will allow New York to achieve its 9-GW target,” Zalcman said in a December news release.

He also flagged one of the chokepoints that faces New York’s leaders in their efforts to decarbonize the state: moving all those new kilowatts from generator to consumer.

“New York also needs to make some key and timely decisions on transmission investments to facilitate the significant levels of offshore wind energy that we will need beyond the 9 GW,” Zalcman said.

Here are some of the larger developments in 2022.

New York

Winning bids totaling a record $4.37 billion were submitted in a February auction of federal lease rights to six tracts totaling 488,000 acres in the New York Bight.

The 130-MW South Fork Wind became the state’s first and the nation’s second large-scale OSW project to begin construction.

The state in July opened its third OSW solicitation, this one for at least 2 GW installed capacity, on its way to a self-imposed target of 9 GW capacity by 2035.

New York laid the groundwork for the physical and human infrastructure — factories, ports and career training — needed to support all this activity and allocated $500 million in funding for it.

Nearly a year of negotiations over plans for the 924-MW Sunrise Wind resolved a dispute over its potential effect on fishers. (It is an issue that may arise elsewhere: the U.S. Bureau of Ocean Energy Management has warned of potentially significant impact on commercial and for-hire recreational fisheries from other OSW projects in the New York Bight.)

BOEM and the National Oceanic and Atmospheric Administration completed a draft strategy to protect the endangered North Atlantic right whale from OSW development efforts.

Massachusetts

In August, Massachusetts Gov. Charlie Baker signed into law “An Act Driving Clean Energy and Offshore Wind,” codifying the goal of 5.6 GW of OSW nameplate generation capacity in Massachusetts by mid-2027.

Work continued on the 800-MW Vineyard Wind, which in late 2021 became the first large-scale OSW project in the nation to start construction. 

The state in late December announced $180 million in funding to build up port infrastructure to support OSW projects.

Developers of the Commonwealth Wind and Mayflower Wind offshore projects said in October that the terms of the deals they had negotiated to sell the power from their planned wind farms were no longer tenable because of rising costs.

In December, Commonwealth moved to cancel those agreements but said it would rebid the 1.2-GW project if it was offered as part of a 2023 OSW solicitation by the state. (See Avangrid Seeks to Terminate Commonwealth Wind PPAs.) Mayflower Wind, which would provide 400 GW under the contracts in question, remained in development but the company would not comment on its plans.

Rhode Island

Rhode Island — home to the 30-MW Block Island Offshore Wind Farm, the first commercial OSW project in the U.S. — requested proposals for 600 to 1,000 MW of additional OSW.

Already in development is the 700-GW Revolution Wind, which is projected to go online in 2025 with 400 GW of power for Rhode Island and 300 GW for Connecticut.

Connecticut

In October, Avangrid pushed back by one year the target completion date of its 800-MW Park City Wind, which sits off the Massachusetts coast but will feed Connecticut’s grid. The developer said it hopes advances in technology in that year will allow it to extract more power from each turbine and improve the economics of the project. (Avangrid also pushed back Commonwealth Wind in Massachusetts for one year for the same reason.)

Maine

BOEM in August issued a Request for Interest in commercial OSW in the Gulf of Maine and received responses from five qualified developers.

Also in August, BOEM invited proposals for floating OSW turbine research in the Gulf of Maine.

New Jersey

In September, New Jersey kicked its OSW goal from 7.5 GW to 11 GW by 2040, the most of any state on the East Coast.

Three wind farms proposals totaling 3.7 GW are in some stage of review, and a port to support the projects is under construction in southwest New Jersey.

January 2, 2023October 25, 2023

CARB Eyes Another Busy Year for Climate Policy

The California Air Resources Board had a big year in 2022, adopting the Advanced Clean Cars II regulation, which bans the sale of most gas-powered cars starting in 2035.

It also approved a climate change scoping plan that sets a course for the state to reach carbon neutrality by 2045. (See Calif. Adopts Rule Banning Gas-powered Car Sales in 2035; CARB Approves Plan to Reach Net Zero by 2045.)

CARB will have another busy year in 2023.

The agency is expected to approve an Advanced Clean Fleets (ACF) regulation aimed at accelerating the transition to zero-emission medium and heavy-duty trucks. The regulation’s goal is to achieve a zero-emission truck and bus fleet in California “where feasible” by 2045 and much sooner for some vehicles such as last-mile delivery and drayage trucks.

The CARB board held a hearing in October on the proposed ACF regulation, which is expected to return for final approval in early 2023.

CARB is also re-examining its low-carbon fuel standard (LCFS) with an eye toward increasing the stringency of carbon-intensity targets for 2030. The regulation sets carbon intensity benchmarks for transportation fuels, which decrease over time. Fuels with a carbon intensity less than the benchmark generate credits that can be purchased by providers of fuels that have a carbon intensity above the benchmark.

The potential increased stringency of LCFS is important as CARB’s new scoping plan sets a target of reducing GHG emissions to 48% below 1990 levels by 2030. That exceeds a statutory goal of a 40% emissions reduction by 2030.

CARB held several workshops in 2022 to discuss potential changes to LCFS. Those discussions will continue in 2023.

Also in 2023, CARB will continue working on a strategy to achieve net-zero emissions for cement used within California by 2045. The strategy, which is due by July 1, is a requirement of Senate Bill 596 passed in 2021.

And last year’s SB 905 requires CARB to establish a program to evaluate the safety and viability of carbon capture, utilization and storage technologies. Work on the program will start this year.

CARB Executive Officer Steven Cliff is expected to outline the agency’s priorities for 2023 during the January board meeting.

Another issue CARB will tackle in the new year is how the Environmental Justice Advisory Committee can continue on an ongoing basis. The EJAC was convened in 2021 to work on the 2022 scoping plan. EJAC members represent communities most heavily impacted by air pollution, including low-income or minority populations.

In the past, the EJAC’s work ended with completion of the scoping plan. But CARB Chair Liane Randolph has committed to keeping the EJAC going so the panel can advise the agency on scoping plan implementation.

CARB staff have proposed an ongoing EJAC with 11 members that would meet twice quarterly. During development of the 2022 scoping plan, the EJAC had as many as 21 members and often met two days a month. CARB staff said it’s been tough keeping up with the work required for that schedule.

But during the committee’s Nov. 30 meeting, EJAC member John Kevin Jefferson said the group will have even more work to do as the scoping plan is implemented. He suggested that CARB assign more staff to work with the committee.

“The pace needs to actually increase as opposed to decrease,” Jefferson said. “There’s a lot of work to do.”

January 2, 2023June 14, 2023

SPP Makes Moves Out of the Southwest

SPP continues to make a misnomer out of its name. The Southwest Power Pool? Really?

In October, it added Canadian utility SaskPower as its first international member.

And this July, SPP’s board, state regulators and members will gather in St. Paul, Minn., for their quarterly meetings. After all, who wants to meet in Minnesota in January?

And of course, the grid operator continues to expand its beachhead in the Western Interconnection along several different fronts.

Focusing on the RTO’s stakeholder-driven culture as a counterweight to CAISO’s market buildout efforts, staff worked closely with potential Western stakeholders to finalize its Markets+ service offering. The document lays out the market’s governance structure and resource adequacy requirements that will, as SPP says, “ensure Western customers get the products and services they need at affordable rates they help control.” (See Governance, Resource Adequacy Key to SPP’s Markets+.)

“Without you at the table, we simply cannot develop the market the West wants: one that will serve Western needs with the governance that you value so much,” CEO Barbara Sugg told Western stakeholders in a holiday email.

The grid operator says Markets+ is a conceptual bundle of services that would centralize day-ahead and real-time unit commitment and dispatch, deploy hurdle-free transmission service across its footprint and reliably integrate renewable generation for utilities that aren’t yet ready to pursue full RTO membership.

Several Western organizations have already committed to funding the first development phase of Markets+ that establishes market rules and tariff language. SPP will engage through March with those utilities that have committed to funding Phase 1; staff have projected that will cost $9.7 million and take about 21 months.

Phase 2 will include the day-ahead market’s development. Based on SPP’s experience in building the Integrated Marketplace, staff has estimated the second phase will take three years and about $130 million to complete. Staff is assuming the market will be about a 50-GW system with up to 30 balancing authorities and 90 market participants.

Sugg said SPP has also seen a “growing interest” in full-scale RTO services. Seven participants in SPP’s Western Energy Imbalance Service (WEIS) market, which the grid operator has been administering on a contract basis since February 2021, have signed onto a plan to form a Western RTO — dubbed RTO West.

SPP’s legacy RTO footprint and its western market services | SPP

Western stakeholders are currently developing the RTO’s terms, with a review scheduled to wrap up by March. It would then take another two or three years to integrate those utilities into the system. The WEIS market will also welcome Xcel Energy-Colorado, among others, in April.

A Brattle Group study for the grid operator found that a Western RTO would produce approximately $49 million in savings annually for SPP’s current and new members. The Western utilities would receive $25 million a year in adjusted production cost savings and revenue from off-system sales, and SPP’s Eastern Interconnection members would benefit from $24 million in savings resulting from the expansion of the RTO’s market, transmission network and generation fleet.

SPP is also exploring a Markets+ transitional real-time balancing market, similar to the WEIS, that would launch in June 2024. A day-ahead balancing market would be developed at the same time and launch as soon as possible.

“Markets+ won’t exist in isolation,” Sugg said. “We certainly see opportunities to improve energy coordination within the East today, and we know California is a valuable trade partner in the West. Markets+ can optimize and improve the value of energy trading through carefully negotiated terms of coordination between peers across these seams.”

SPP will form a Markets+ seams committee early this year and will work closely with stakeholders to facilitate and advocate for seams coordination “that results in fair, equitable and value-added outcomes, Sugg said.

Already a NERC-certified reliability coordinator for 16 Western utilities, SPP will also provide program operator services for the Western Power Pool’s Western Resource Adequacy Program when it receives FERC approval. (See FERC IDs Deficiencies in Western RA Program.)

Meanwhile, in the East…

Sugg said SPP is well on its way to achieving many of its Aspire 2026 Strategic Plan initiatives, beyond expanding its service offerings in the West. It continues to improve and consolidate its transmission planning process, reduce the backlog in its interconnection queue, and define the grid of the future.

What the RTO was unable to do was find mutually beneficial interregional projects on its MISO seams. The grid operators’ staffs said in December they will not pursue any small projects that will relieve constrained flowgates. It was the fifth time the RTOs have come up empty after four fruitless joint studies last decade. (See MISO, SPP Unable to Find Smaller Joint Tx Projects.)

In the meantime, demand continues to grow. Staff said increased load assumptions could result in an almost $7 million over-recovery for the year. As it was, SPP set new records for summer and winter peak demand (53.2 GW on July 19 and 47.1 GW on Dec. 22). The highs were 4.2% and 7.9% increases over previous records.

Non-standard loads such as crypto miners, data centers, biofuel and alternative fuel manufacturers, and cannabis grow houses account for much of the growth. SPP said that, since June, it had received more than 7 GW of interconnection requests for the firm and non-firm load, some of which would be behind the meter.

Staff will begin the year attempting to secure approval of a mitigation strategy for load-responsible entities unable to meet the new 15% planning reserve margin (PRM). They could reduce the deficiency payment charge, extend the timeline to cure deficiencies or add mechanisms to assure capacity and make failure to meet the requirements “less costly or less punitive.”

The SPP board raised the PRM from 12% to 15%, effective Jan. 1. That left some members complaining they wouldn’t have enough time to meet the requirements. (See SPP Board, Regulators Side with Staff over Reserve Margin.)

January 2, 2023June 14, 2023

NM Rings in New Year with Reconfigured Utility Commission

New Mexico Gov. Michelle Lujan Grisham has appointed three members to the state’s revamped Public Regulation Commission, a panel that up until late December had five elected members.

The new PRC members are Gabriel Aguilera, Brian Moore and Patrick O’Connell. The appointments were effective Jan. 1.

The switch from a five-member elected PRC to a three-member appointed commission is the result of a change to the state constitution proposed by the legislature and ratified by voters in 2020.

The governor chose the new commissioners from a pool of nine candidates selected by a seven-member nominating committee.

Gabriel Aguilera | NIPCC

Aguilera had worked for FERC since 2007, most recently serving as senior policy adviser in the commission’s Office of Energy Market Regulation Western region. He was appointed to a four-year term.

Moore served in the state House of Representatives from 2001 to 2008 representing eastern New Mexico. He served on the state’s Renewable Energy Transmission Authority Board and the governor’s Economic Recovery Council. Moore, who is president and CEO of Ranch Market supermarket in Clayton, was appointed to a two-year term.

O’Connell was the Clean Energy Program interim director at Western Resource Advocates. He worked for Public Service Company of New Mexico, New Mexico Gas Co. and the Sangre de Cristo Water Co. He was appointed to a six-year term.

Brian Moore | New Mexico Legislature

“These appointees are experienced professionals who have the skills needed to oversee an energy transition that is affordable, effective and equitable for every New Mexico community,” Lujan Grisham said in announcing the appointments on Dec. 30.

The PRC Nominating Committee accepted applications for the PRC positions through the end of September. The committee chose 15 applicants to interview. During a Dec. 2 meeting, the committee voted to forward nine of those names to the governor for consideration.

In addition to Aguilera, Moore and O’Connell, the nominating committee’s list included James Ellison, principal grid analyst at Sandia National Laboratories; Carolyn Glick, a former PRC hearing examiner; Joseph Little, the former general counsel to the Pueblo of Zia; Art O’Donnell, a former senior analyst with the CPUC; law professor Amy Stein; and Cholla Koury, chief deputy in the New Mexico Attorney General’s Office.

Since its formation in 1996, the PRC consisted of five elected members representing different regions of the state. With the change to a three-member appointed PRC, Native American advocacy groups say indigenous people are losing their voice on the PRC.

Pat OConnell (Western Resource Advocates) Content.jpg

Patrick O’Connell | Western Resource Advocates

“For our voice to be eliminated in this way is unjust,” Krystal Curley, executive director of Indigenous Lifeways, told the nominating committee on Dec. 2.

Indigenous Lifeways and two other groups — Three Sisters Collective and the New Mexico Social Justice Equity Institute — filed a petition with the New Mexico Supreme Court in September to overturn the change, saying the ballot language was misleading and voters weren’t aware they would lose the ability to elect commissioners. But after hearing arguments in the case, the court rejected the petition in November.

In announcing the PRC appointments last week, Lujan Grisham acknowledged concerns about a potential lack of Native American representation on the commission.

To address those concerns, the governor signed an executive order on Dec. 30 creating a Tribal Advisory Council to advise the PRC. Lujan Grisham will appoint the advisory council’s first set of four members by Jan. 30.

“It’s extremely important that we ensure tribal voices are heard on issues before the PRC, regardless of who is appointed to the commission now and into the future,” the governor said.

December 22, 2022

FERC Rejects Sale of AEP’s Kentucky Operations to Liberty

FERC last week rejected the sale of American Electric Power’s (NASDAQ:AEP) Kentucky operations to Algonquin Power & Utilities (NYSE:AQN) subsidiary Liberty Utilities, ruling that the companies failed to prove that the transaction would not adversely affect rates (EC22-26).

Under the agreement filed with FERC a year ago, and amended in October, AEP would sell Kentucky Power — a vertically integrated utility with 1,075 MW of generation — and Kentucky Transco to Liberty for $2.646 billion. (See AEP Accepts Lower Price for Kentucky Operations Sale.)

But the commission found that the companies’ commitment to hold customers harmless for all “transaction-related costs” for five years was not sufficient to demonstrate that the sale would not have an adverse impact. The application notes that the pledge is not a rate freeze and that Liberty would be able to seek rate changes to reflect their full costs of service.

The commission said that an “increase in rates that results from a transaction is not the equivalent of a transaction-related cost” and suggested that the applicants could have included a projection of the impact to rates following the sale.

“Applicants’ representations do not provide complete information upon which to evaluate the effect of the proposed transaction on rates,” the commission said. “To support their position, applicants could have, for example, included a comparison of rates currently in effect to a projection of rates once the proposed transaction is consummated.”

Both the Kentucky Public Service Commission and a group consisting of American Municipal Power, Blue Ridge Power Agency and Wabash Valley Power Association filed protests arguing that the application did not contain enough information to show that ratepayers would not be negatively impacted by the transaction.

The PSC itself gave its approval of the transaction in May, though it stipulated numerous conditions to protect consumers. (See PSC OKs Sale of AEP’s Kentucky Operations to Liberty Utilities.)

The cooperative group argued that Liberty should be required to maintain the companies’ current return on equity of 9.85% and the maximum permitted equity component of capital structure of 55%. It also pushed for Liberty to be required to show customer benefits to justify any rate increases during the five-year hold-harmless period and for that pledge to include any cost of debt.

“Applicants further state that, to the extent such costs change as a result of the change of ownership, those changes will not impact customers through the end of 2022 and will be addressed in 2023 and in the future through the formula rate projection and true-up process in the normal course,” FERC said.

The commission dismissed the application without prejudice, meaning the companies are free to file a new application “that provides adequate information” on its effects on rates.

“If the effect of the proposed transaction on rates is adverse, applicants should propose adequate ratepayer protection or mitigation to address that adverse effect, or otherwise demonstrate specific benefits due to the proposed transaction that offset such effect,” FERC said.

Danly Concurs, but with Criticism of Commission

Though he concurred with the decision, Commissioner James Danly criticized the time FERC took to rule on the deal and for not requesting additional data or changes to mitigate any rate effects. The companies initially filed the application for the transaction in December 2021; on June 3 they requested that the commission authorize the transaction no later than June 21 to allow the deal to close on schedule in mid-2022.

“Instead, having waited six months to reach the same conclusion we had come to before — that we did not have enough information — we have merely impeded the actions that the applicants could have taken to move ahead with the proposed transaction, such as filing a new application with needed information, perhaps after consultation with commission staff,” he said.

Had the commission sought additional information, Danly said, it may have been possible to receive a satisfactory rate commitment within a few months. By requiring the companies to file a new application, the commission made it difficult for companies and investors to make business decisions, he said.

“It is nearly impossible to rationally allocate capital and conduct business responsibly when it is unclear who will own that business or when the decision regarding the disposition of jurisdictional assets will be made. When we delay these decisions, employees and leadership of both entities live under a cloud of uncertainty. Shareholders are unable to properly determine the value of their shares,” he said.

Phillips also Concurs

Commissioner Willie Phillips also issued a concurrence, saying that he would have preferred a conditional approval of the application. He noted the commission has rarely denied similar applications and has instead granted conditional authorization with market power mitigation measures.

“I recognize those cases may be distinguishable in certain respects but would have preferred to have taken that approach here by providing joint applicants with clear guidance on possible mitigation strategies such as a hold-harmless commitment on rates, not just transaction costs, or a rate freeze that assures the commission that transmission customers will not feel adverse effects from this transaction,” he wrote.

December 22, 2022December 14, 2023

Supporters See Strong Potential in SW Hydrogen Hub

Energy leaders in Arizona and Nevada have partnered on a clean hydrogen hub proposal, with advocates saying the states’ proximity to California, their copper and lithium mining, and the presence of salt caverns make them a good candidate for federal funding.

The Center for an Arizona Carbon-Neutral Economy at Arizona State University is collaborating with partners including the Nevada Governor’s Office of Energy and the Navajo Nation on the hub, called the Southwest Clean Hydrogen Innovation Network (SHINe).

SHINe submitted a concept paper to the U.S. Department of Energy in November seeking $1 billion in federal funding through the agency’s $7 billion clean hydrogen hub program, according to Ellen Stechel, executive director of the Center for an Arizona Carbon-Neutral Economy. DOE is planning to fund six to 10 hydrogen hubs.

Applicants now expect to hear any day whether the DOE will encourage them to send in full proposals, which will be due on April 7.

Abundant Sunshine

Stechel said that with the abundant sunshine in the two states, green hydrogen — made from electrolysis of water using renewable energy — could account for much of the hydrogen produced in the hub.

Arizona is also home to the Palo Verde Generating Station, the nation’s largest nuclear energy facility, raising the possibility of producing so-called pink hydrogen. Arizona Public Service (APS) and Salt River Project (SRP) are part owners of Palo Verde, and both are participants in SHINe.

Another feature of Arizona — its salt caverns — could contribute to the hub by providing space for large-scale hydrogen storage, Stechel said in an interview with NetZero Insider.

SHINe would help meet demand for hydrogen in California, a neighbor to both states.

One partner in the SHINe hub is Air Liquide, which in May opened a $250 million liquid hydrogen production and logistics infrastructure facility in North Las Vegas. The plant is the company’s largest liquid hydrogen production site in the world.

“The facility was built to meet the renewable hydrogen demands of the burgeoning California mobility market with the capacity to fuel more than 40,000 fuel cell vehicles, thereby eliminating concerns around fuel supply reliability and allowing this market to develop more quickly,” the company said in a fact sheet.

The hub could also meet growing demand for hydrogen in Arizona and Nevada. For example, the Regional Transportation Commission of Southern Nevada, a SHINe partner, is acquiring hydrogen fuel cell buses as part of its transition to a zero-emission fleet.

Arizona and Nevada play a role in transportation electrification through their lithium and copper mines. Demand is surging for both metals, which are used in electric vehicles. Arizona is the top copper-producing state in the U.S.

Stechel said a hydrogen hub has the potential to decarbonize mining operations in the states.

Industry, Utility Partners

SHINe includes more than 40 members. On the utility side, Tucson Electric Power and Southwest Gas are participants in addition to APS and SRP.

In addition to Arizona State University, academic partners are Northern Arizona University, the University of Arizona and the University of Nevada, Las Vegas.

Industry partners include Phoenix-based Nikola, which designs and manufactures battery-electric and hydrogen-fueled vehicles as well as hydrogen station infrastructure. The company announced in August three Southern California locations for its hydrogen-fueling stations, including a site serving the Port of Long Beach.

“California is a launch market for Nikola, and these stations will support key customers and advance the state’s efforts to decarbonize the transport sector,” the company said in a release.

In Nevada, the Governor’s Office of Energy was “happy to support the initiative,” GOE Director David Bobzien said. More details of Nevada’s involvement in SHINe will be worked out under the administration of incoming governor Joe Lombardo, said Bobzien, who is resigning from GOE effective Jan. 2.

“Since the passage of the Infrastructure Investment and Jobs Act, hydrogen has been an important area of interest, especially considering Air Liquide’s investments in southern Nevada and exploration of hydrogen applications in medium- and heavy-duty clean transportation and long-term storage benefitting the grid,” Bobzien said in a statement provided to NetZero Insider.

December 22, 2022

NYISO Management Committee Briefs: Dec. 21, 2022

Abbas to Join Talen Board

NYISO CEO Rich Dewey announced to the Management Committee on Wednesday that Director Gizman Abbas had accepted a position on Talen Energy’s board of directors.

Dewey said NYISO has determined that the appointment “does not present a conflict” with FERC’s rules and the ISO’s own Code of Conduct, as Talen no longer operates, nor owns any assets, in New York. But, he said, the ISO would “continue to watch and monitor the situation,” and revisit that determination should Talen move back into New York and “come up with a cure.”

Mark Reeder, representing the Alliance for Clean Energy New York, asked whether Talen had any interests in NYISO’s neighbors and if that was considered in the ISO’s determination.

The company does have interests in PJM and ISO-NE, owning several generators in Pennsylvania, New Jersey, Maryland and Massachusetts. Dewey said “it was considered, and we felt [under] a strict interpretation of the rules, it did not present a conflict.”

Capacity Accreditation

The MC voted to recommend that the Board of Directors approve proposed tariff modifications that would implement a new capacity accreditation process and market design.

Having been approved by the Business Issues Committee last week, several stakeholders again voiced their reservations about approving measures that they believed were either not fully understood or would be applied to resources unequally. (See NYISO Capacity Accreditation Implementation Worries Stakeholders.)

Michael DeSocio, director of market design at NYISO, said the ISO “remains committed” to doing the work required for capacity accreditation implementation and “acknowledges the need” to tackle portions of the project that were raised by stakeholders. DeSocio also assured the committee that these commitments would be reflected in the meeting’s minutes.

Hybrid Storage Resources

The MC voted to recommend that the board approve NYISO’s proposed tariff revisions that would integrate aggregated HSRs — multiple generators co-located with energy storage behind a single interconnection point — into the ISO’s markets.

The revisions were also approved by the BIC last week, and NYISO anticipates filing the changes with FERC in the third quarter of 2023. (See “Aggregated Hybrid Storage,” NYISO Capacity Accreditation Implementation Worries Stakeholders.)

Julia Popova, NRG energy manager of regulatory affairs and vice chair of the committee, asked why the revisions were being filed so late next year.

NYISO officials answered that they are targeting the third quarter because there are other projects that need to be implemented first, such as internal controllable lines. They also said the HSR construct would not be implemented until 2025 anyway, so there is no rush to get it to FERC.

CAC Scoping Plan

NYISO agreed to brief stakeholders on the New York Climate Action Council’s recently approved scoping plan and how it would impact the ISO’s work. (See related story, New York Climate Scoping Plan OK’d.)

Executive Vice President Emilie Nelson said NYISO is “looking through [the plan] carefully and is very, very interested in working with all stakeholders and state agencies going forward.” The ISO also “appreciates the acknowledgement within the plan that there are challenges ahead of us that we need to work together to solve.”

Reeder requested a “small,” formal presentation from NYISO about aspects of the plan that would affect its markets, though he acknowledged that the plan is just a framework that will take “at least multiple years” of legislation and agency rulemakings to implement.

December 22, 2022April 11, 2024

ERCOT Board of Directors Briefs: Dec. 19-20, 2022

Members, TAC Stripped of Responsibilities for Policy Development

ERCOT’s Board of Directors on Tuesday stripped away the right of corporate members to vote on future changes to the grid operator’s bylaws, rejecting an alternative stakeholder recommendation in the process.

The directors approved bylaw amendments, drafted by staff at the board’s direction, that remove ERCOT’s corporate members’ ability to vote “on any matter submitted to the general membership.” The amendment does allow members to comment on any such proposals and to propose amendments themselves.

The bylaw revisions take away the Technical Advisory Committee’s ability to recommend policy and procedural changes to the board. It leaves that top stakeholder group with doing little more than managing the process for changing market rules and document guides.

Stakeholders have expressed their opposition to the change since the draft amendments became public late this summer. The revisions are designed to align ERCOT’s governance with legislation, passed in the wake of the deadly 2021 winter storm, that created an independent board and removed market representatives from participating. (See ERCOT Stakeholders Wait on Bylaw Amendment Changes.)

Chris Hendrix 2022-12-20 (RTO Inisder LLC) FI.jpg

“There’s no real avenue to meet with the board,” Demand Control 2’s Chris Hendrix told RTO Insider. “It makes it more like a PJM model or an ISO-NE model, where you have no access to the board.”

Hendrix represented the membership and six of the seven market segments (investor-owned utilities were not involved) in offering up an alternative recommendation that agreed with much of the bylaw revisions but carved out three exceptions: retaining members’ voting rights, removing staff’s language that gives the board authority to amend TAC’s procedures without a vote of its representatives and removing language that allows the directors to disband TAC.

“Keep corporate members voting because it is a corporate membership,” he said. “It’s an incentive. We pay to be a member, and that comes along with voting rights.”

Several directors pointed to revised language giving members a 21-day window to comment on any proposed changes and noted that TAC can’t be disbanded without the Public Utility Commission’s direction.

Hendrix said the changes allow the board to set TAC’s policies and procedures, which could lead to extreme measures such as meeting once a year or eventual disbandment. He said that its only “the good word of the PUC” that prevents drastic changes.

The commission in November issued a statement that helped set the stage for this week’s discussion. The commissioners agreed that ERCOT’s board is “empowered to amend its bylaws without obtaining the affirmative vote of the corporate members. It is necessary for ERCOT to amend its bylaws such that the ERCOT board of directors has the sole authority to change the bylaws, subject only to the approval of the commission.”

The statement also called for preserving market participant input in developing market functions by amending the bylaws such that the board “cannot eliminate [TAC] without specific direction from the commission.” (See “PUC Sides with ERCOT Board,” Proposed ERCOT Market Redesigns ‘Capacity-ish’ to Some.)

“I believe the proposed bylaws changes represent something that is not dissimilar to the organizational structures that we see in the rest of the country,” PUC member Will McAdams said before the commission’s separate vote to approve the bylaw changes. “Ultimately, the commission has an appellate jurisdiction to approve all policies, and there’s an obligation on the part of stakeholders, the board and the commission under this contract … to collaborate and work through operational issues as they become apparent so that we can provide the best outcome for the public in Texas.”

Hendrix, who admitted he faced an uphill battle, said the revisions will only help ERCOT’s larger members who can afford to lobby legislators and regulators and might lead some market participants to forego memberships.

ERCOT held a 20-minute annual membership meeting following the board’s executive session, with only a handful of members present. ERCOT CEO Pablo Vegas promised a return to an in-person annual meeting next year and “better opportunities to connect with fellow corporate members, with the ERCOT board of directors … with staff, with commissioners and with other invited guests.”

“I think it’s an opportunity to really connect on the issues that are important to the industry and have an opportunity to get to know each other through that and have a higher-value discussion,” he said.

Board Chair Paul Foster also expressed desire for a “stronger engagement opportunity” next year and said the bylaw amendments represented “another milestone” in ERCOT’s changing governance structure.

“Each board director has now had time over the past year to see the TAC membership and the stakeholders in action and the role they provide in the policy development of the rules that helped run a reliable grid and a fair efficient market,” he said.

Grid Prepared for Winter Weather

Vegas reassured directors and stakeholders that the grid operator continues to expect adequate supplies and reserves in advance of sub-freezing temperatures forecast for the Christmas weekend. He said staff expects to have more than enough generation to handle a projected peak of nearly 68 GW with nearly 90 GW of capacity online. Wind and solar account for 20-22 GW of the available capacity.

During a press conference with Gov. Greg Abbott Wednesday morning, Vegas reduced the online capacity estimate to 85 GW, with wind and solar accounting for 12 GW. He was joined by PUC Chair Peter Lake, who said the ERCOT grid is “ready and reliable.”

ERCOT on Wednesday elevated a previously issued advisory for the extreme cold weather to a watch, effective Thursday morning through Monday, Dec. 26.

“Things are looking good to get through the weekend,” Vegas said.

Chris Coleman 2022-12-20 (RTO Inisder LLC) FI.jpg

Chris Coleman, ERCOT’s lead meteorologist, said the cold front, part of a powerful winter storm that has settled over the Midwest, will not be as severe as the deadly 2021 winter storm that almost brought down the ERCOT grid.

“We’re several degrees warmer than that, and we will also not have the precipitation associated with it,” he said.

North Texas and the Panhandle will likely see snow, Coleman said. He predicted low temperatures of about 12 degrees F in Dallas and 17 degrees in Austin Friday morning. Freezing temperatures could extend as far as the Rio Grande Valley before conditions begin returning to normal during the weekend.

“We could see 70 degrees [next week], so there’s something encouraging to look forward to,” Coleman said.

Coleman is sticking by his winter outlook, which predicts that this winter will not be as warm as last year’s, but not as cold as 2020/21. This is the third straight winter with the La Niña system in place and will deepen Texas’ drought conditions. Coleman said 52% of the state has drought concerns, up from 46% last year.

“I think the drought will remain in place and potentially expand and worsen here over the next few months,” he said. “I don’t think we’re going to get through this winter, saying, ‘Boy, we had a lot of fun. It was just never warm.’ It’ll likely turn around here, so I’m not closing the door beyond this week on more cold opportunities.”

TAC Membership Set for 2023

A cast of familiar faces will be back for TAC next year following the board’s approval of the committee’s 2023 representatives.

The Office of Public Utility Counsel’s Nabaraj Pokharel, CenterPoint Energy’s David Mercado and Garland Power and Light’s Russell Franklin are the only new additions to the 30-person stakeholder group.

Current TAC Chair Clif Lange, with South Texas Electric Cooperative, has offered to again lead the group next year. Members will vote on leadership during their Jan. 24 meeting.

ERCOT Gets 1st Adjunct Member

The directors approved an adjunct membership for Pine Gate Renewables, a utility-scale solar and storage developer headquartered in Asheville, N.C., with five projects in its Texas pipeline. ERCOT staff said the company does not currently meet any segment requirements but will align with the independent power producers in the stakeholder process.

In other actions, the board approved:

- - Robert Black’s hire as vice president of public affairs following a short stint with AEP Texas and a 30-year political career on the Republican side of the aisle;
  - ERCOT’s 2023 methodologies for determining minimum ancillary service requirements, previously endorsed by TAC;
  - the Finance and Audit Committee’s acceptance of a system and organization control audit of ERCOT’s market settlements operations that found no reportable exceptions; and
  - the Reliability and Markets Committee’s charter, outlining its responsibility to review the grid operator’s core functions and disbanding the Credit Working Group. TAC will add the credit reporting functions to its structure.

Board Approves 10 Changes

The board approved a consent agenda that included six nodal protocol revision requests (NPRR), single changes to the Nodal Operating Guide (NOGRR), other binding documents (OBDRR) and the Resource Registration Glossary (RRGRR), and a system change request (SCR):

- - NPRR1128: Sets an ancillary service offer floor 1 cent/MW lower for fast frequency response (FFR) than for other RRS categories to allow FFR procurement up to the current limit, without proration with other RRS categories.
  - NPRR1132: Specifies that during local cold weather conditions, each qualified scheduling entity (QSE) must update its generation resources’ and energy storage resources’ current operating plans, real-time telemetry, and outage and derate reporting to reflect any limitations. It also requires each resource entity to provide resource-specific cold weather minimum temperature limits, hot weather maximum temperature limits, and alternate fuel capability information in its submitted resource registration data and update this information as necessary.
  - NPRR1138: Requires each resource entity to ensure the reactive capability curve for any intermittent renewable resource accurately reflects its reactive capability when it is not providing real power or is operating at lower levels of real power output.
  - NPRR1148: Resolves protocol gaps found during emergency contingency reserve service’s creation of its system change requirements.
  - NPRR1152: Removes the protocol requirements to submit emergency operations plans (EOPs), weatherization plans, and declarations of summer/winter weather preparedness; revises procedures for submitting declarations of natural gas pipeline coordination with natural gas generation resources; revises the list of items considered protected information to remove references to weatherization plans and add protections for information relating to weatherization activities; and revises the list of ERCOT critical energy infrastructure information to clarify language concerning EOPs and add protections for information relating to weatherization activities.
  - NPRR1154: Updates language to allow for a qualified alternate resource to be considered in calculating the availability reduction factor for the firm fuel supply service (FFSS) resource and provides a new settlement billing determinant providing the FFSS award amount per QSE per FFSS resource by hour.
  - NOGRR226: Adds provisions for transmission operator “anti-stall” automatic firm load shedding at 59.5 Hz to mitigate the risk of a total systemwide blackout.
  - OBDRR043: Aligns the operating reserve demand curve’s methodology with NPRR1148’s revisions, approved in August, in calculating the real-time reserve price adder.
  - RRGRR032: Adds data required to be shared with ERCOT as the reliability coordinator, balancing authority and transmission operator in considering cold weather limitations in its operational planning analysis, real-time monitoring, real-time assessments, and other analysis functions. The grid operator also requires this information for hot weather limitations and making this a requirement for distributed generation resources and distributed energy storage resources.
  - SCR821: Allows transmission and distribution service providers to set the voltage set point target information provided to distribution generation or distribution energy storage resources.