RENSSELAER, N.Y. — NYISO officials said Wednesday they will begin stakeholder discussions early next year on revising the interconnection process to make it more efficient, calling it one of their top priorities for 2023.
Zach Smith, vice president at NYISO, told the Management Committee that the ISO is considering a “queue window-based approach,” where each stage of the study would be more meaningful and potentially binding.
The new approach would replace the current three-step study structure, which includes an optional feasibility study and a non-binding system reliability impact study (SRIS) before the facilities study, which results in binding cost allocations.
Smith said the ISO envisions a “clustering approach” where projects are put into a study together to evaluate their joint impact. Smith emphasized, however, that this was simply a preview of what will be discussed with stakeholders and that nothing is settled.
Smith said the additional changes would require tariff revisions and FERC approval, unlike changes the ISO has already made — adding interconnection support liaisons and project managers; improving the interconnection portal; streamlining the SRIS — and ones in process — developing templates to shorten SIS reports and improving handling of material modification requests. (See NYISO Identifies 35 Projects for Narrowed SRIS Scope.)
The ISO expects to begin discussions in the MC, the Transmission Planning Advisory Subcommittee and Electric System Planning Working Group as soon as January and no later than February. “We do not intend to hold up on any improvements waiting” for an order from FERC’s June Notice of Proposed Rulemaking on interconnection generator interconnection procedures and agreements (RM22-14), Smith said. (See FERC Proposes Interconnection Process Overhaul.)
Smith said NYISO is acutely aware of potential tradeoffs stemming from pursuing faster methodologies but is committed to ensuring that project reliability is never sacrificed.
“Do you want speed or do you want flexibility?” Smith said. “One will have to be sacrificed for the other.”
Smith added that it is important for FERC to maintain “independent entity variations” enabling RTOs to tailor solutions to their own regional problems.
CEO Rich Dewey said that the ISO is committed to addressing both the effectiveness of these processes and the customer communication around them. Dewey told stakeholders he understands trade-offs will occur as further changes are made to find the “sweet spot” between flexibility and efficiency.
Mark Reeder, representing the Alliance for Clean Energy New York, commended the ISO for its continued focus on improving the interconnection process: “That’s greatly appreciated.”
Texas lawmakers have jumped into the middle of the Public Utility Commission’s effort to redesign the ERCOT market, saying they are concerned the PUC’s proposals don’t do enough to incent investment in new gas-fired generation.
The commission had been quietly working with consultants behind closed doors to develop new market designs that would protect ERCOT against a repeat of 2021’s disastrous winter storm. But when the PUC unveiled the results of its work last month, it quickly drew pushback from the market and energy experts over its close resemblance to capacity markets. (See Proposed ERCOT Market Redesigns ‘Capacity-ish’ to Some.)
The lead proposal, a performance credit mechanism (PCM) that would require load-serving entities to buy performance-based credits from generation resources that meet reliability standards, has never been tried by a U.S. grid operator. The PUC has asked ERCOT stakeholders and the general public to provide feedback on the PCM and five other market designs by Dec. 15.
However, Texas lawmakers, who see adding more gas-fired, or dispatchable, generation as the solution to the problem (They define dispatchable resources as those not “controlled primarily by forces outside of human control.”) have stepped into the fray.
On Wednesday, Lt. Gov. Dan Patrick, who presides over the state Senate and has tremendous influence over its legislation, unveiled his list of priorities for the Texas Legislature’s 88th session, which begins Jan. 10. They include improving the grid’s reliability; he threatened to keep lawmakers in Austin until they pass legislation that encourages gas-fired power plants to be built.
“Whether it is incentivizing them; whether it’s building them; whatever the plan is, I personally cannot see myself leaving this building knowing that another [winter storm] can happen,” Patrick, who called renewable energy “a luxury,” said during a press conference. “We have to level the playing field so that we attract investment in natural gas plants.”
Observers have noted that would put Patrick at odds with Gov. Greg Abbott and Peter Lake, his handpicked commission chair. Both have said the grid is better than ever because of weatherization, coordinated communication and other operational changes put in place at the end of last year.
The bipartisan Senate Business and Commerce Committee followed up Patrick by sending a letter Thursday to the PUC’s commissioners, urging them to stick to the directives in Senate Bill 3. The omnibus bill, passed last year following the winter storm that almost brought down ERCOT’s grid and left millions of Texans in the dark for days, called for “adequate incentives” for dispatchable generation. It also instructed the PUC to incentivize that dispatchable generation by establishing a reliability standard for the market and using that standard to develop or procure a new ancillary or reliability service for the generators. (See Abbott Signs Texas Grid Legislation into Law.)
The committee had already heard from the PUC, ERCOT and stakeholders, having held a hearing on the plan Nov. 17. It said the testimony that day indicated the PCM was an “administratively complex and novel concept” that would “deter new investments in the ERCOT market until it is fully in place.” (See Legislators, Stakeholders Pan Proposed ERCOT Market Design.)
“By the commission’s own admission, [that] could be several years down the road,” committee members wrote. “There is significant concern the proposals being considered by the commission … not only failed to meet the directives clearly stated in SB3, but more importantly will not guarantee new dispatchable generation in a timely and cost-effective manner. …
“It is not in the best interest of our constituents to support any proposal that further delays investments in new dispatchable generation, and the commission should carefully consider the unintended consequences of any type of proposal that creates more uncertainty for market participants.”
The committee directed the PUC to define ERCOT’s reliability goals before moving forward with any “significant” market redesign and to evaluate creating a new market-based ancillary or reliability service to meet reliability standards.
“Any holistic market design change, including the PCM, that goes beyond the scope of SB3 should not be adopted by the commission without further consultation with the legislature,” the committee said in concluding its letter.
The hits could keep coming. On Monday, the House of Representatives’ State Affairs Committee will hold a public hearing to review the proposed market changes.
The PUC seemed unfazed by the legislative comments. It still plans to present a final recommendation to the legislature next year before allowing ERCOT to begin the implementation process.
A spokesman said the commission will develop a reliability service, “as we’ve said since the beginning of this process.”
“The [PUC] published multiple options for consideration and eagerly awaits public comments on all options,” Rich Parsons said in an emailed statement. “Once the commission holds a vote on a preferred reliability service, we will present it to the legislature next session.”
“The PUC should take this legislative brushback of the chairman’s preferred solution very seriously. It’s a bad idea to tick off the folks who approve the commission’s budget, appointments and headcount,” Alison Silverstein, an energy consultant with experience at both the PUC and FERC, told RTO Insider on Friday.
She said the PCM proposal is “barely articulated, poorly analyzed, ill-supported and precedent-free, with little evidence that it will produce new gas plants.”
“I wouldn’t risk the Texas economy and energy affordability for [the PCM],” Silverstein said.
She put in a plug for the backstop reliability service, one of the other five designs. The ancillary service would meet specific reliability needs not met by ERCOT’s real-time and ancillary service markets during high uncertainty periods. Silverstein said it would act as an insurance policy that would better manage plant retirements.
Stoic Energy principal Doug Lewin said that building new gas plants will only lead to higher customer bills.
“If you want to lower bills, you need to integrate more renewables and increase energy efficiency,” he tweeted, noting that a consultant for the PUC has shown that high renewable generation reduces energy costs by 20%.
“No one thing will solve any, much less all, of these problems,” Lewin added. “Unfortunately, some policymakers are trying to solve a different problem. They don’t like renewables and want more gas plants. That won’t solve any of the problems.”
CARMEL, Ind. — MISO said last week its members may need to build 200 GW in new installed capacity by 2041 to meet reserve requirements and achieve renewable targets and emissions-cutting goals, according to the RTO’s annual regional resource assessment.
The grid operator used this year’s report, which draws on members’ public generation plans and MISO’s own capacity expansion estimates, to repeat warnings of continuing capacity shortages and plead for more controllable generation. Staff said members may need to construct more than 100 GW of new capacity within the next 10 years alone to meet “publicly announced plans and goals in a reliable manner.”
After the inaugural assessment in 2021, MISO said it would need to add 140 GW of new capacity over the next two decades to meet state carbon-reduction targets while also maintaining reliability. Carbon reduction goals have only become more aggressive in the last year, with utilities frequently revising net zero goals. (See MISO Resource Assessment: 140 GW Needed Within 20 Years.)
This year, MISO focused on accredited capacity numbers. Although it expects members to add 30 GW of net installed capacity by 2041, it said accredited capacity will be at least 10 GW lower than what is available today.
The RTO projects members will likely need to add 47 GW in accredited capacity above the 141 GW of planned and accredited existing resources it expects to have in 20 years. It has approximately 162 GW in total accredited capacity today.
MISO said it will likely approach 30% of its annual energy coming from renewables within five years, with penetration levels increasing by about 10% every five years.
Systemwide existing, planned, and needed resources | MISO
Its modeling “indicates a continued near-term capacity risk, highlighting the urgent need for coordinated resource planning and additional investment.” Staff stressed that the assessment captures a snapshot in time that relies on publicly available resource planning and isn’t necessarily MISO’s future. They emphasized that MISO members do not produce “detailed” resource plans on a 20-year time horizon.
“In the absence of a coordinated transition plan, having a holistic assessment of our entire operating region is important for our members, policymakers and MISO as we all work to anticipate and manage the complex issues facing our industry,” CEO John Bear said in a Wednesday press release accompanying the report.
According to the report, wind and solar generation will serve 60% of MISO’s annual load by 2041, reducing emissions by nearly 80% relative to 2005 levels. The RTO said that generation mix will “sharply increase the complexity of reliably operating and planning the system.”
The footprint will “have a much greater need for controllable ramp-up capability,” MISO said. It said its short-duration ramp needs will increase three-fold from current levels by 2031, and four-fold by 2041.
MISO also said that by 2031, it will encounter resource adequacy risks in all seasons, not just summer. The grid operator said the risk will mostly be concentrated in the evenings when solar generation tapers off and wind generation is still ramping up.
The RTO found that as more solar capacity is added to the system, the capacity contribution of solar generation “is forecast to decline rapidly,” while wind generation’s contribution remains stable with additions.
“As the MISO region rapidly transitions to a decarbonized fleet, the system will become more interconnected and interdependent,” Jordan Bakke, director of strategic insights and assessments, said. “The task of resource planning is becoming more complex and having a shared understanding of future trends and risks is necessary to ensure reliability.”
MISO has a staggering amount of proposed capacity in the interconnection queue after fielding in September a record 171 GW of proposed renewable generation and storage projects from 956 requests. (See MISO Insists it can Handle Record-setting Interconnection Queue.)
The rub is MISO’s supply of accredited capacity. And while capacity increases, its share of on-demand capacity is drying up.
During a Nov. 10 stakeholder workshop, policy studies engineer Hilary Brown said members are largely planning investments in solar and wind capacity as they schedule more coal generation retirements.
“A one-for-one megawatt replacement is likely not sufficient,” Brown said of members’ plans.
She said MISO expects the near-term capacity risk to continue with the growing need for flexible resources to reinforce intermittent resources.
The RTO’s system simulation showed it will likely need a yet-unknown combination of low-emission, high-capacity grid-enhancing technologies by 2030, including carbon capture and sequestration, small modular reactors, green hydrogen and long-duration energy storage.
Stakeholders have pressed MISO to provide a megawatt value of how much new storage it might need over the next 20 years.
CARMEL, Ind. — MISO is releasing preliminary design details of a sloped demand curve in its capacity auction. Staff plans to use its planning reserve margin requirement as a middle point and adding and subtracting incremental amounts of capacity, measured by expected unserved energy.
“It’s going to be convex shaped,” Mike Robinson, principal adviser of market design, told the Resource Adequacy Subcommittee Wednesday.
Robinson said MISO doesn’t yet have exact values associated with the demand curve.
“We have preliminary numbers, and we’re assessing them to make sure they pass the smell test and that they’re reasonable,” he said.
Reliability will be “foremost” in designing the curve’s shape, Robinson said. He noted MISO wants a demand curve that encourages reliability while valuing capacity at market prices. A capacity glut would render sloped curve prices nil, Robinson said.
Independent Market Monitor David Patton said a sloped curve can prevent premature resource retirements and will raise revenues for most utilities. He said the curve will also “reduce financial risk and the volatility associated with overbuilding and underbuilding of capacity.”
“You’ve all heard me talk about this for a decade or more,” Patton told stakeholders.
OMS Executive Director Marcus Hawkins said support was “near unanimous.”
Some stakeholders have said that setting a demand curve is challenging because utilities place differing value on additional capacity.
MISO said that to formulate a sloped demand curve, it will need to run analyses using the net cost of new entry (CONE), or an approximated revenue from capacity payments. To do this, the grid operator is proposing to use three years’ worth of historical data to calculate inframarginal rents, the money used to cover generators’ fixed costs. Net CONE will be calculated by subtracting inframarginal rents from CONE and using them to inform the curve’s final shape.
Robinson said staff is trying to bend the curve in a way that supports net CONE over the long run.
Multiple stakeholders cautioned that inframarginal rents are rooted in market ambiguity and could set off lengthy stakeholder disagreements over what amount is appropriate.
A sloped curve will also have MISO adding what it calls an “advanced” fixed resource adequacy plan (FRAP) option.
Robinson said MISO isn’t planning on changing any existing participation options for market participants; they can still opt out of the auction, make a FRAP, self-schedule resources, or purchase from the PRA.
“This is just another option here we want to make available,” he said.
An advanced FRAP will require market participants to get their relevant regulator’s approval, make a showing that they can meet their load obligations a month ahead of the auction, and commit to not taking offers in in the auction for a minimum of three consecutive years. Under an advanced FRAP, load-serving entities could sell their excess capacity provided it they have a certain, yet-undetermined percentage of capacity beyond their requirement.
Robinson said MISO won’t allow partial advanced FRAPs as it does with run-of-the-mill FRAPs. “You’re either fully in or fully out,” he said.
Robinson said allowing a partial advanced FRAP would complicate the auction’s algorithm. He also said a minimum commitment will discourage load-serving entities from “toggling in and out of the auction.”
MISO will take stakeholder opinions on its early proposal through the end of the year.
A sloped demand curve in the capacity auction was top of mind during a late summer stakeholder idea exchange.
Bill Booth, a consultant to the Mississippi Public Service Commission, said he didn’t see why a downward sloping demand curve is en vogue again. He said MISO’s circumstances — being overwhelmingly comprised of vertically integrated utilities — haven’t changed since a sloped demand curve was last contemplated and shot down five years ago. He said the RTO’s excess capacity drying up is the only thing that’s different.
“There’s plenty of renewable generation trying to tie into the system, so I don’t think we need to promote that,” Booth said. “That’s clear from the interconnection queue … but it might not be the generation we need for our circumstances.”
He said decisions on fuel mixes are made at the state level and its naïve to hope that a demand curve’s prices will spur more dispatchable resources. Booth suggested MISO’s planning reserve margin requirement could be tailored to require a certain amount of dispatchable generation.
Hawkins argued that a capacity shortage isn’t MISO’s only issue. He said clearing prices in recent resource auctions have become increasingly volatile.
Julie Fedorchak, the North Dakota Public Service Commission’s chair, said the RTO’s capacity market “desperately” needs better market signals, and the demand curve is a tool toward improving them. She said that, candidly, she was “sick and tired” of some MISO members freeriding at the expense of her ratepayers.
MISO has committed to more frequent postings of preliminary capacity auction data. The grid operator will standardize the schedule of seasonal reserve requirements in zones to twice per month in mid-January.
The more frequent data shares are a response to stakeholders’ asking staff to publish more regular updates ahead of the auction on its supply estimates and requirements. (See “Stakeholders Ask for Data Improvements,” MISO Promises Stakeholder Discussions on Capacity Auction Reform.)
CARMEL, Ind. — MISO says it “largely agrees” with its Independent Market Monitor’s five new market recommendations issued this year.
The IMM’s annual State of the Market report, released this summer, listed recommendations for promoting transmission reconfiguration plans, reducing out-of-market commitments, creating a future-looking dispatch model and ensuring MISO only pays for real load reductions. (See MISO Monitor Prescribes 5 New Fixes in Annual Market Report.)
The grid operator said it is actively working on three of the ideas, while the remaining two are on its list of five-year goals.
In reviewing the market performance in 2021, the Monitor said the RTO should:
work with its transmission owners to identify and implement economic transmission reconfiguration plans to better manage congestion;
evaluate and restructure its unit commitment process to reduce out-of-market commitments and ensuring make-whole payments;
develop a multihour, look-ahead dispatch and commitment model to better manage fluctuations in net load and decisions on when to use storage resources. Patton said, “as reliance on intermittent resources grows in MISO, the need to manage extraordinary fluctuations in net load will grow;”
improve rules around demand participation in energy markets so that MISO only pays for load reductions that occur; and
consider classifying load-modifying resource (LMR) curtailments as short-term demand in pricing models and the unit dispatch system.
The last recommendation stems from Patton’s observation that LMRs are allowed to set real-time energy prices long after emergency conditions have passed. He said that’s because of MISO’s extended locational marginal pricing (ELMP) model respecting resources’ ramp rates, which makes it impossible to replace a large volume of LMRs within a single dispatch interval.
Patton said the LMRs appear to be necessary and set prices “long after MISO’s resources are sufficient to replace them by ramping up.” He said that if MISO treats LMRs as an operating reserve demand in the ELMP model, it would eliminate the problem.
MISO said it has yet to begin work on the second stage of its look-ahead commitment tool or categorizing LMR curtailments under short-term demand for pricing purposes.
Zhaoxia Xie, with MISO’s market design team, said staff may encounter some difficulty including LMR curtailments because short term reserves are priced systemwide or zonally, whereas LMRs are modeled at the more local nodal level. But she promised more evaluation on the issue Thursday during a Market Subcommittee meeting.
The RTO said it plans to augment its look ahead commitment tool in 2023 to improve commitment decisions. It said upgrades should reform its unit commitment processes with the added benefit of using storage resources to manage fluctuations in net load.
“This has been a hot topic between MISO and the IMM for a while,” Xie said. She said staff is constantly evaluating improvements in its commitments process.
The grid operator agreed that it could use more stringent rules and procedures for demand participation “to avoid unjust payments.” MISO said it may file tariff revisions with FERC after consulting with stakeholders.
Staff said they’ve been working since January with transmission owners to develop operating procedures for transmission reconfiguration. They will begin a reconfiguration process in 2023’s first quarter to reduce congestion costs.
MISO’s Tony Rowan said the procedure involves a market participant bringing a suggested economic reconfiguration to staff and relevant TOs, who will test the solution over 15 business days for reliability and economic impacts. If MISO and TOs agree the solution puts a dent in congestion without deteriorating system conditions, the reconfiguration plan will go into effect for an agreed-upon duration.
MISO also said it will maintain a public list of the footprint’s top 10 most economically impacted constraints.
CARMEL, Ind. — MISO is proposing a biennial review to reduce its “parking lot” list of improvement suggestions, although some stakeholders are putting up resistance.
“We’d like to make sure that good ideas don’t go to the parking lot to linger indeterminately,” Laura Rauch, senior director of transmission planning, said during a Market Subcommittee meeting Thursday
MISO’s parking lot contains improvement ideas submitted to MISO through its issues-submission process. It has become a graveyard of shelved ideas, with some stakeholders complaining that their recommendations remain unaddressed. (See MISO Pledges Review of On-hold Stakeholder Ideas.)
The grid operator said it will clean up the parking lot and eliminate nearly 20 suggestions. In some cases, staff doesn’t have a record of the stakeholder that originally submitted the idea or its full description.
The grid operator said it will use “active,” “inactive,” and “closed” to label the idea list. “Closed” means MISO has no current plans to address the idea and i will fall off the list. Staff will work with stakeholders with inactive projects and determine their feasibility every two years.
Rauch pointed to a suggestion creating a universal resource participation model that has spent years in the parking lot. MISO doesn’t distinguish market participation models by intermittency, energy storage and demand response, leading Rauch to term the suggestion “aspirational” and suggest it should be closed. Stakeholders could always revive the idea by submitting it again to the RTO.
Rauch also said there’s some redundancy among the improvement recommendations.
“To me, this seems like another way MISO isn’t allowing stakeholders to decide when an item doesn’t need attention,” Clean Grid Alliance’s Natalie McIntire said.
Independent Market Monitor David Patton took umbrage with MISO’s move to close his suggestion that a virtual spread product be created in the day-ahead market. It would allow participants to specify the maximum congestion between two points they are willing to pay in a virtual transaction.
Rauch said in this case, staff last delivered a presentation on a virtual spread product in 2012. She said MISO has no plans to address the issue.
Xcel Energy’s Kari Hassler said she was concerned that the grid operator would put recommendations on the chopping block before it has completed its new market platform, which has been billed as being able to host more complex market products.
“We have a lot of projects that are pushed back and waiting in the wings until” MISO’s new market platform is finished, Hassler said.
MISO plans to roll out its day-ahead market on the new, modular market platform next year.
FERC must better explain its 2019 decision to give MISO transmission owners unilateral authority to finance upgrades needed to interconnect new generation, the D.C. Circuit Court of Appeals ruled last week.
The proceeding was “the latest episode in a long-running dispute over how to fund upgrades to power lines,” Judge Justin R. Walker wrote in the decision issued Friday (20-1453).
The details in the case extend back to 2015, when Otter Tail Power filed a complaint with FERC challenging MISO’s policy of providing “direct” transmission owners with unilateral authority to decide whether to initially fund a needed upgrade — and later collect the costs from the interconnecting generator — or allow the generator to pay the costs up front. Otter Tail contended that while direct TOs exercised that privilege, operators of affected systems further downstream (“indirect” TOs) enjoyed no such option, resulting in differential treatment.
In a decision issued June 2015 (ER14-2464), FERC agreed with Otter Tail, but rather than extending the right of unilateral initial funding to TOs indirectly affected by an interconnection, it instituted a proceeding under Federal Power Act Section 206 directing MISO to either remove the unilateral option or explain why it shouldn’t. (See FERC: MISO Gen Agreement Allows Overcharging.)
The D.C. Circuit vacated FERC’s decision in 2018 in Ameren Services Co. v. FERC, saying the commission hadn’t considered complaints from Ameren and five other TOs that claimed the policy forced them to accept “risk-bearing additions to their network with zero return” and essentially act as “nonprofit managers” of network “appendages.”
The decision in Ameren “also held that FERC should have considered that its decision could force transmission owners to incur the financial risks of generator-funded upgrades without the opportunity for a profit,” the court noted in Friday’s ruling. “We declined to decide whether those enterprise-risk concerns required a particular result until FERC ‘developed a record by considering’ them.”
The case was then remanded to FERC, which in 2019 reinstated TO funding rights and extended them to indirect owners, a decision the commission affirmed the following year after a protest by the American Wind Energy Association (later renamed the American Clean Power Association (ACP)) (EL15-68, et al.). (See FERC Upholds MISO Self-fund Order, Glick Dissents.)
The commission had also made its decision retroactive, forcing the renegotiation of several generator interconnection agreements between 2015 and 2018. (See FERC OKs MISO Agreements Following TO Funding Ruling.)
‘Plausible Reasons’ for Concern
In the case decided by the D.C. Circuit on Friday, the ACP petitioned the court to review FERC’s orders, arguing that the commission had: failed to follow the Ameren decision’s command to “develop a record” of enterprise risks for TOs; acted in an arbitrary and capricious manner by giving TOs unilateral funding authority; and erred in making its 2019 decision retroactive.
The court dismissed the third argument, saying that its jurisdiction only extends to arguments that a party raised in a rehearing application to FERC, “unless there is reasonable ground for failure to do so,” points that ACP failed to argue.
Addressing ACP’s first argument, the court found that FERC did comply with the Ameren remand order.
There, we told FERC to ‘[develop] a record byconsidering’ the transmission owners’ enterprise-risk argument,” the court wrote. “That instruction suggested no particular briefing. Nor did it demand any additional evidence for a record that was already voluminous. Rather, it required nothing more than FERC ‘considering’ the enterprise-risk argument and putting that consideration on the ‘record’ for our review.
“On remand, FERC did just that: It considered the enterprise-risk argument and rendered a decision on its merits in the record for us to review.”
But the court did agree with ACP’s second argument, ruling that FERC’s decision to grant unilateral funding authority to all TOs failed to satisfy the “arbitrary and capricious” standard in the Administrative Procedures Act.
“Although FERC’s decision may ultimately prove to be ‘reasonable,’ it was not ‘reasonably explained,’” the court said.
The court noted that ACP did not “seriously dispute” FERC’s determination that, under the FPA, direct and indirect TOs should receive similar treatment with respect to upgraded funding. Instead, it argued that the commission violated the APA “by not adequately explaining its decision to solve that problem by giving unilateral funding authority to all transmission owners, rather than by denying unilateral funding authority to all transmission owners.”
The court said it agreed with ACP that FERC failed to reasonably explain its decision: “In particular, it gave short shrift to the petitioner’s concern that transmission owners might discriminate in favor of generators they own.”
In proceedings before FERC, the court noted, ACP provided “plausible reasons” for that concern, having pointed out that many TOs in MISO also own generators, providing a competitive motive to discriminate against other generators. And while FERC acknowledged that concern, it also concluded that concerns about potential discrimination did not outweigh the TOs’ enterprise-risk concerns.
FERC had argued that ACP did not “show why the ability of [generators] to challenge costs before the commission, a point on which the court relied, is inadequate to address any concerns with potential undue discrimination.”
But the court pointed to “something important missing from FERC’s orders: an assessment of the risk of discrimination and an explanation of why individualized proceedings provide generators with sufficient protection against that risk.”
In oral arguments, the court noted, counsel for intervenors supporting FERC “gave a relatively detailed assessment and explanation” of why the current regulatory regime should alleviate the risk of TOs giving preferential treatment to their own generation.
But FERC’s orders had failed to do that, it said.
“FERC had the chance to explain itself at two different steps in its proceedings,” the court said Friday. “It could have done so when it found that the unilateral funding option was not unjust or discriminatory, or later when it remedied the disparity between direct and indirect transmission owners in the Otter Tail proceeding. …
“We therefore remand for FERC to adequately explain its decision,” the court concluded. “But we do so without vacating FERC’s orders ‘because there seems to be a significant possibility that [FERC] may find an adequate explanation for its actions, and, in any event, it appears that the consequences of its current ruling can be unraveled if it fails to.’”
The California Air Resources Board is getting close to finalizing details of its electric bicycle incentive program, a $13 million initiative expected to launch in early 2023.
The program will be geared toward low-income participants. CARB is considering an eligibility cap of 300% of the federal poverty level (FPL). In 2022, 300% of the FPL is $40,770 for a one-person household, $54,930 for a family of two, or $83,250 for a family of four.
The amount of the e-bike purchase incentive has yet to be decided, CARB staff said during a workshop on the program last week. Participants in previous workshops said a rebate of $750 to $1,000 would be enough to encourage an e-bike purchase.
Larger incentives might be offered to residents of disadvantaged communities or those whose income is less than 225% of the federal poverty level. Bigger rebates might also be available to buyers of specialized bikes, such as cargo bikes or adaptive bicycles for special-needs riders.
CARB is looking at setting aside half the program’s funding for people whose income is less than 225% of the FPL and those living in disadvantaged communities. Applications from those groups would be processed first.
The agency expects to start offering incentives in the first quarter of 2023.
Despite limiting the incentive to low-income applicants, CARB staff said they’re expecting strong demand.
“We already know this program is going to be super successful,” said Aria Berliner from CARB’s Advanced Transportation Incentive Strategies Section. “There is so much interest.”
An Alternative to Cars
E-bikes are viewed as an ideal alternative to cars for trips around town. By encouraging e-bike adoption, CARB aims to support active transportation, reduce miles traveled by car and cut greenhouse gas emissions.
California’s e-bike incentive program received a $10 million allocation from the 2021/22 state budget. (See Calif. Program to Provide $10M in E-bike Incentives.) Last month, the CARB board voted to increase program funding to $13 million.
Following a competitive solicitation, CARB selected San Diego-based Pedal Ahead to administer the e-bike incentive program. The nonprofit started work on the project on Dec. 1.
CARB has held a series of workshops to help decide program details. The agency discarded an earlier proposal to exclude Class 3 e-bikes from the incentive program. CARB’s concern was that the Class 3 bikes, which reach speeds of 28 mph, could be a danger to pedestrians or other cyclists.
But Class 3 has become the most popular type of e-bike, workshop participants said, and the bikes are useful to riders making longer trips.
Another issue that’s been debated is whether incentives can be used at online retailers, or brick-and-mortar stores only. Under CARB’s current proposal, eligible purchase locations would include local bike shops and online retailers with a presence in California — either a physical store, company headquarters or a manufacturing site.
CARB is also looking at requiring eligible bikes to come with a two-year warranty at no additional cost. Another idea is to offer incentives for safety equipment such as bike locks, lights, helmets and safety vests. Some workshop participants said eligible bikes should come equipped with front and back lights.
Other workshop participants said CARB should also offer financing for e-bike purchases. According to the California Bicycle Coalition (CalBike), e-bikes that are safe and have “respectable durability” cost $2,000 and up.
CARB plans to hold another workshop on the e-bike program early next year, with discussion focused on incentive amounts, safety gear subsidies and e-bike cost limits.
Other Incentives
In crafting its e-bike incentive program, CARB is looking at e-bike incentives available in areas such as San Mateo County, Calif., Denver and British Columbia.
The city of Denver this year started an e-bike rebate program with a standard rebate of $400 and a $1,200 rebate for low-income residents. E-cargo bikes are eligible for an extra $500.
As of late October, 4,401 e-bike vouchers had been redeemed, the city said. The program was paused because funding ran out, but it’s expected to return next year.
Pedal Ahead runs an e-bike program in San Diego County that prioritizes low-income applicants. The program loans e-bikes to participants, who are asked to ride at least 150 miles per month and use an app to collect trip data. Participants who meet the requirements for two years may then keep the bike.
This year, Pedal Ahead announced a partnership with the San Diego Association of Governments to bring the program to another 125 participants.
FERC on Thursday approved NYISO’s request for up to three more years to implement tariff revisions that will allow distributed energy resources in aggregations to provide all ancillary services they are capable of, in compliance with Order 2222 (ER21-2460).
NYISO last month proposed to extend the revisions’ effective date from the fourth quarter this year to a “flexible” date of no later than Dec. 31, 2026, because of unexpected delays in developing and implementing the necessary software modifications.
The ISO said it will not necessarily need all of that time to complete the necessary work. It noted that it is still on track to implement the DER aggregation and participation models accepted by the commission in 2020 by the third quarter of 2023 and, as a result, may be able to start having aggregations participating in its markets far in advance of 2026.
It also said that in 2024 it will start deploying software that will automate much of the work that will at first be done manually by staff.
NYISO had earlier this year requested for more time to submit its Order 2222 compliance filing; as part of compliance with the order, each RTO and ISO was required to propose a date by which it could complete the necessary work integrating DERs into their markets. (See NYISO Requests Extension, Clarification on Order 2222 Compliance.)
In its brief order, FERC noted that no answers were filed in response to NYISO’s request, approving it without further comment.
RENSSELAER, N.Y. — NYISO’s Management Committee on Wednesday approved tariff revisions on credit rules for virtual transactions, the deliverability of “internal controllable” lines and transmission owners’ right of first refusal. The committee also received briefings on the ISO’s winter supply outlook and its updated Strategic Plan.
Credit Requirements on Virtual Transactions
The MC approved the first changes since 2009 to the ISO’s credit requirements for virtual transactions — bets on the price spread between the day-ahead-market (DAM) and the real-time market.
The 2009 changes distinguished for the first time between virtual load — offers to acquire energy in the DAM — and virtual supply, offers to provide energy. The rules varied credit requirements based on seasonal, time of day and zonal groupings to reflect their risk characteristics, using data from April 2005 forward.
The current rules break supply and demand credit requirements into four periods for weekday peak hours (HB7-22), and one each for nights and weekends/holidays. Under the proposed changes, virtual demand bids will have different requirements for summer, winter and shoulder months, with 28 distinct groupings. Virtual supply bids will be broken into 33 groupings, also reflecting the seasonal differences.
Virtual supply and virtual demand positions show lookback comparisons | NYISO
The proposal also would change the lookback period, giving one-third weight to data from the last year and two-thirds to the last five years.
NYISO said expected changes to its transmission system and resource mix over the next decade “provide support for shift to a shorter lookback period so that changes in real-time price variability are reflected in credit requirements without a long delay.”
The ISO settled on the weighting to balance accuracy with responsiveness, said John Jucha, senior credit risk analyst. Longer lookback periods provide more data points and more accurate estimates but result in slower changes to credit requirements when system conditions and price volatility are changing rapidly. Shorter lookback periods allow quicker adjustments to credit requirements but can also result in dramatic changes not warranted by underlying conditions.
The proposed rules also would treat the ISO’s transmission zones and proxy buses individually rather than the current practice, which sets one requirement for zones A to F and another for zones G to I. The ISO said it expected “significant benefits” immediately for zones A and F, with potential benefits for other zones in the future.
Also changed was the threshold for virtual supply positions, which will increase to the 98th percentile. The threshold remains unchanged at the 97th percentile for virtual demand positions.
The new rules will also apply to external transactions.
Pending approval by the Board of Directors, the ISO hopes to file the changes with FERC by April 2023 and deploy them in June.
NYISO Strategic Plan
NYISO shared its 2022 Strategic Plan, which highlighted its responsibilities, accomplishments and future goals, as well as how state and federal policies help drive the ISO’s strategic objectives.
Executive Vice President Emilie Nelson said offshore wind represents the largest potential shift in New York’s resource mix and that the state Climate Action Council’s forthcoming final scoping plan will inform much of the ISO’s future work. Energy security has become a growing concern as geopolitics impact global supplies, she added.
Nelson told stakeholders that NYISO has taken on more responsibilities, such as developing a reliability needs assessment, increasing stakeholder communications and tackling multifaceted issues like cybersecurity.
Bruce Bleiweis of DC Energy asked Nelson what letter grade the ISO would give itself as a “leader in the application of technology.”
Nelson responded that NYISO performs at an “A” level.
Bleiweis disagreed, saying he and other stakeholders focused on the financial markets have been frustrated with their inability to win ISO backing for “relatively minor changes” to the transmission congestion contracts (TCC) market.
“We’ve been asking for certain changes to the TCC markets for six or eight years,” he said, saying a “simple posting of data” calculated by the ISO “seems to become a [$500,000] project.”
Bleiweis said his company doesn’t face such “roadblocks” in the other organized markets. “Once a project is approved by stakeholders and the ISO, they seem to move forward relatively quickly.”
Nelson said the ISO must make “difficult” tradeoffs between competing budget priorities.
Deliverability Rules
The MC approved proposed tariff language governing the deliverability of internal controllable lines (ICLs) such as Clean Path New York.
The rules would require a class year transmission project requesting capacity resource interconnection service for unforced capacity (UCAP) deliverability rights to be deliverable throughout the capacity region to which it proposes to inject energy and throughout the capacity region from which it proposes to withdraw energy.
Amanda Myott, NYISO market design specialist, said the ISO was proceeding with tariff revisions on the deliverability of ICLs before the rest of the ICL market design to ensure the changes apply to the class year 2023 deliverability analyses. (See “Ramp Limits on ‘Internal Controllable’ Lines,” NYISO Installed Capacity Working Group/Market Issues Working Group Briefs: Sept. 30, 2022.)
The changes approved by the MC also affect tariff Attachment S regarding the calculation of UCAP deration factors in the class year deliverability studies and expedited studies.
Pending board approval, the ISO intends to submit the revisions to FERC in January.
The March order only addressed upgrades that are part of a developer’s proposed PPT project. The new proposal, presented by Stuart Caplan of Troutman Pepper, would extend the ROFR provisions to “network upgrade facilities” that are required as a result of the transmission interconnection process. (See NY TOs Seek Clarification on ROFR for Upgrades.)
Without the changes, TOs must engage in case-by-case bilateral negotiations and FERC filings, resulting in a more time consuming and less transparent process, Caplan said.
Subject to board and FERC approval, the changes would be effective for the Long Island offshore wind transmission project.
Winter Capacity Assessment
Natural gas storage levels are higher than anticipated thanks to a mild fall, but they are still lower than previous years, according to the ISO’s winter capacity assessment.
Winter natural gas underground storage levels | NYISO
Distillate fuel inventories are well below the five-year average capacity, but generating units are still receiving deliveries, and inventories are approximately 95% of last year’s capacity, according to NYISO Vice President of Operations Aaron Markham.
Markham also shared that both the Sprainbrook-East Garden City Y49 line in Long Island and the Moses-Willis MW1 line would be taken out service this season for repairs.
