Page 483 – RTO Insider

March 10, 2022November 30, 2023

ERCOT Board of Directors Briefs: March 7-8, 2022

Governance Changes for TAC, Stakeholder Process Remain Unclear

ERCOT’s Board of Directors left the grid operator’s top stakeholder committee, the Technical Advisory Committee, in a bit of limbo this week as it continued to debate governance and stakeholder coordination.

The directors on Tuesday first deferred confirmation of the TAC’s leadership, normally a routine matter, until the board’s April 27-28 meeting. That meeting was rescheduled from April 12 and would have conflicted with a TAC meeting. However, the committee moved its April 27 meeting up to April 13 to help push an urgent protocol revision request through the stakeholder process.

The directors then approved the creation of a board-level meeting committee to oversee ERCOT’s core functions. As proposed by staff, the Reliability and Markets Committee would focus on markets, planning, reliability and resilience. The scope would also include information technology and project delivery.

Both actions followed an extensive executive session that began Monday and ended Tuesday.

TAC Chair Clif Lange, with South Texas Electric Cooperative, said the delayed vote on his confirmation caught him by surprise and wasn’t telegraphed by ERCOT staff. He said he only became aware of the board’s actions when he started receiving texts from TAC members Tuesday morning.

“We didn’t see that coming,” Lange told RTO Insider. “Nothing had been communicated to us.”

He said nothing in the meeting materials indicated to him that the TAC would answer directly to the board and said that further modifications to the committee could be in the offing.

The board, which has met with all 11 members just twice since December, has been vocal in its previous meetings about the time it takes protocol revisions to clear the stakeholder process. The TAC is responsible for vetting and endorsing protocol revisions that come up from the working groups, while market participants’ heavy involvement in ERCOT’s governance has drawn attention since the February 2021 winter storm.

The TAC, for its part, has discussed the potential changes to the stakeholder process several times in recent months. (See “TAC Members Look for Direction on Governance Structure, Stakeholder Process,” ERCOT Technical Advisory Committee Briefs: Jan. 31, 2022.)

“I know we on the TAC are a little concerned that not engaging stakeholders and shutting them out will result in suboptimal products for ERCOT,” said Lange, who added that he plans to take his concerns to interim CEO Brad Jones.

ERCOT officials say the eight new independent board directors are grappling with their new responsibilities.

Chris Ekoh, interim CEO of the Office of Public Utility Counsel (OPUC) and the only non-independent voting board member, read a memo into the record that expressed his concerns for the stakeholder process and with the new board committee. He asked whether the TAC will be disbanded or made “subservient” to the new board committee.

“It is not clear to OPUC how the creation of the new Reliability and Markets Committee will impact or coexist with the current stakeholder process,” he said. “How will the proposed Reliability and Markets Committee interact with TAC? How does the committee and TAC work together, if at all? How does it impact the protocol revision process?”

Ekoh also asked whether there were compliance concerns for ERCOT if the revision process is modified.

“Those are questions everybody has about how TAC is going to interact with the board,” Lange said.

There was no public discussion of Ekoh’s comments among the board members.

Upward Pressure on Admin Fee

CFO Sean Taylor told the directors that ERCOT’s costs are projected to continue to grow at a rate faster than shown in its current 2022-2023 budget, which was approved last year. He said additional demands placed on staff as a result of last year’s winter storm include new regulatory requirements, protocol and planning revisions, and increased IT support costs for new or improved services that were not expected.

“There is upward pressure on the 2023 budgeted system administration fee rate,” Taylor said. “That fee will not be as adequate as previously thought.”

ERCOT has maintained a system admin fee of 55.5 cents/MWh since 2016. It had projected increasing the fee to 66.5 cents/MWh in the 2024-2025 budget.

Staff reported a preliminary negative net variance of $25.5 million for 2021, with system admin fees coming in $10.9 million under expectations because of less energy sold. The grid operator had projected 413.1 TWh of energy sales in 2021, only to see 393.3 TWh of energy sold.

Expenditures were $14.4 million overbudget, primarily because of outside legal services, hardware and software support and maintenance, higher insurance premiums, and professional consulting.

ERCOT has operated with a biennial budget since 2014, at the Public Utility Commission’s request. Its filed budget includes four additional years of forecasted numbers.

Board Approves Firm Fuel Product

The board approved three revision requests that cleared the TAC with dissenting votes, including a nodal protocol revision request (NPRR1120) that creates a firm fuel supply service (FFSS) designed to provide additional grid reliability and resilience during extreme cold weather. The NPRR also compensates generators that meet a higher resilience standard in the face of a natural gas curtailment or other fuel supply disruption.

The PUC has directed that the standalone, auction-based product be procured similarly to ERCOT’s black start program and serve as a stopgap should weatherization not be incorporated into a load-serving entity’s obligation.

- - OBDRR039: removes FFSS-deployed resources’ high sustained limits from the ORDC’s reserve calculation.
  - PGRR095: establishes minimum deliverability criteria over the entire real power capability range of each ERCOT resource whose output is primarily within the grid operator’s control through dispatch instructions.

The directors also approved eight additional NPRRs, a Nodal Operating Guide revision (NOGRR), three more OBDRRs, single changes to the Planning Guide (PGRR) and the Retail Market Guide (RMGRR), and three system change requests (SCRs).

- - NPRR1095: contains revisions that the Texas Standard Electronic Transaction (Texas SET) Working Group has determined are necessary to support the Texas SET V5.0 improvement list.
  - NPRR1097: creates reports posted three days after each operating day that document forced outages, maintenance outages and forced derates of generation and energy storage resources.
  - NPRR1098: establishes reactive power capability requirements for new DC ties interconnecting to the ERCOT system and existing DC ties replaced after Jan. 1.
  - NPRR1099: grants ERCOT greater authority to move a resource node in the network operations model when deemed necessary to properly reflect point-of-interconnection (POI) changes or resource retirements.
  - NPRR1102: allows ERCOT to adjust back-casted non-interval data recorder load profiles.
  - NPRR1111: expands the use of the security-constrained economic dispatch (SCED) base point below the high dispatch limit flag to signify that ERCOT has instructed an intermittent renewable resource (IRR) or DC-coupled resources not to exceed its base point.
  - NPRR1113: adjusts the real-time ancillary service imbalance payment/charge’s definitions to prohibit double-counting of the regulation-up schedule when calculating capacity in the imbalance settlement for controllable load resources available to SCED.
  - NPRR1114: establishes processes to assess and collect securitization uplift charges to qualified scheduling entities representing LSEs pursuant to one of the PUC’s two debt obligation orders (52322).
  - NOGRR234: revises the guide to be consistent with NPRR1098’s reactive power capability requirements for DC ties, specifying DC tie operator responsibilities related to real-time operational voltage control.
  - OBDRR034: allows ERCOT to move network operations model resource nodes for POI changes or resource retirements.
  - OBDRR037: caps the power balance penalty curve at $5,001/MWh (the HCAP plus $1/MWh), effectively setting the curve’s price at its maximum value when violations are above 100 MW. The measure also reduces the generic transmission constraint shadow-price cap for base case voltage violations from $9,251/MW to $5,251/MW. Gray box language describes how the curve will work with the new HCAP upon real-time co-optimization’s implementation.
  - OBDRR038: updates the ORDC’s minimum contingency level to 3,000 MW within the relevant methodology document.
  - PGRR099: provides that an entity will not be eligible to begin or maintain a generator interconnection or modification (GIM) if it or any other owner of the project meets any of the company ownership (including affiliations) or headquarters criteria listed in the state’s Lone Star Infrastructure Protection Act. Any entity that seeks to initiate a GIM will be required to submit an attestation confirming that it does not meet the statutory criteria.
  - RMGRR169: updates the Texas SET’s continuous service agreement (CSA) bypass validations at ERCOT; allows for rejection of move out (MVO) transactions if the CSA owner and MVO competitive retailer (CR) do not match; allows ERCOT to issue a move in transaction for the appropriate CSA CR when an MVO is submitted; and revises the inadvertent gain process to align with SCR817’s proposed MarkeTrak enhancements.
  - SCR816: unlocks congestion revenue right bid credit on the same day auction results are posted.
  - SCR817: adds validations/requirements to existing MarkeTrak subtypes, revises existing workflows and suggests new subtypes to align with current market practices for more efficient issue resolution.
  - SCR819: improves dispatch of base points to resources to account for ramping un-curtailed IRRs.

March 10, 2022

Green Hydrogen Bill Passes Wash. Legislature

A bill is headed to Washington Gov. Jay Inslee to create a new state office to support development of green hydrogen and other alternative fuels.

The state Senate unanimously approved Senate Bill 5910 on Wednesday, after the House passed it Monday 96-2 with some minor tweaks.

“Renewable hydrogen is an exciting part of our future,” bill sponsor Sen. Reuven Carlyle (D) said prior to Wednesday’s floor vote.

The bill appears to boost Washington’s prospects to receive money from the federal Infrastructure Investment and Jobs Act to create one of four regional hydrogen hubs in the nation. (See Fast-moving Bill Seeks to Win Hydrogen Hub for Wash.)

The proposed Office of Renewable Fuels in the Washington Department of Commerce would collaborate with other state agencies to accelerate market development of renewable fuel and electrolytic hydrogen projects along their full life cycle, in part by supporting research and development around production, distribution and end uses. It would also identify ways to best deploy the fuels to support the state’s climate change mitigation and adaptation efforts.

The new office is also expected to help boost job creation while partnering with “overburdened” communities to ensure they benefit from clean fuels development. It would also review the state’s existing renewable fuels and hydrogen initiatives and support public-private opportunities that encourage adoption of clean fuels. The office is expected to coordinate its efforts with local state and federal governments, the private sector and universities.

The bill would also allow proposed hydrogen production projects the choice of applying for permits from the state Energy Facility Site Evaluation Council, rather than local governments. (See Bill to Expand Powers of Wash. Siting Council Passes Senate.) It would also authorize municipal utilities and public utility districts to produce, use, sell and distribute hydrogen and other renewable fuels.

The legislation could help Washington land one of the four hydrogen hubs outlined in the IIJA, enacted last year. The federal law allocates $8 billion for the creation of at least four hydrogen hubs across the country, as well as $1 billion for the domestic manufacture of the electrolyzers needed to convert water to green hydrogen. The U.S. Department of Energy will solicit proposals for the hubs until May 15 and select the four sites a year later.

Washington has one hydrogen production plant under construction near East Wenatchee, which will use Columbia River water as its source. The plant, to be operated by Douglas County Public Utility District near the Wells Dam, is scheduled to go online late this year. A hydrogen fueling station is on the drawing board for near East Wanatchee, and another is in the works for public transit buses in Lewis County, about 25 miles south of Olympia.

March 10, 2022

Power Plant Emission Rules Up in the Air as Technologies Change

The battle over federal rules controlling power plant emissions is heating up again as the Biden administration’s EPA prepares to issue revised regulations by the end of the year.

The agency is developing the rule even as the Supreme Court considers an appeal of rules issued by the Trump administration and thrown out by the D.C. Circuit Court of Appeals. The high court listened to oral arguments two weeks ago and is expected to issue an opinion in June. (See Supreme Court Hears Arguments on EPA Authority Over GHGs.)

Some of the same issues that cropped up in the Obama administration’s Clean Power Plan (CPP), finalized in 2015, may persist: “beyond the fence line” emission rules, generation shifting, and the even trickier standards promulgated in the Affordable Clean Air Energy (ACE) rule issued by the Trump administration in 2019 for heat rate efficiency.

In a webinar produced Wednesday by D.C.-based OurEnergyPolicy, four of the industry’s top legal minds examined some of these issues.

“I think [among the] things that are being discussed even while we wait for the decision is what should EPA base the standard on,” said Carrie Jenks, executive director of Harvard University’s Environmental and Energy Law Program.

“The power sector has changed [since] the Clean Power Plan was designed and also when ACE was designed. And how does EPA look at that what has happened with technologies? What’s the basis for the standard? What should companies and states be allowed to do in terms of complying with that standard?” she said.

Emily Sanford Fisher, general counsel for the Edison Electric Institute, also noted that technologies have changed since the CPP was introduced.

“Actually quite a lot has changed. One way to think about it is that the Clean Power Plan was aiming to achieve a 32% reduction in industry-wide emissions by 2030. And at the end of 2020, as an industry we were at 40% below 2005 levels.

“So obviously something that EPA in 2015 thought we wouldn’t be able to achieve until 2030 we accomplished without the Clean Power Plan and actually before it even would have taken effect,” she said, adding that the Obama administration gave the industry until 2022 to achieve the lower emissions.

The growth of renewable energy, which Sanford-Fisher noted “is a very competitive form of generation,” and state renewable portfolio standards have also been responsible for making the industry cleaner, she said.

Another factor that changed total emissions was the Obama administration’s decision to issue the final Mercury and Air Toxics Standards, which led to the retirement of about a third of the coal fleet, she said, adding that about 50 of the 65 member companies in EEI have long-term commitments to continue to reduce emissions.

Ben Longstreth, senior attorney with the Natural Resources Defense Council, said he “concurred entirely” with Fisher but added that the emphasis should not be taken off the power sector because it will become even more important as the number of electric vehicles grows.

He also said that EPA is facing mandates that Congress put into the original law.

“NRDC always had a program thinking about the conventional air pollutants — the SO_x, NO_x, mercury — and while the sector has improved a lot, [the pollutants] remain significant,” he said.

March 10, 2022

WECC Sets May 1 Target for Resumption of In-person Meetings

WECC is planning to resume in-person meetings at its Salt Lake City headquarters, asking for “grace” as it plots a way to accommodate all stakeholders, CEO Melanie Frye said Wednesday.

“March 23 actually marks the two-year anniversary of us closing the WECC office,” Frye said during a quarterly meeting of WECC’s Board of Directors.

She pointed out that the regional entity’s last in-person event was the March 2020 board meeting, held just before the COVID-19 pandemic drove office workers into quarantine and established widespread use of remote working and virtual meetings.

WECC will retain elements of that now well-established practice in its approach to stakeholder gatherings, adopting a “hybrid” model of face-to-face meetups with the continued option of participating virtually, Frye said.

“Beginning May 1, we’ll start to consider on a case-by-case basis moving to hybrid meetings, which probably will be our new normal at work,” she said. “We know that many companies are still in limited travel arrangements, so as we contemplate having technical committee meetings, we know there will probably always be an element that is hybrid, with people remotely participating and, [for] those who are able to travel, in person.”

In a roundtable discussion during a meeting of the WECC Member Advisory Committee on Tuesday, stakeholders expressed a desire to get back to in-person meetings as their states and employers begin relaxing pandemic restrictions.

“Our policy is allowing for travel where appropriate, and we would love to see it happen,” MAC member Brian Evans-Mongeon, president of Utility Services, said.

Russell Noble, reliability compliance manager at Cowlitz County Public Utility District in Washington, said the “last vestiges” of his state’s COVID regulations would be expiring March 12. “We are looking towards getting back to normal and definitely be allowed to make necessary travel arrangements for necessary meetings.”

But WECC’s Canadian members still face uncertainty about crossing the border into the U.S., said Diana Wilson, director of enterprise risk management and compliance at the Alberta Electric System Operator. “I think it’s going to really have to be a matter of how things unfold,” she said.

Frye asked for forbearance as WECC attempts to transition to hybrid meetings.

“The final point I’ll make is just to really ask grace as we start to implement hybrid meetings,” Frye said. “We’ll be evaluating the technology that we have in our meeting rooms, [and] it will be something new and different to have a combination of in-person participants and remote participants. So there may be some technology bumps along the way, and we’ll keep learning and evaluating what we might need on our end to provide the best experience for all of our stakeholders.”

Restrictions Relaxed, FlexWork Begins

Frye on Wednesday also informed the board that WECC will begin welcoming all staff to return to the Salt Lake City office on April 4, relaxing existing limits on the number of people allowed to work in the building on any given day.

“We have announced to our employees that we think now is the time to start to transition to our FlexWork — new normal — that we’ve developed,” Frye said.

WECC announced its decision to implement the new FlexWork program last June. The program is designed to give most employees the option to work from home, while also holding out the requirement that they might need to put in “core hours” at the office to attend trainings, committee meetings, regulatory audits and board meetings. FlexWork was postponed in September as the Delta variant fueled a surge in COVID cases.

“Our FlexWork program is a strategic business initiative that provides flexibility in work schedules that best fits WECC’s business objectives and expectations, and fulfills individual and team needs on the job in a collaborative and flexible work setting,” Julie Booth, WECC manager of communications and outreach, told ERO Insider Wednesday.

With the rollout of the program next month, WECC will lift current pandemic-related restrictions, including the 50% cap on attendance, the requirement to use the ClearPass application to sign in to work a day in advance to provide a health attestation and the need to wear a mask.

“For FlexWork, we will keep in place extra cleaning measures, hand sanitization stations and mask wearing when requested,” Booth said.

March 10, 2022November 14, 2023

New Yorkers Support 10-GW Solar Target — with Reservations

Consumers, environmentalists, utilities, developers and labor organizations expressed support for New York’s plan to expand state solar incentives by $1.5 billion through 2030, but many are concerned with who pays, how much, and how often (Case No. 21-E-0629).

The groups filed comments in response to the Public Service Commission’s roadmap for achieving 10 GW of distributed solar by the decade’s end. Installed distributed solar and projects under development already total more than 93% of the previous state goal of 6 GW by 2025. The roadmap defines distributed solar as including residential, non-residential and commercial/industrial projects, including community distributed generation, distinguishing them from utility-scale projects (greater than 20 MW). (See New York Issues 10 GW Solar Roadmap for 2030.)

McGowan Southworth, a solar advocate and consultant said owners of small buildings that have taken out solar loans tied to the value of solar production under the NY-Sun program will not be able to make monthly loan payments if Con Edison doesn’t distribute value stack credits accurately and consistently.

“This would in turn harm their credit [and] also erodes fragile trust between the end customer and all parties related to solar, utility and PSC included,” Southworth said. “Would the PSC allocate funds for auditing community solar accounts on behalf of subscribers who are otherwise bearing this cost and administrative headache?”

Cost Concerns

New York utility customers already are overburdened and contribute billions of dollars annually to a large and rapidly growing list of customer-funded programs and initiatives, said Multiple Intervenors (MI), an ad hoc group of more than 50 large commercial, industrial and institutional energy consumers.

The state’s economy is continuing to experience the disruptive impacts of the COVID-19 pandemic, as well as energy prices that have skyrocketed this year, the group said.

MI asked for scrutiny of costs, as it did recently regarding National Grid transmission projects proposed for western New York. (See Large NY Consumers Oppose National Grid Tx Upgrades.)

“The solar roadmap fails to demonstrate why certain proposed costs, such as supplementing the labor costs of solar developers, even should be funded by utility customers,” MI said. “The commission … should evaluate such proposals collectively with the other programs and initiatives that customers already are being required to fund. This type of comprehensive evaluation is long overdue and should be undertaken expeditiously.”

C/I projects sized between 1-5 MW occupy an important space in New York’s solar portfolio, with economies of scale producing lower development costs compared to residential rooftop and small commercial sectors. | NYSERDA

New York City said it supports expanding incentives, noting that for Con Edison customers, the average bill impact in 2024 — the year of highest impact — is estimated to be 0.52% for residential customers and 0.97% for commercial and industrial (C&I) customers.

“The estimated bill impacts are modest and reasonable when weighed against the benefits that customers should realize in return for their investment,” the city said. Solar developer Ecovis Group said the rules requiring the payment of prevailing wages for distributed energy resources over 1 MW will tax the finances of small local companies.

“We are asking the PSC to add requirements for monthly progress payments to the contractors for work completed the previous month. This will help to offset cash flow changes,” Ecovis said. “Developers are going to receive additional funds through [New York State Energy Research and Development Authority] grants; however contractors will bear the brunt of the cash requirement.”

Climate Jobs NY, a coalition of labor unions representing 2.6 million workers in the state, said it supports the program expansion, which the state says should create 6,000 new jobs.

Developer Incentives

The New York Power Authority said it supports the roadmap, but that uncertainty around the availability of future incentives has caused customers working with NYPA to hesitate on committing to new projects.

“This observation is particularly pronounced amongst customers in Con Edison’s service territory, where project economics are challenging due to high labor and installation costs, along with the siting constraints inherent to the region’s dense urban environment,” NYPA said.

A group of environmental organizations including Scenic Hudson, Natural Resources Defense Council and the Sierra Club said that NY-Sun should include an incentive for projects that include agrivoltaics — the co-location of solar-powered projects and agriculture — similar to those for landfill, brownfields and parking canopy projects.

“Providing such incentives in the NY-Sun program will have several benefits, including achieving distributed solar targets, supporting the agricultural economy, and promoting community acceptance of projects in rural and farming communities that might otherwise object to projects as a threat to farmland and community character,” the environmentalists said.

The Joint Utilities, representing the investor-owned utilities in New York, said they are developing a pilot to bring more solar energy to underserved communities in support of the state’s expanded target.

“In addition, the mid-point review should explore more funding sources and evaluate incentive levels so that necessary modifications can be made before funding is exhausted,” the utilities said.

New York City said Con Edison deserves a bigger slice of the incentive pie, given its outsize share — 39.6% — of total electricity sales in the state.

The city supports the proposal to segment Con Edison incentives based on system size, which will ensure that smaller projects can continue to be built.

The city recommended, however, that the commission modify the roadmap’s proposals for Con Edison and create three tiers of incentives for non-residential projects versus the proposed two tiers. The city also called for reducing the base incentives for non-residential projects to encourage up to 568 MW of new distributed solar in Con Edison’s territory. It also said the state should re-allocate some of the base incentive dollars to increase the proposed community adder for community solar projects in Con Edison’s territory.

Community organizers WE ACT for Environmental Justice said that “a proposal of this size, without comprehensively planning for equitable outcomes, could do more harm than good,” and that the investment must comply with the statutory requirement that disadvantaged communities receive 40% of overall benefits of state spending on clean energy and energy efficiency programs.

“Right now, the only benefit being accounted for and attributed to disadvantaged communities is bill discounts of 10%. The benefits of distributed solar are plentiful, and bill discounts are one very small piece of that pie,” said WE ACT policy director Sonal Jessel.

March 10, 2022

Stakeholders Divided on MISO Long-range Cost Allocation’s Fairness

MISO’s subregional cost-allocation plan for its long-range transmission projects had both fans and critics at FERC this week.

The RTO has proposed a 100% postage stamp allocation to load for the long-range projects, limited to two of its subregions, in a filing at FERC. Entities had until Monday to file comments, protest or intervene (ER22-995).

Industrial customers denounced the cost recovery plan, arguing against the sub-regional allocation for yet-to-be-determined projects. Consumers Energy said it was concerned that the grid operator hadn’t yet shared specific calculations of benefits for actual projects.

Others said the RTO’s separate-but-equal allocation application is inherently unequal.

MISO hopes to have the allocation plan, limited to its Midwest and South regions, in place by mid-May. The first long-range projects, all in MISO Midwest, are targeted for board approval in June.

WPPI Energy said if FERC accepts the filing, it should “prevent” MISO from violating the commission’s cost-allocation principles by requiring the RTO to explain when it will use a subregional versus region-wide cost recovery. The grid operator should also defend its strategy to use a different allocation design for the final two cycles of projects in its long-range transmission plan, WPPI said. The utility said it might be unfair to employ a different cost allocation once MISO begins planning long-range projects in its South subregion.

The recovery design relies in-part on a Brattle Group analysis that shows Midwestern projects are unlikely to produce benefits that seep into MISO South unless the subregional transmission transfer capacity limit is increased. Multiple stakeholders have said they’re hopeful that the long-range planning effort’s third and fourth cycles produce a project that broadens transfer capability between Midwest and South.

Staff have repeatedly said the RTO’s postage stamp rate separated by subregion is meant to be temporary and only applies to the first two project cycles. The grid operator has already begun stakeholder talks on a more permanent allocation design. (See MISO Seeking New Tx Cost Allocation for Major Buildout.)

Other stakeholders told FERC the plan represents the best option for now.

Americans for a Clean Energy Grid said the cost allocation design will confront an “existing roadblock to regional transmission development.” The group said FERC should permit flexibility in cost allocation “if it enables regions to gain stakeholder support for new transmission expansion.”

NextEra Energy said it “strongly supports” the proposal because it’s a step toward developing necessary transmission infrastructure.

The Organization of MISO States said it supported both the bifurcated postage-stamp approach and the plan to create a new allocation methodology for the second half of long-range projects.

DTE Electric said the establishment of two separate cost-sharing subregions is appropriate because it follows FERC’s “roughly commensurate” benefits standard for allocation.

DTE also asked that MISO include tariff language that ensures staff and members also consider customer affordability when planning new transmission.

“Customer affordability metrics should be established and used as a tool in the planning process to ensure that transmission investment is financially feasible for customers across the entire MISO footprint,” DTE wrote.

Entergy, which accounts for the lion’s share of MISO South, also supported the filing. The utility said although the plan was “not perfect,” it characterized a compromise among stakeholders. Entergy also noted that MISO Midwest “is clearly at the forefront of the portfolio transition that MISO describes as a driving force behind” its long-range transmission plan.

Chairs of the Senate and House energy committees in the Minnesota legislature wrote to “stress the urgency of MISO’s long-range transmission planning process to affordably allow carbon-free energy to be built at the scale required and demanded in Minnesota.” They said the state’s utilities, including Xcel Energy, Great River Energy and Minnesota Power, “are some of the most forward-looking utilities on clean energy in the country.”

March 10, 2022June 14, 2023

ISO-NE Announces Capacity Auction Results After Killingly Delay

Capacity prices in Southeast New England fell to $2.639/kW-month in Forward Capacity Auction 16, a 34% decrease from last year’s auction, ISO-NE reported Wednesday. The total cost of the FCA 16 was $1.04 billion, a $320 million (24%) drop from 2021.

ISO-NE said the auction procured 32,810 MW of capacity for the 2025/26 period.

Prices were mostly flat outside of the Southeast zone, coming in at $2.531/kW-month in Northern New England and Maine, and $2.591/kW-month in Rest of Pool.

“New England’s clean energy transition is well underway, and the region’s wholesale markets are playing a vital role by sustaining a reliable power system, maintaining competitive prices and creating opportunities for the resources that will be the backbone of our clean energy future,” said Robert Ethier, ISO-NE’s vice president for system planning.

Nearly 5,000 MW of renewables, energy storage and demand resources cleared the auction, making up 15% of the total capacity, ISO-NE said. That includes more than 700 MW of energy storage, 500 MW of solar generation and 275 MW of existing wind generation.

Resources worth 256 MW submitted retirement bids, all of which cleared, and 1,540 MW worth of generation was delisted.

No Delist for Merrimack Power

The owner of New England’s last active coal plant, Merrimack Station, submitted a static delist bid, seeking to remove its two units from the capacity auction if prices dropped below a certain point (the dynamic delist bid threshold).

But the bid was rejected by ISO-NE’s Internal Market Monitor, which reviews delist requests, and subsequently withdrawn by the operator of the plant.

Resources successfully submitting retirement bids included Potter II, a 96-MW combined cycle plant owned by Braintree Electric Light Department; two units at Schiller Station in New Hampshire, which shuttered in 2020; and two units burning kerosene and gas at the West Springfield Generating Station.

Information about which individual resources cleared the auction will be published when ISO-NE sends its filing to FERC, expected to occur as early as next week.

A Disjointed Process

The results were delayed by several weeks because of the uncertainty over the Killingly Energy Center, which won a last-minute stay from the D.C. Circuit Court of Appeals allowing it to temporarily take part in the auction. (See Killingly Uncertainty Could Delay Capacity Auction Results Another Month.)

ISO-NE ended up tallying results both with and without Killingly participating, and when the Connecticut natural gas plant under development by NTE Energy ultimately lost its appeal at FERC and forfeited its financial assurance, the grid operator was able to confirm that it would be using the results without the plant.

Killingly’s exit from the market had an effect on the auction’s outcome, said Dan Dolan, president of the New England Power Generators Association.

Prices dropped sharply in Southeastern New England in FCA 16 vs. FCA 15, pushing overall costs down by nearly one-quarter. | ISO-NE

“We saw with the removal of Killingly less supply than the prior year’s, and when matched with the lower demand this year versus FCA 15, it led to relatively flat pricing overall,” Dolan said. “There are continued historically low capacity prices across the board.”

NEPGA’s members have been frustrated with the uncertainty created by the Killingly delay, Dolan said, but they are relieved that the results have been released and that the grid operator is working quickly to start the process for next year’s FCA 17.

“There is a feeling of ‘we can make this work.’ This is now a manageable timeline and process overall,” he said.

March 10, 2022November 15, 2023

New Jersey Tees up Funding, Guidebook to Boost EV Charger Installations

New Jersey plans to boost the number of EV chargers in the state with $4 million in funding from the Volkswagen settlement and a new guidebook to help municipalities efficiently move proposed charging stations through the permitting process.

The money — part of the state’s share of the carmaker’s settlement for false reporting of vehicle emissions — will go to the New Jersey Department of Environmental Protection’s (DEP) It Pay$ to Plug In program for a second round of grants that will add conveniently located charging sites to the 636 public chargers already installed and in operation across the state.

The DEP will start accepting applications on Monday for awards that can be used to install Level 1, Level 2 or DC fast chargers. The deadline for applications is May 14.

The state’s new, 28-page guidebook, “Charge Up Your Town: Best Management Practices to Ensure Your Town is EV Ready,” is intended speed up those installations by helping towns and cities evaluate EV charger projects and expedite their permitting. The book was put together by the DEP, the New Jersey Board of Public Utilities (BPU), the New Jersey Department of Community Affairs and stakeholders, including two independent transportation agencies.

“With this guide, we are equipping towns with a roadmap to help develop cost-effective EV charging infrastructure,” said Lt. Governor Sheila Y. Oliver, in a Tuesday release announcing the guidebook’s publication. “Taking these steps is part of our administration’s larger strategy to help the state meet its climate goals.”

The DEP expects the Plug In program to award between 20 and 53 grants that will cover the cost of installing and maintaining Level 1 and 2 chargers and DC fast charger projects. Eligible locations include public areas, multi-unit dwellings and private sites, such as workplaces, with a maximum grant of $200,000 per location.

Gov. Phil Murphy has committed $10.8 million, or about 15 percent of the state’s share of funds from the Volkswagen settlement to the installation of electric charging stations. The first round of It Pay$ to Plug In awarded $3.2 million in grants to install 535 chargers with 842 ports in four counties and more than 40 municipalities. Funded projects — not all of which may be complete and in operation yet — are located at public sites, multi-family housing and workplaces.

The manual includes sections detailing different types of chargers and what they are used for, how to reduce the time and effort needed to ensure charging stations meet zoning, construction and building permit requirements, and the varied fee structures charging stations can use to generate revenue.

The introduction to the guide states that it is “intended to help municipal staff and their communities understand the context for the statewide EV ordinance, and the considerations relevant to municipalities as they take steps to support the state goals of increasing access to electric vehicle charging infrastructure.”

EV Charger Targets

Charger availability is key to Murphy’s goal of converting the state to 100% clean energy by 2050, and dramatically cutting emissions from the transportation sector, which generates 43% of the state’s greenhouse gas emissions.

The state wants 330,000 passenger and light-duty EVs on the road by 2025. The targets for chargers are at least 400 DC fast chargers at 200 or more locations and at least 1,000 Level 2 chargers — those with a 240-V electricity source — by December 2025.

In addition, a state law passed in 2020, S2252, sets a deadline of December 2025 for having at least 100 charging sites in community locations, such as such as a town centers, commercial areas, retail centers and multi-unit dwellings.

A network of chargers spread evenly across the state would help to assuage the concerns of prospective EV drivers who might be reluctant to buy battery-powered cars due to concerns that the batteries might run out with no charger nearby.

That need for “geographic distribution” across the state means that the location of a proposed site will play a big part in whether a proposed DC fast charger site will get second-round funding, Andrea Friedman, supervisor in the DEP’s electric vehicle program told a recent online seminar held to explain the program to potential applicants.

“We want them to be convenient, and we want them to be visible in communities,” she said. “We want to give people the confidence to go out and buy electric vehicles because they know there will be chargers nearby.”

Time is of the essence, she said.

“We’re looking for projects that are shovel-ready,” she said. “What that means to us is that you will be able to begin the process as soon as the DEP makes the award. If you’re planning a project that can’t be installed for two or three years, that won’t work for this grant program.”

State Charger Incentives

The It Pay$ to Plug In program is the latest of a raft of state and federal initiatives designed to boost the availability of chargers in New Jersey.

The federal Joint Office of Energy and Transportation rolled out the first round of state funding for EV charging from the bipartisan Infrastructure Investment and Jobs Act in February, with New Jersey slated to receive more than $15.4 million in 2022. To qualify for the funds, the state will be required to submit a plan detailing how it will use the money. (See States to Get $615 Million for EV Charging from IIJA Funds.)

In parallel, the BPU is pursuing two straw proposal processes, one to set out the rules to induce private investors to install Level 1 and Level 2 chargers around the state and another to deploy chargers for medium- and heavy-duty electric vehicles.

In September, the board also launched a $4 million incentive program to install chargers on main traffic corridors and at tourist hotspots, especially at the Jersey Shore, to attract more visitors to the state.

And in December, the BPU authorized a program to promote the installation of chargers in multifamily buildings by offering a $1,500 incentive for Level 2 chargers installed in apartment, condominium or mixed-use residential buildings. The program also will pay half of the project’s “make-ready” costs — for installing the wiring required for a charger — up to a total of $5,000.

Murphy in July signed two bills designed to make it easier to set up electric vehicle charging stations. One made the installation of electric vehicle supply equipment or a make-ready parking space a permitted use under municipal zoning laws, removing the sometimes lengthy and expensive task of getting a zoning variance to install a charger. The second bill required that any redevelopment plan approved by a municipality must include EV charging infrastructure as part of the planning for the redevelopment or rehabilitation of the area. (See NJ Cuts Permitting Obstacles for EV Charging Stations.)

Picking ‘User Friendly’ Locations

The Plug In program awards grants in two tracks, one to cover costs to purchase and maintain Level 1 chargers (120 V) with up to five ports, and the second for Level 2 chargers (240 V) with at least two charging ports. The program will offer up to $750 per Level 1 port and up to $4,000 per Level 2 port in a “first come, first served” system, the DEP’s Friedman told the online seminar.

Grant awards for DC Fast chargers, which use a 480 V source, will be made in a separate, competitive solicitation, she said. These chargers must be in a “community location,” with maximum grants of $200,000 per location, according to the program rules.

The program will not fund the expansion of existing sites because the DEP wants to stimulate the deployment of chargers across the state. Fast charger applications must include plans for at least two 50 kW chargers that are “available exclusively to the general public,” Friedman said.

On top of that, she said, “they must be user friendly.”

“That means well-lit, open 24 hours a day, seven days a week all year round,” she said. “They must accept credit cards. They can use other forms of payment, but they must accept credit cards, and they must display pricing information.”

“We’re also very interested in locations with amenities within walking distance, maximum a quarter mile,” Friedman said. “The closer, the better. We’re looking for locations with bathrooms, food, coffee, retail. And the reason is: people will be spending 20 or 30 minutes or more at these sites, and we want them to have a good charging experience and have something to do while they’re at the chargers.”

March 10, 2022

EPA Restores California Tailpipe Standards

California and other states can again enforce tailpipe emissions rules that exceed federal regulations following EPA’s repeal Wednesday of Trump-era actions that revoked state authority to enact higher standards.

The decision also restored California’s mandate that all new passenger vehicles sold in-state must be emissions-free by 2035.

The Trump-era actions were “decided in error and are now entirely rescinded,” EPA said in a summary of its decision. “With this action, California’s authority under the Clean Air Act to implement its own greenhouse gas emission standards and zero-emission vehicle sales mandate is restored.”

Since the 1970s, California has had waivers from the federal government to adopt its own stricter vehicle emissions rules because of “compelling and extraordinary conditions,” including Southern California smog. In 2013, the state received its latest waiver under the federal Clean Air Act to pursue the state Air Resources Board’s Advanced Clean Cars program, with tough restrictions on greenhouse gas emissions and the zero-emission vehicle mandate.

Sixteen other states and the District of Columbia enacted the California GHG rules with federal permission.

In September 2019, the Trump Administration adopted the Safer Affordable Fuel-Efficient Vehicles Rule Part One: One National Program Rule (SAFE-1). Under SAFE-1, the National Highway Traffic Safety Administration declared that state regulation of carbon dioxide emissions from new cars intruded on federal regulation of fuel-economy standards and was preempted by federal law.

EPA withdrew California’s 2013 waiver based on NHTSA’s actions and its own interpretation that the state did not need its GHG emissions standards and zero-emission vehicle mandate to address the compelling and extraordinary conditions that had prompted the waiver. Interpretations of SAFE-1 also prevented other states from adopting California’s GHG emissions standards.

On his first day in office, President Biden issued an executive order directing federal agencies to review SAFE-1 and other Trump administration rulings. EPA said it was reconsidering the previous administration’s withdrawal of California’s waiver in April 2021, as EPA Administrator Michael Regan called the withdrawal “legally dubious.”

On Wednesday, Regan said, “We proudly reaffirm California’s longstanding authority to lead in addressing pollution from cars and trucks. Our partnership with states to confront the climate crisis has never been more important. With today’s action, we reinstate an approach that for years has helped advance clean technologies and cut air pollution for people not just in California, but for the U.S. as a whole.”

Environmental groups praised the decision, saying the cutting-edge actions of California and likeminded states had pushed automakers to produce lower-emissions vehicles nationwide.

“States have long been leaders in cleaning up tailpipe pollution, and the EPA is absolutely right to recognize this,” Luke Tonachel, director for clean vehicles and fuels at the Natural Resources Defense Council, said in a statement.

“While the previous administration tried to undermine this authority, the law clearly gives California and other states the ability to adopt standards to curb the pollution affecting the health of their citizens,” Tonachel said. “Reaffirming this legal authority will protect public health and help address the climate crisis.”

March 9, 2022June 14, 2023

Texas PUC Pushed on Reliability Charges

The one-year anniversary of ERCOT’s near grid collapse during last February’s disastrous winter storm was marked by a glut of reports, webinars and opinion pieces recapping what went wrong and detailing the changes made to ensure it doesn’t happen again.

Connect the Texas grid to the rest of the country, said an energy institute. Because about 61% of Texan households now use electric heat, a group of academics determined that ERCOT’s grid is more susceptible to cold weather. Another university study posited that 100% clean energy and renewable energy would prevent blackouts.

One politician said Texas fixed its problems quickly because it isn’t connected to the national grid, while another wrote that Texas is on the right track. An energy fellow at the University of Houston blamed the problems on the energy-only ERCOT market, which places all the risk on the consumer.

The truth is out there. Somewhere.

Yes, the grid has survived three cold snaps and an arctic front, but none of them was as severe as last year’s winter storm. The lights and heat stayed on, but not before raising anxiety levels among Texans still suffering from PTSD.

Alison Silverstein | Texas Tribune

During one of her many recent webinar appearances, energy consultant Alison Silverstein didn’t wait for questions on the grid’s performance, asking them of herself. She said the grid is in better shape than last year with “lots more to do” but that ERCOT’s performance during these latest cold-weather events are not proof that everything is fixed. (See ERCOT Breezes Through Latest Winter Storm.)

“Absolutely no,” Silverstein said during a panel discussion last month set up by Advanced Power Alliance. Last month’s weather “was not enough of a stress test to really show that the grid is better.”

ERCOT’s regulator, the Public Utility Commission of Texas, has made several major changes, directed by the numerous power-related bills lawmakers passed last year. Power plants have been ordered to winterize, with ERCOT conducting inspections and the PUC penalizing those that have failed to comply.

The commission has also lowered the price cap from $9,000/MWh to $5,000/MWh; the previous commission set prices at the old cap for four days during last year’s storm, resulting in $45 billion in market transactions that week and several bankrupt participants. Ancillary service prices have also been limited after last year, part of several tweaks around the edges in what is called Phase 1 of the market improvements.

At the PUC’s prodding, ERCOT has been practicing a “conservative” approach to operations, calling on more reserves more quickly and increasing the number of reliability unit commitments (RUCs). London Economics said in a recent study that 96% of the RUCs last year were to maintain additional online reserves and not for resolving local issues.

“That is a good thing in terms of having more resources ready to operate, but we’re also paying a bundle to make that happen, and we haven’t had any public accounting of that those costs yet,” Silverstein said.

Partnering with the Texas Consumer Association, Silverstein filed a petition with the PUC asking it to direct ERCOT to calculate the costs spent on grid reliability. The filing says the reliability costs, along with a 36% increase in natural gas prices from April 2020 to February 2022 and new charges for securitizing generator and retail electric providers’ losses during the storm, “are being passed through higher electric bills” to the 27 million individuals the grid operator serves.

“The rough information available in the PUCT proceedings to date suggest that costs could exceed several billion dollars for past [Winter Storm] Uri costs (which will not improve future reliability) and at least another billion for recent reliability improvements,” Silverstein wrote.

During a one-on-one interview with PUC Chair Peter Lake as part of a weeklong virtual symposium, “The Winter Storm, One Year Later,” Texas Tribune CEO Evan Smith said he had been told ERCOT had spent $25 million procuring reserves during one day of the arctic front and as much as $500 million since the middle of last year.

Asked to confirm the numbers, Lake deferred to ERCOT.

“I don’t know the numbers off the top of my head, but yes, more reliability costs more … and we know we need more reliable power in Texas,” Lake said.

Doug Lewin 2022-03-02 (RTO Insider LLC) FI.jpg

Stoic Energy President Doug Lewin harkened back to ERCOT CEO Brad Jones’ September testimony to the state Senate Business and Commerce Committee. Asked about the RUC costs, Jones estimated that they were $40 million/month during the summer.

“That’s a lot of money for consumers to shoulder, potentially a 5 to 10% surcharge on top of already higher bills,” Lewin said. “These numbers are rough estimates. I’d love to replace them with more accurate figures, but we need transparency from ERCOT and the PUC on these costs.”

Lewin estimated $1 billion in additional reliability costs, assuming ancillary service costs have gone up two or three times from 2020’s $381.5 million bill and $50 million in monthly costs since the summer.

On Tuesday, Jones told RTO Insider that those numbers are way off. He pointed out that the $40 million was the cost during summer months for all ancillary services and said that ancillary costs were $270 million from last summer through early February.

“To put that into context, that’s less than $1 a customer per month, on average,” Jones said.

He said staff assumed 380 million MWh of energy production in ERCOT, with the average consumer using about 1 MWh/month in deriving the figure, with RUC costs being “shockingly low.”

ERCOT’s annual RUC report shows there were 3,853.1 effective RUC resource-hours in 2021, up from 220.1 in 2020. Total RUC make-whole payments were about $5.3 million last year and were covered through capacity short charges, staff said, with about $3.1 million in excess profits clawed back from generators. In 2020, those numbers were about $404,000 and $484,000, respectively. (See “RUC Usage Skyrockets,” ERCOT Technical Advisory Committee Briefs: Jan. 31, 2022.)

“These actions have also moved us significantly toward a capacity market since these are mostly out-of-market capacity payments,” Lewin said. “Whatever you think about capacity markets, those decisions should be made with transparency, not by opaque regulatory changes.”