Page 359 – RTO Insider

January 3, 2023

Major Changes in 2022 Continue to Shape PJM Outlook in 2023

The close of 2022 finds PJM in a state of flux, with recent FERC orders and pending dockets carrying significant changes to the RTO’s expanding interconnection queue and the structure of its capacity markets, as well as ongoing stakeholder discussions on how to account for the capacity from intermittent resources. Many of those discussions that have culminated in solutions will begin their implementation in the new year, while others still in deliberations aim to wrap up in the first few months of 2023.

Here’s a review of some of the major stories of 2022 and ongoing discussions continuing into 2023.

Finalization of Capacity Auction Pushed into 2023

The first order of business in 2023 will be a review of the “indicative” 2024/25 capacity auction results on Tuesday, following a concern that the DPL South locational deliverability area (LDA), which is centered around the Delmarva Peninsula, could experience artificially inflated prices. (See Capacity Auction ‘Mismatch’ Roils PJM Stakeholders.)

During the Dec. 21 Members Committee meeting, Senior Vice President of Market Services Stu Bresler said the design of the reliability requirement for each LDA can create a situation where large facilities or intermittent generators cause the requirement to increase as more resources are brought online because of the need to account for when those resources are offline. When those resources are included in the resource modeling and lead to an elevated reliability requirement, but do not ultimately enter into the auction, it can create the appearance of a shortage that doesn’t exist.

PJM submitted concurrent Federal Power Act Section 205 and 206 filings with FERC on Dec. 23 seeking that the auction results in DPL South be found unjust and unreasonable and to allow the RTO to adjust the reliability requirement for the LDA “based on the actual supply of resources that submitted offers into the auction” (ER23-729, EL23-19).

The Section 206 filing argues that this would effectively function as an additional factor in the evaluation of offers into the market before the results are finalized.

“Absent the ability to include this additional factor in the optimization algorithm, PJM would be forced to utilize a materially inaccurate locational deliverability area reliability requirement that does not reflect the actual capacity needs of the particular LDA in question and would result in an unjust and unreasonable outcome,” the RTO said.

Several stakeholders raised concerns that the move would establish a precedent of market changes being implemented in the middle of auctions. Those reservations extended to PJM’s determination to publish the DPL South results Tuesday, which could hamstring the commission’s ability to allow market participants to alter their offers to reflect any rule changes.

Bresler said it is not a step being taken lightly, but the scale of the impact to DPL South warrants immediate measures while concrete long-term solutions are sought. In the filings before FERC, PJM said the clearing price for the LDA would be more than four times higher if the proposed changes are not made.

“More particularly, based on preliminary auction data, PJM estimates that as a result of this confluence of events in this small LDA, should PJM complete the auction and award capacity commitments, the clearing price for the DPL-S LDA (and the revenues received by capacity market sellers in this small LDA) would be more than four times what the clearing price should be if the planned generation capacity resources that did not offer in the auction are excluded from the locational deliverability area reliability requirement given that they did not offer into the BRA,” PJM told FERC.

The opening of the auction had already been delayed from August to November as part of a FERC-approved adjustment to the capacity auction timeline through the end of 2023 to allow PJM additional time to implement a revised forward-looking energy and ancillary services (E&AS) offset. The commission reversed its approval of the RTO’s forward-looking E&AS offset in December 2021 and granted the delayed timeline on Feb. 23, pushing the January 2022 auction to June. (See FERC Approves PJM Capacity Auction Date Changes.)

The 2023 auctions were postponed from February to June and from August to November. The schedule is set to return to normal with the 2027/28 BRA, in May 2024.

Capacity Prices Fall for 2023/24

The 2023/24 capacity auction, held in June, saw prices fall by nearly one-half relative to the previous auction, with 144,871 MW of capacity sold for $2.2 billion for the delivery year starting in June 2023. The 2022/23 delivery year saw a total capacity bill of around $4 billion. (See PJM Capacity Prices Crater.)

Several market changes likely impacted prices, including a decreased unit-specific market seller offer cap (MSOC), the use of a historical E&AS revenue offset, the introduction of the effective load-carrying capability (ELCC) methodology for measuring intermittent resource capacity and the near elimination of the minimum offer price rule.

The Independent Market Monitor found that the auction results were competitive, largely because of the new MSOC. (See Monitor Finds PJM’s 2023/24 Base Residual Auction Competitive.)

Accreditation of Intermittent Resources Remains Divisive

Stakeholders are also pushing forward with an effort to have a new accreditation methodology for ELCC resources in place for the 2025/26 BRA in June. (See PJM Stakeholders Review Proposals on CIRs for ELCC Resources.)

The often contentious issue has been discussed in more than 25 meetings since a problem statement was adopted in early 2021, a referral to the FERC Enforcement hotline and a complaint to the commission filed by economist Roy Shanker on Nov. 30. At issue is whether PJM has been in violation of its tariff by improperly permitting energy above renewable resources’ capacity interconnection rights (CIRs) to be entered into the Reliability Pricing Model (RPM) auctions as capacity.

In his complaint, Shanker alleged that the practice results in diminished reliability; load overpaying for “phantom capacity” that does not meet reliability standards; artificial reduction of capacity prices for other resources; and inefficient economic decisions from market participants acting on potentially inaccurate information. Because the resources already have established interconnection service agreements (ISAs) and defined CIRs, the complaint states that an immediate solution can be implemented by capping capacity offers at the rates determined in those agreements with each resource (EL23-13).

The commission approved a PJM request for an extension from Dec. 20 to Jan. 10 to provide more time for its response to the complaint.

At the start of the year, the PJM Power Providers (P3) sent a letter to the PJM Board of Managers arguing that by allowing resources to acquire capacity obligations greater than their demonstrated deliverability, the RTO has “materially destabilized the market” and is not upholding its tariff. The board responded with a letter to stakeholders saying that it believes the accreditation of intermittent resources has been appropriate and compliant with the tariff.

The stakeholder discussions on a long-term solution has resulted in 11 packages of changes being offered as potential solutions, of which six remain under consideration by the Planning Committee. Though they agree on the ultimate methodology for accrediting intermittent resources, the packages vary widely on where to cap capacity offers for resources that already hold an ISA. The transitionary measures range from granting ELCC resources higher CIRs and having load pay for the transmission upgrades to capping their current CIR rating and requiring the resource to re-enter the interconnection queue to request a higher accreditation.

The PC is set to consider endorsement of a package on Jan. 10, while the Markets and Reliability Committee and MC are set to vote on Jan. 25. The proposals would also require approval from the board, which is set to take up the issue on Feb. 1. The solutions all look to be implemented for the 2025/26 BRA, but they differ in whether that is a target or mandatory.

Interconnection Queue Overhaul Approved

Following years of a growing backlog in its interconnection queue, FERC on Nov. 29 approved a proposal from PJM to overhaul how the RTO studies network upgrades for new projects. According to PJM, the number of new service requests it received tripled from 2019 through 2022 to more than 2,700 projects pending in the queue as of May 10 (ER22-2110).

The new system aims to reduce completion times by clustering projects together both for studying the upgrades required and allocating costs, as well as by discouraging speculative project submissions by requiring evidence of site control and progressively scaling readiness deposits throughout the process. (See FERC Approves PJM Plan to Speed Interconnection Queue.)

Once again the transitionary provisions were the source of much of the debate around the changes. Under the new system, projects submitted between April 2018 and September 2021 with a price tag above $5 million will be studied under two sequential transitionary cycles, while less expensive projects will be placed in an expedited “fast-track” queue.

Concerns raised by protesters questioned whether the measures would be enough to weed out proposals seeking to offload the work of testing a project’s viability onto PJM staff and whether site control requirements could allow viable projects to be forced out of the queue.

During the Organization of PJM States Inc.’s (OPSI) annual meeting on Oct. 18, PJM Vice President of Planning Kenneth Seiler said many of the smaller projects already in the interconnection queue could have their studies complete within six months and that the fast-track could be completed within two years after its approval.

Division over Design of Capacity Market

As FERC continues to weigh whether to approve PJM’s proposed changes to the RPM, generation owners are seizing upon comments made by PJM CEO Manu Asthana — in which he expressed concern about the pace of new generator installations — to argue that the capacity market should be structured to procure additional capacity. (See PJM MRC Briefs: Oct. 24, 2022.)

At the RTO’s annual meeting on Oct. 24, Asthana said about 40 MW of generation is expected to retire by 2030 as construction of new resources lags behind expectations and load continues to grow.

“We have time, but we don’t have time to waste,” he said. “We need to take action to ensure we retain an adequate supply of dispatchable generation through the [clean energy] transition.”

Protests against PJM’s proposed variable resource requirement (VRR) demand curve have pointed to Asthana’s statement as evidence that the RPM should be designed to incentivize the retention and development of all types of capacity (ER22-2984).

The Quadrennial Review filing proposed changing the reference resource to a combined cycle generator, revising the calculation of the gross cost of new entry (CONE) and changing how it is adjusted in years between reviews, steepening the VRR curve and shifting from a historical E&AS offset calculation to a forward-looking offset.

P3 protested that the changes are not transparent and would disincentivize the sort of generation Asthana said is needed over the coming decade. (See PJM Defends Quadrennial Review Parameters from Generator Protests.)

“To P3, this sounds like PJM is indeed on the cusp of a reliability crisis and the impact of the instant filing will coincide directly with the predicted reliability challenges in PJM,” the group said.

In response to previous P3 protests, several environmental and public advocacy groups — jointly filing as the Public Interest Entities — said the claims are unfounded and noted that PJM remains well above its “conservative” reliability standards.

“Rather than a market ‘on life support,’ PJM’s capacity market remains robust, procuring — indeed over-procuring — the resources necessary to maintain reliability,” they said.

January 3, 2023February 25, 2024

MISO Concludes Turbulent 2022, Commences Busy 2023

MISO made several maneuvers in 2022 to position itself for a majority-renewable portfolio while attempting to take the sting out of an escalating capacity deficit in its entire Midwest territory.

After years of warnings from MISO leadership, the portfolio transition is in full swing in the footprint.

And MISO’s 2023 docket includes planning the next round of long-range transmission projects, navigating expected capacity shortfalls, attempting a sloped demand curve in a newly revamped seasonal capacity auction and managing an unprecedented number of new renewable resources queuing up for interconnection.

“There are going to be more things happening in the next five years than in the past 20 years,” CEO John Bear began a Nov. 28 executive update.

Bear thanked stakeholders for their assistance on MISO efforts. He said he understood the magnitude of work “takes a toll” on them, but that they and the RTO accomplished a lot over 2022 “in really trying times.”

“The urgency of course is always high,” Bear said, noting that decarbonization goals are always intensifying.

Board Chair Todd Raba (left) and CEO John Bear at December Board Week | © RTO Insider LLC

MISO’s most attention-grabbing headline of 2022 was the Midwest region’s 1.2-GW capacity shortage exposed in the RTO’s 2022/23 Planning Resource Auction. The shortfall triggered a $236.66/MW-day cost of new entry (CONE) clearing price for the Midwestern subregion. (See MISO’s 2022/23 Capacity Auction Lays Bare Shortfalls in Midwest.) MISO had said the capacity deficit might force it to order temporary, controlled load sheds, and it predicted insufficient firm resources to handle summer peak forecasts under typical demand.

“We have a resource adequacy problem. We have challenges to delivering energy when we need it,” Bear said simply during the Board of Directors’ meeting Dec. 8.

However, MISO cleared 2022 without dipping into its most serious maximum generation procedures, though it issued summertime and early fall alerts. (See Monitor Critiques MISO’s Commitment Usage During Summer.)

With a week left in 2022, MISO managed to avoid an emergency in its South region during a fierce cold blast Dec. 23. The late December winter storm also forced MISO Midwest into conservative operations overnight into Dec. 24.

At the time, MISO said its South region was facing higher-than-forecasted load and significant generation outages. MISO South remained in conservative operations mode and under a cold weather alert until Dec. 26.

Queue Bursting at the Seams

As it rounded out September, MISO received a record-setting 171 GW of proposed renewable generation and storage projects across 956 interconnection requests. Those requests could bring the total interconnection queue to the brink of 300 GW, triple that of just two years ago. Five years ago, a nearly 300-GW queue was unthinkable. In 2017, MISO planners said processing the then-60-GW queue was a tall ask.

MISO has said it’s up to the task and — what’s more — said it will stick to its pared-down 375-day study schedule for the queue’s definitive planning phase (DPP). The RTO got FERC permission in February to swap the new timeline for its previous 500-day DPP.

However, MISO has pushed back the DPP start of its record-setting 2022 cycle of entrants until Feb. 27 because of the multitude of requests.

At an October planning meeting, MISO’s Andy Witmeier said the RTO plans to study the current queue in a “timely manner” using the new deadlines.

“We do obviously have a backlog that needs to be worked through as well,” Witmeier said, predicting MISO will play catchup on the queue’s existing delays through 2023.

The queue is further evidence the footprint is marching toward more weather-dependent resources and fewer resources able to be called upon at a moment’s notice. MISO has said that while it expects an increase in installed capacity, accredited capacity values will plunge. Consulting firm McKinsey & Co. has said the MISO footprint could see a nearly 50% increase in overall capacity by 2030.

In September, Chief Digital Officer Todd Ramey said MISO will notice the loss of ramp-up capability the most acutely.

“We’re moving away from the worst hour of the year to the worst day of a season,” Ramey said of MISO peak demand planning in the years ahead. “In the future, it might be the worst week or the worst two weeks of a season.”

But during an October executive update, Ramey said MISO is “excited and honored to be working on so many reliability initiatives.”

As of late 2022, MISO had about 30 GW worth of registered wind capacity and 3.6 GW in registered solar capacity.

The grid operator also officially opened its wholesale markets to energy storage beginning in September. It’s the first time in years MISO has added a new resource type to its energy market portfolio. (See MISO Officially Opens Markets to Storage Resources.)

Seasonal is in

MISO is gearing up to simultaneously conduct four seasonal capacity auctions this spring, with accreditation values that vary by season. In late August, the grid operator got FERC’s approval to simultaneously clear four separate auctions once per year and use an availability-based resource accreditation that relies on the riskiest hours in a season. (See FERC OKs MISO Seasonal Auction, Accreditation.)

The new design is a reaction to MISO’s proliferating emergency declarations and a desire for more accuracy on when capacity is available.

However, MISO has yet to land on a separate, availability-based accreditation for its renewable generation. It plans to spend 2023 refining capacity values with stakeholders.

Without a new renewable capacity accreditation in place, MISO will use an 18.1% effective load carrying capability accreditation for wind generation in summer, a 23.1% accreditation in fall, 40.3% in winter and 23% in spring.

In a June presentation to the board, MISO said that it’s “on the front edge of insufficient supply, and coordinated action is needed to ensure sufficient resources with accredited attributes are available throughout the fleet transition.”

“The MISO region is experiencing continued resource transition acceleration and tight system conditions, which are expected to endanger reliability and market efficiency. Ongoing resource transition trends will likely lead to scarcity of certain essential resource attributes that require evaluation and collaboration with stakeholders,” MISO Director of Policy Studies Jordan Bakke said in August.

Since then, MISO has been trying to pin down what and exactly how much of certain system attributes it needs from its generating units.

The Attribute Debate

Against the resource turnover and capacity shortfalls, some environmental proponents have alleged that MISO employees are inappropriately appearing in front of state commissions to urge the construction of new natural gas-fired generation. (See “Unease over MISO Support for Gas Plant,” MISO Executives Spotlight Fleet Evolution Planning, Risks.)

At a Nov. 28 executive update, Sustainable FERC Project attorney Lauren Azar said MISO’s role is to be fuel-agnostic.

“MISO is of course using euphemisms for natural gas,” Azar said. “I’m just questioning how much you guys are looking into creative solutions.”

CEO Bear countered that MISO has been “very consistent” that it is in desperate need of “controllable, long-duration resources” quickly to cover the capacity shortfalls the grid operator foresees through 2027.

Planned retirements and additions by resource type, according to MISO members’ publicly announced plans | MISO

“Those comments always seem to get taken out of context,” Bear said, adding that MISO is angling for dependable resource attributes, not a certain fuel type.

MISO has defined six system reliability attributes as necessary, including availability, the ability to deliver long-duration energy at a high output, rapid start-up times, providing voltage stability, ramp-up capability and fuel assurance. (See MISO Considers Resource Attributes as Thermal Output Falls.)

MISO Independent Market Monitor David Patton said the RTO’s quantifying requirements for resource attributes isn’t helpful. He said MISO would be better served by a combination of a sloped demand curve in the capacity auction, a marginal capacity accreditation for non-thermal resources and improved shortage pricing so the quickest and most available resources are rewarded for their performance.

“There’s no answer to the question, ‘how many peakers do we need?’ or ‘how many long-duration resources do we need?’” Patton said during a Dec. 6 meeting of the board’s Markets Committee. “You’re positing a question that has no answer. There’s an infinite combination of attributes that would achieve the same reliability objective.”

But some stakeholders have said a discussion of resource attributes is overdue as portions of the Midwest fast approach levels of intermittent resources that will complicate grid operations.

LRTP Becomes Reality

Whether MISO’s grid will be able to support the influx of intermittent resources is an open question. The grid operator in July approved slightly more than $10 billion in long-range transmission planning (LRTP) and is embarking on a second portfolio to accommodate further resource turnover. (See MISO Board Approves $10B in Long-range Tx Projects.)

MISO said its second of four LRTP portfolios could run as much as $30 billion; stakeholders have voiced apprehension with the estimated price tag. (See ‘Conceptual’ Tx Planning Map Troubles MISO Members.)

The new transmission won’t arrive in time for MISO to avert a pair of system support resource (SSR) agreements to maintain system reliability.

Over 2022, MISO took steps to seek approval for two SSR agreements — a coal plant in Missouri and another in Wisconsin. (See MISO Proposing 2nd SSR Agreement for Retiring Coal Unit.)

During a Dec. 6 meeting of the board’s System Planning Committee, Witmeier said MISO believes that SSRs are the best route to “protecting the system” as thermal output falls and intermittent generation rises.

Stakeholders have asked how MISO can simultaneously juggle an unprecedented queue volume, long-range transmission planning, a shifting resource mix, the upcoming move to a seasonal-based capacity auction and testing use of a sloped demand curve in said auction.

“A shortage of work to be done has never been a challenge,” Ramey said in September. He said MISO plans to add manpower and devote more resources to projects where needed.

January 2, 2023June 14, 2023

Plans Revive to Make CAISO a Western RTO

California lawmakers are planning a new effort in 2023 to allow CAISO to become a multi-state RTO under conditions that have changed greatly since the last attempt failed five years ago, while the ISO is hoping to win approval for a day-ahead extension of its real-time Western Energy Imbalance Market, increasing its role in the West.

The potentially big changes come as California is contending with regionalization efforts by SPP, which plans to launch a Western version of its Eastern RTO, and the Western Power Pool, which is seeking FERC approval for its Western Resource Adequacy Program, a possible launchpad for an RTO.

Developments in the past five years are fueling the efforts, including strained grid conditions in Western heat waves, the need for new transmission to carry renewable power, legal mandates for Colorado and Nevada transmission owners to join RTOs by 2030, and more states adopting clean energy and emissions reduction targets.

Collaborating to meet those needs in organized markets would be far less expensive than going it alone, a number of studies have shown.

“There’s a strengthened recognition of the need to work together in the West and the benefits of working together,” CAISO CEO Elliot Mainzer said in an interview with RTO Insider.

CAISO CEO Elliot Mainzer

| © RTO Insider LLC

Last year’s California Assembly Concurrent Resolution 188, authored by Assemblyman Chris Holden, chair of the Assembly Appropriations Committee, asked CAISO to report on studies of the benefits of regional markets by the end of February. The measure passed the state Senate and Assembly by unanimous bipartisan votes.

“This is an important precursor to what’s likely to be a legislative push in California’s legislature next year for broader governance reform,” Mainzer said in a Dec 13 meeting of the WEIM Governing Body. “We look forward to following up with Chair Holden in the early new year to start thinking about the timing and the coordination and the choreography of that important initiative.”

Holden, the former chair of the Assembly Committee on Energy and Utilities, authored bills in 2017 and 2018 to pave the way for CAISO to become a multi-state RTO, but those bills failed. He asked CAISO for the ACR 188 report to show lawmakers the value of regional cooperation.

Since 2018 “states across the West and utilities have adopted their own policies to achieve a clean resource mix and reduce greenhouse gas emissions, which are generally consistent with the policy direction of California,” Holden said in a statement on the bill. “Two states [Nevada and Colorado] have mandated participation in a West-wide market.

“As tens of thousands of megawatts of renewable resources are slated for development in the West, and thousands of megawatts of coal-fired resources are retired and continue to be shut down, momentum is building for greater regional coordination to ensure that electricity is available at all hours of the day,” Holden said. “Consequently, I think it’s time for California to revisit a broader regional market.”

Restarting the Conversation

In the interview with RTO Insider, Mainzer said, “We don’t have any specific details and certainly haven’t seen any legislative language … but we certainly think that Chair Holden, having led the earlier efforts on this a number of years ago, believes that the time is right for another examination of this issue. So, I think the 188 [report] was his effort to start getting folks engaged and get good information and good facts … and to start reinitiating that conversation.”

CAISO commissioned the National Renewable Energy Laboratory to produce the study in partnership with the ISO and California’s eight other balancing authorities, including the Los Angeles Department of Water and Power, the Balancing Authority of Northern California and PacifiCorp. CAISO had planned to release a first draft of the report before the end of 2022 but postponed it until mid-January to give the drafting team more time.

A stakeholder process in the fall identified 41 relevant studies on legal, technical and market issues. They included a study by CAISO in 2016 that it conducted pursuant to Senate Bill 350, a measure that declared the legislature’s intent to “provide for the transformation of [CAISO] into a regional organization to promote the development of regional electricity transmission markets in the Western states.”

The five members of CAISO’s Board of Governors are all Californians appointed by the governor and confirmed by the state Senate. Changing that to allow governors from other states would require legislative action, SB 350 noted. The bill told CAISO to study the potential impacts of becoming a multistate, regional organization before any governance changes could occur.

The SB 350 study found that “a larger ISO-operated regional market [could] create significant value to California ratepayers, decrease overall [greenhouse gas] emissions inside and outside of California, reduce environmental impact in California and elsewhere, increase jobs and economic activities in California and improve the conditions of California’s disadvantaged communities.”

The benefits to the state and the West “increase significantly with the expansion of the market footprint, reducing emissions and the costs associated with the integration of larger amounts of renewable generation resources,” it said.

Holden characterized the ACR 188 report as an update of the SB 350 study.

Another study published last year found an RTO covering the entire U.S. portion of the Western Interconnection could save the region $2 billion in annual electricity costs by 2030 and cut carbon dioxide emissions by 191 million metric tons. A group of Western states led the study, which was financed by the U.S. Department of Energy. (See Study Shows RTO Could Save West $2B Yearly by 2030.)

Other studies identified for the ACR 188 report looked at the potential effects of regionalization on resource adequacy and transmission development.

Kellie Smith, a special consultant to Holden hired to work exclusively on Western regionalization in 2023, said the “critical question and the primary focus of ACR 188 is, ‘Is it good for California?’ Mr. Holden thinks the results are going to say, yes, it’s needed.”

“Since 2018, the perspectives and momentum are building,” Smith said in an interview. “I think it’s pretty obvious that the ISO has the best system around. It’s been working on integration and renewables and [greenhouse gas] tracking for years. The others just don’t have that. So, it makes a lot of sense for the ISO to be the lead” in Western market formation.

A bill to accomplish that, she said, would probably be similar to Assembly Bill 813, which Holden introduced in 2017 and advocated for until it languished in the Senate Rules Committee at the end of the 2017/18 legislative session. The measure passed by a vote of 74-0 in the Assembly and cleared three Senate committees. It never reached a Senate floor vote because some key lawmakers worried it could relinquish control of CAISO to out-of-state interests and jeopardize the state’s climate agenda. (See CAISO Expansion Bill Dies in Committee.)

AB 813 would have instructed CAISO to continue to develop a proposal, originally drafted in 2016, to establish a two-step process for selecting regional board members including a “stakeholder-based nominating committee that selects nominees with the assistance and support of a professional search firm and an approval committee, consisting of the voting members of [a] Western states committee, which would confirm each slate of nominees.”

The Western states committee would have included representatives from each state with transmission owners in CAISO.

The process for selecting members of the CAISO Board of Governors would have then been similar to the process for selecting members of the WEIM’s Governing Body, which includes members from California and other Western states.

The WEIM, which spans much of the Western Interconnection, has been popular with other states, in part, because of its inclusive governance and CAISO’s efforts to share power over WEIM matters with the market’s Governing Body. In contrast, energy leaders from across the West have said they would not join a CAISO-led RTO controlled by California politicians.

EDAM Moves Forward

The other major effort to broaden CAISO’s reach across the West in 2023 is its proposal for an extended day-ahead market (EDAM) for the WEIM. CAISO has promoted the EDAM this year as a way to bring greater cooperation to the balkanized Western Interconnection, which has 38 balancing authorities.

As a real-time-only market, the WEIM has produced more than $3 billion in benefits for its participants since 2014. The real-time market, however, represents only a fraction of the Western market. The day-ahead market is much larger.

The EDAM could generate $1.2 billion a year in benefits, or 60% of the savings of a West-wide RTO, if it encompassed the entire U.S. portion of the Western Interconnection, a new study commissioned by CAISO and performed by consultant firm Grid Strategies found. (See West Could Save $1.2B a Year in CAISO EDAM.)

CAISO fast-tracked the EDAM stakeholder initiative in 2022 amid competition for Western market share by SPP, which is pursuing its own day-ahead Markets+ program in addition to its RTO West. It published the final EDAM plan Dec. 7 and expects to seek approval from its Board of Governors and the WEIM Governing Body in February. The plan will also require FERC approval. (See PacifiCorp to Join EDAM, Final Plan Released.)

“An amazing amount of hard work and robust stakeholder engagement are coming to fruition with publication … of our final extended day-ahead market design,” Mainzer said in his year-end written report to the CAISO Board of Governors and WEIM Governing Body. “The strong stakeholder participation and engagement have helped shape the design through its various iterations, and we are committed to working with stakeholders in making any necessary adjustments that might be needed once the market is up and running.”

“We want to go and see some big things happen in 2023,” Mainzer said.

January 2, 2023June 14, 2023

Winter Problems, Capacity Accreditation, New Faces on the Docket for ISO-NE in 2023

ISO-NE will start 2023 like it starts every year: worrying about the winter weather.

But from there, the New England grid operator will have to move on quickly to the longer-term concerns that will dominate the year, including imminent challenges with gas supply in the region and the complex project to update the way ISO-NE’s capacity market measures resource adequacy.

And the organization will be doing all that while facing tough questions and challenges, from new faces leading the states to a little closer to home, where an upstart group of climate activists has carved out a piece of the grid operator for its own.

Winter, Winter, Winter

In the first few months of 2023, grid officials will be closely watching the winter weather for extended cold spells that could spell danger for the region’s energy supply. So far, both weather and future forecasts have been mild, the only blip a brief shortage on Christmas Eve that was handled by reserve resources.

ISO-NE 2023 work plan (ISO-NE) Content.jpg

ISO-NE’s work plan for 2023 | ISO-NE

ISO-NE will be using a newly updated (and beautified) 21-day energy forecast, a tool that helps it and the public understand what risk lies in the coming weeks.

In the longer term though, the forecasts and solutions aren’t proving so neat.

Both outside experts and the RTO itself say that the Everett LNG facility north of Boston has to stay in operation in order to ensure that there’s enough gas to send out to generators in the region and keep the lights on in winter. (See ISO-NE: Reliability Still Depends on Mass. LNG Import Terminal.)

But the end of the reliability-must-run agreement keeping that facility’s “anchor tenant,” the Mystic Generating Station, alive has caused immense worry among energy policymakers.

“The clock that’s running is going to force us into another set of stopgap solutions,” ISO-NE CEO Gordon van Welie said at a recent conference put on by the New England Power Generators Association. “I don’t think we can design the elegant, long-term resource neutral solutions in a timely fashion to deal with the clock that’s running on Everett right now.”

With the Mystic contract ending in 2024, much of the New England energy world’s focus in 2023 will be on sorting out those solutions.

Capacity Accreditation, and Beyond

Meanwhile, in the NEPOOL stakeholder process undergirding ISO-NE’s policy decisions, there’s a debate underway about capacity accreditation that will burst into full bloom in 2023.

In the RTO’s own words, the project is designed to “identify and implement methodologies that will more accurately reflect resource contributions to resource adequacy in the Forward Capacity Market.”

More broadly, it’s a key part of the region’s energy transition: As more renewable resources come onto the grid, ISO-NE needs a better way to fairly measure the contributions of both them and the incumbent generators like natural gas plants.

But it’s also a highly complex process that has and will continue to strain the capabilities of even the most experienced energy policymakers in NEPOOL (let alone the journalists tasked with translating it to their readers).

In its early work on the concept, ISO-NE has pushed forward with using a metric that sets a resource’s accredited capacity based on the “marginal reliability impact of an incremental change in size.” (See ISO-NE Firms up its Support for Marginal Capacity Accreditation.)

Its preliminary proposals have already earned pushback from stakeholders including the Natural Resources Defense Council and LS Power, who are worried, respectively, that it undervalues the contributions of clean energy resources and doesn’t adequately account for the limitations of gas resources.

Much more of that debate is set to come in 2023, along with other key projects like developing a day-ahead ancillary services market and studies to examine 2050 transmission needs and the impacts of extreme weather.

Healey to the Fore

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New Massachusetts Gov. Maura Healey could be a thorn in ISO-NE’s side. | © RTO Insider LLC

ISO-NE’s relationship with the New England states has been strained in recent years over disagreements about the speed and degree of the clean energy transition and responsibility for the region’s failings.

That’s not likely to change in 2023, but there is a new variable that could shake up the relationship further: Maura Healey.

The former Massachusetts attorney general was elected governor and is set to be sworn in as Charlie Baker’s replacement on Thursday. She’s likely to continue and build on what was, in the end, a fairly robust set of climate policies put forward by Baker. (See Healey Focuses on Climate in Mass. Gubernatorial Race.)

One area to watch where Baker took criticism was on environmental justice and project siting. But she also could take aim at ISO-NE. As AG, Healey and her office spent lots of time and energy navigating the NEPOOL process and helping to organize consumer advocacy responses to ISO-NE’s work.

And significantly, her chief energy aide as AG, Rebecca Tepper, is coming on to join her in the governor’s office as secretary of energy and environmental affairs.

Tepper has been a regular thorn in the side of ISO-NE and regularly pushed it to collaborate more with the states.

The Call is Coming from Inside the House

2023 will be a year when climate activists, for the first time ever, have control of a small piece of ISO-NE.

A group led by the group No Coal No Gas won election to several seats on the coordinating committee of the Consumer Liaison Group, a forum that ISO-NE is required to use for communicating with the public. (See Climate Activists Take Over Small Piece of ISO-NE.)

CLG holds no formal policymaking power, but the committee sets agendas for its four quarterly meetings, which have become increasingly high-profile and well attended.

In 2023, those meetings will look a bit different than they have in the past, with the group promising to focus on connecting the issues that ISO-NE works on more closely to ratepayers (and potentially even pushing for a name change for the group).

“It will now be much harder for ISO New England to keep the CLG from getting feisty,” said Donald Kreis, New Hampshire’s consumer advocate.

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.