Page 999 – RTO Insider

January 10, 2021

Competition, Flexibility Sought for New NJ Solar Initiatives

New Jersey’s new solar power incentives program should use competitive solicitations to minimize costs and differentiate between project types and locations to ensure “a robust and diverse fleet,” consultants recommended to the Board of Public Utilities on Friday.

The BPU commissioned The Cadmus Group to produce the “New Jersey Solar Transition Final Capstone Report” in response to the Clean Energy Act of 2018 (AB-3723), which required the state to replace the Solar Renewable Energy Certificate (SREC) market with a lower-cost program to encourage solar development.

Ariane Benrey, program administrator, presented the report at a meeting Friday, where the BPU also approved two measures related to the state’s offshore wind projects and Public Service Electric and Gas’ (PSE&G) $778 million smart meter deployment (EO18101115). PSE&G will be the second utility in the state to install smart meters, following Rockland Electric. Smart meter proposals by Jersey Central Power & Light and Atlantic City Electric are pending before the BPU.

State of Transition

The Clean Energy Act required that the SREC program close once solar totals 5.1% of electricity sales, a threshold the state hit in April 2020. (See Solar Subsidy Program Ending in New Jersey.)

An interim, “transition” program took effect in May for projects registered with the state by the 5.1% milestone date but not yet operational, as well as projects registering after the milestone but before implementation of the successor program that is the subject of the capstone report.

Renewable energy credits (RECs) under the transition program range between $91.20 and $152/MWh, compared with an average of $214/MWh during the last five years of the SREC program, according to the state.

Under New Jersey’s 2019 Energy Master Plan, in-state solar would comprise 34% of the state’s electric generation by 2050 as part of Gov. Phil Murphy’s midcentury goal of 100% “clean energy.” The plan seeks 5.2 GW of in-state solar by 2025, 12.2 GW by 2030 and 32 GW by 2050.

The state registered about 3,476 MW of solar under the SREC program and estimates about 700 MW will be added under the transitional incentive, leaving about 8,020 MW to be filled under the successor program by 2030.

For the successor program, Cadmus recommended the BPU implement a fixed-incentive program, similar to the transition incentive, to “provide strong certainty, business visibility and especially ‘finance-ability.’” It said the fixed incentive would complement net metering incentives in the near term and could evolve into a “total compensation” program “to reflect more holistically the value of these projects to the market, grid and environment.”

It said the new program should ensure flexibility through a timetable of re-evaluations and potential revisions “while providing the industry with enough line-of-sight to enable long-term investment.”

The largest solar projects should receive incentives based on competitive solicitations, with administratively set incentives for smaller projects, Cadmus said. “This will enable market price discovery while establishing minimum incentive levels.”

The consultants also urged the use of megawatt-based targets that consider historical trends and segments that may have been underutilized in the past, such as commercial rooftops, solar carports and front-of-the-meter “grid supply” projects.

They also recommended differentiating between project customer classes, installation types, locations and technologies, noting that “variations in tariffs and interconnection costs across electric distribution company service territories, along with differences in construction costs between solar installation types, can have significant impacts on overall project economics.”

The BPU should order a study on the state’s total feasible capacity for solar, Cadmus added. “New Jersey was an early leader in solar in the United States and has developed a robust market. That relatively long history of success in installations, however, suggests that the developer community has likely spent significant time prospecting for optimal projects and that some of the best opportunities for solar may have been taken already for various project types or otherwise did not work under existing market structures,” it said.

NJ Solar — The Six Flags Great Adventure amusement park in Jackson, N.J., is mostly powered by a 23.5-MW solar project. | *Six Flags*

‘Total Compensation’ vs. Fixed Incentives

The “total compensation” incentive, like the Solar Massachusetts Renewable Target (SMART) program, acts like a contract for differences between the value of energy and the total compensation paid.

One advantage of the SMART program, Cadmus said, is that it includes adders and subtractors to encourage a diversity of project types and discourage large-scale, ground-mounted projects in undeveloped spaces. Projects on landfills, parking lots and in “dual-use” agriculture — growing crops such as wheat, potatoes and beans under solar canopies — receive adders.

But the consultants said the SMART approach is also complex and can result in unintended consequences, with larger, front-of-the-meter (FTM) projects crowding out behind-the-meter (BTM) systems. As of September 2019, 60% of the large building-mounted and canopy systems in the Massachusetts program were installed as standalone projects instead of BTM systems. “BTM systems provide several benefits, including more economic opportunities to pair with battery storage and reduce on-site demand … reducing interconnection costs and utility work associated with creating new standalone service,” Cadmus said. “Amending regulations to correct this flaw has been proposed as part of the [current] review of the program.”

Fixed incentives offer set prices that are paid in addition to any revenues the facility may earn from electricity sales and costs avoided through reduced energy consumption. The programs, such as Connecticut’s Zero Emissions Renewable Energy Credit (ZREC), typically require transmission and distribution utilities to purchase RECs from solar electricity generators through long-term contracts.

Providing solar developers a reliable revenue source over a long period reduces lenders’ risks and the cost of capital. The simplicity of fixed incentives also reduces transaction costs.

But regulators can have problems determining the appropriate price level, Cadmus said. “If the price level is set too high, the market will accelerate too quickly, solar developers will capture excess profit and undesirable electricity rate increases may occur. Conversely, if the price level is set too low, the market will grow too slowly or not at all.”

And because it involves long-term contracts, fixed incentives lack market-responsiveness, although “program design can help mitigate some of these potential disadvantages,” Cadmus said.

The consultants proposed minimum 15-year incentives in the PSE&G territory, ranging from a low of $55/MWh for a community solar ground-based project to a high of $180/MWh for a commercial carport system with third-party ownership. Minimum incentives for residential rooftop systems were estimated at $95/MWh.

The 127-page report followed more than a dozen stakeholder meetings and a series of focus groups since January 2019.

With the release of the report, BPU staff recommended the board direct further stakeholder proceedings on developing the successor program. “The capstone report and underlying analysis should be considered as guidance only and … does not bind the board in any way on the development of a successor program or related incentives,” Program Administrator Benrey said.

BPU President Joseph Fiordaliso said the acceptance of the report was an “important step” in the development of a replacement for the SREC program, whose development in 2004 led to heated debates over its price tag.

He said he welcomed feedback on the report. “We [the BPU] don’t have all the answers,” Fiordaliso said. “Collectively, hopefully, we will.”

In a related matter, the board also approved a waiver of a requirement that applicants to the Community Solar Energy Pilot Program provide an interconnection upgrade cost assessment (QO20080556). The waiver applies only to projects proposed in the PSE&G service territory for program year 2, applications for which are due by Feb. 5. PSE&G informed BPU staff that it is unable to perform the requested interconnection cost assessments because of staffing constraints and an increase in interconnection study requests. In lieu of the assessments, applicants can submit a letter explaining why interconnection of the proposed project is likely to feasible.

Offshore Wind

The BPU on Friday also approved a solicitation for a consultant to help BPU staff work with PJM on transmission development for its offshore wind projects.

The board in November asked PJM to conduct a competitive solicitation for upgrades to connect 6,400 MW of offshore wind to the regional grid under its NJ Asks PJM to Seek Bids for OSW Tx.)

Jim Ferris, bureau chief for new technology at the BPU, said PJM is incorporating the state’s request into the 2021 Regional Transmission Expansion Plan (RTEP) and is working with BPU and PJM staff and transmission developers to solicit options for the board’s consideration.

Ferris said the consultant will be asked to assist staff in the preparation and review of documents required for the RTEP process, engage with stakeholders, aid in an independent review of all submitted proposals and provide recommendations for the best transmission solutions resulting from the process.

Fiordaliso said the BPU lacks staff with the expertise to manage the complicated RTEP process. “If we don’t have people who are well versed in certain subject areas, the learning curve is steep,” Fiordaliso said.

Commissioner Dianne Solomon said it made sense to bring in outside expertise. “We’re wading into waters that really need some specialized background and information,” Solomon said. “Far be it from me to tell PJM what to do, but I hope they too will engage consultants in areas in the past where they’ve said they don’t have sufficient staff to address some of these issues.”

The board also unanimously approved a memorandum of understanding to provide the South Jersey Port Corp. with $1.8 million in funds generated by the Societal Benefits Charge “to support the development” of a facility to manufacture monopiles for offshore wind turbines at the Paulsboro Marine Terminal in Gloucester County (QO20120770).

Kelly Mooij, director of the BPU’s Division of Clean Energy, said developing an OSW supply chain with manufacturing in New Jersey will produce economic benefits and help reduce the cost of reaching the state’s clean energy goals.

Gov. Murphy announced the $250 million Port of Paulsboro project last month, saying it would be the largest industrial offshore wind investment in the U.S. and create more than 500 jobs at full buildout. Construction will break ground this month, with production beginning in 2023. EEW Group, a German monopile manufacturer, will operate the facility.

Commissioner Bob Gordon asked if $1.8 million was enough for the facility. He said he has been a supporter of the idea of developing a supply chain for OSW in New Jersey but wondered if the BPU knows what the funds will be used for.

“It just seems to me that $1.8 million is not a make-or-break expenditure and is almost an afterthought,” Gordon said.

Fiordaliso said the funds will be used for infrastructure on the site.

January 10, 2021

MISO Intends to Add Seasonal Capacity Auction

MISO said it plans to subdivide its annual capacity auction by seasons so it can better manage budding reliability risks brought on by renewables’ growing share of the resource mix.

Jessica Harrison, the RTO’s senior director of research and development, said leadership is leaning toward a four-season capacity auction, though two or three seasons is still possible. (See MISO Nearing Decision on Seasonal Capacity Auction.)

“There’s still a range of preferences on the number of seasons,” Harrison said during a Resource Adequacy Subcommittee (RASC) meeting Jan. 6.

The grid operator intends to conduct the independent seasonal auctions simultaneously.

“It’s a proposal we’ll put forward and then monitor the need to hold more auctions in a year,” Harrison explained.

MISO’s decision will bring manifold implications and have it crunching separate planning reserve margins and local clearing requirements based on seasons.

MISO Seasonal Capacity Auction — Lynn Hecker, MISO | © *RTO Insider*

The RTO will conduct the loss-of-load expectation (LOLE) study on a seasonal basis to determine how risk is spread across the year. Senior Manager of Resource Adequacy Coordination Lynn Hecker said it will assign seasonal reliability requirements based on the study results.

Stakeholders asked what MISO will do if it can’t detect loss-of-load risk within a particular season.

“That’s a question we’re discussing,” Hecker said. She said staff is considering assigning seasons with a 0.01 LOLE risk target to determine resource adequacy requirements for those seasons.

“The idea that resources are fully available year-round with only some small outages is frankly being tested by the industry,” Harrison said. “We are getting requests to operate resources during [only] portions of the year.”

MISO will impose a must-offer requirement on planning resources only for the seasons they clear in the capacity auctions.

Stakeholders asked whether the RTO will establish separate seasonal capacity import and export limits for its 10 local resource zones.

“That’s another design element to consider that we haven’t spent a lot of time on yet,” Hecker said.

Some attendees urged MISO to make sure its model can handle multiple reserve margin requirements and that the new seasonal requirements work with state integrated resource planning.

Minimum Capacity Requirement for LSEs

The grid operator also proposed a minimum capacity requirement for load-serving entities participating in the seasonal auctions. The LSEs would be expected to procure at least half of their planning reserve margin requirement before the auctions.

Entities could be faced with a “penalty mechanism” for not meeting the 50% requirement, MISO said.

The proposal seemed unpopular with stakeholders. Several appeared taken aback at the rule, with some saying it was only mentioned in passing in stakeholder meetings before being unveiled.

MISO’s Independent Market Monitor also expressed its displeasure.

“We don’t support this 50% requirement. We think it’s a bad idea,” Monitor staffer Michael Chiasson said.

But a few stakeholders said the requirement will end an overreliance on the MISO capacity auction and the free ridership some utilities enjoy.

“This might be scaled to the size of the utility,” Customized Energy Solutions’ Ted Kuhn suggested, adding, “If you’re a 10-MW utility, I don’t think anyone cares where you procure. But if you’re DTE Energy, it’s a different story.”

Minnesota Public Utilities Commission staff member Hwikwon Ham said the requirement might tread on states’ jurisdiction in RA matters.

“MISO can limit its auction to an LSE, but it cannot tell an LSE what to procure,” he said.

Staff said they would reconsider language around the requirement.

Availability-based Accreditation, Too

The grid operator will unsurprisingly pivot to a seasonal capacity accreditation for planning resources, matching the capacity auction. It is also proposing to adopt the Monitor’s recommendation to pivot to an accreditation based on resource availability.

While MISO will adopt an availability-based resource accreditation (ACAP), it will still establish seasonal reliability requirements on an unforced capacity (UCAP) basis. It said it will use a conversion calculation to align the ACAP-based capacity accreditation with UCAP-based planning reserve margins.

The Monitor’s David Patton pressed MISO to rework its capacity accreditation, pitching an accreditation that relies on the system’s megawatts on hand during the operating year’s tightest hours. MISO leadership said it will adopt some — but not all — design elements from the Monitor’s availability-based accreditation recommendation.

Patton said resources that have long startup times and expensive startup costs aren’t able to provide the reliability that fast-ramping and online resources will. He said that currently, MISO’s market doesn’t properly value more agile resources and suggested the RTO could adopt a “sliding scale” of capacity accreditation based on a rolling, three-year average of the resources’ response time.

“The uncertainties around the output of intermittent resources are going to expand the tightest hours of the year beyond those that are easy to see coming,” Patton warned.

He argued that it’s becoming more important for conventional resources to prove availability as the fleet adds more renewable energy. However, he said conventional generation’s availability is shrinking and its undeclared outages are becoming commonplace.

“In theory,” Patton said, “compared to an energy-only market, capacity payments should reflect elements of shortage pricing,” where the units that help most are appropriately compensated.

He said MISO’s current UCAP-based accreditation overlooks facility derates and unreported outages.

“A lot of the lost megawatts come from outages that are not reported, so they wouldn’t be reflected in UCAP,” he said.

Patton said he also took issue with MISO’s current construct that effectively assumes no planned outages happen during summer peak conditions. He said the assumption does a disservice to reality.

“When you look, we have 10-plus GW of outages in the hottest conditions of the year. You wonder how they occur because we seemingly have enough capacity,” he said.

Some stakeholders complained about the suddenness of MISO’s pivot to an availability-based accreditation.

“I feel like our conversations [in] spring, summer have been grounded in availability. That’s exactly what we’ve been trying to get at all year,” MISO RASC liaison Scott Wright said.

Harrison and Hecker asked for written stakeholder opinions and said more details and analyses will be shared in future RASC meetings.

Mississippi Public Service Commission consultant Bill Booth asked whether MISO hadn’t already taken care of some of the availability problems with 2019’s stricter outage-scheduling rules and its recently approved short-term reserve product.

Patton responded by drawing a distinction between energy and capacity and said capacity revenues should naturally decline when “more of the heavy lifting” of providing reserves is handled by shortage products.

Wright said MISO needs to employ tactics in both its operating and planning horizons to address the footprint’s changing risk profile.

“We’ve got to be on all sides of it,” Wright said, adding that an effort to more accurately measure capacity is a valuable planning tool.

CEO John Bear warned members early last year that MISO is pivoting from on a summer loss-of-load emphasis to an “all-hours-matter focus” because of the generation fleet’s “increasingly distributed and intermittent nature.”

January 10, 2021

BOEM Sees Moderate Impacts from South Fork OSW Project

The South Fork Wind Project will have negligible to moderate environmental impacts from construction, operation and decommissioning, according to a draft environmental impact statement (DEIS) issued by the Bureau of Ocean Energy Management last week.

The 132-MW offshore wind joint venture between Ørsted and Eversource Energy would consist of up to 15 wind turbines with a capacity of 6 to 12 MW each located about 30 nautical miles east of Montauk Point, N.Y.

BOEM will hold virtual public meetings on Feb. 9, 11, and 16 where it will accept comments submitted or postmarked no later than Feb. 22 before completing the EIS.

Environmental Impacts

The DEIS categorizes potential adverse or beneficial impacts as negligible, minor, moderate or major, comparing impacts from alternative scenarios and summarizing key findings for the project’s proposed Construction and Operations Plan (COP).

The developers proposed an offshore substation within the lease area, with associated export cables subject to applicable mitigation measures — turbines laid out in a uniform east–west and north–south grid with 1-square-nautical-mile spacing between turbines and diagonal transit lanes at least 0.6 nautical miles wide — spacing agreed on by all OSW developers last summer and recommended by the U.S. Coast Guard. (See Developers Seek 1-Mile Spacing for Vineyard Wind.)

“Impacts associated with the other action alternatives are generally similar to those described for the proposed action,” BOEM said.

The agency outlined four possible regulatory choices:

“no action,” the equivalent to rejecting the project outright;
approving it as proposed;
an alternative layout with a 4-nautical-mile-wide vessel transit lane as proposed by the Responsible Offshore Development Association; or
a “fisheries habitat impact minimization” alternative that would exclude certain turbines and associated cable locations if micro-siting is not possible.

It said it incurred costs of $1.8 million in drafting the EIS, which assesses impacts on air and water quality, bats and birds; marine mammals and sea turtles; benthic habitat; land and wetlands; fisheries and tourism; cultural resources; employment; social justice; and federal income.

Regarding marine mammals, “some individual whales or seals could suffer temporary or permanent hearing injury; these adverse effects would be moderate for affected individual marine mammals [and] overall cumulative adverse impacts would be moderate,” the report stated.

Commercial fisheries and for-hire recreation fishing might suffer moderate adverse effects from increased port congestion and reduced fishing opportunity during construction. Fishing gear could be lost or damaged, and catches might decline if target species avoid construction areas. The “reef effect” of turbine foundations and associated scour protection would have minor beneficial impacts to recreational fisheries, depending on the extent to which the foundations enhance fishing opportunities. Overall cumulative adverse impacts would be moderate, it said.

The report foresees that “overall cumulative adverse impacts [on navigation and vessel traffic] would be moderate.”

It also projects overall cumulative impacts to employment, federal revenue and income to be minor.

On social justice issues, the DEIS sees “minor to moderate adverse impacts to minority or low-income populations and tribes from the project,” with moderate cumulative adverse impacts overall.

Land Ahoy!

BOEM last summer held a series of public hearings on its supplemental environmental impact statement (SEIS) for the Vineyard Wind project in federal waters south of Massachusetts. It was to issue its final EIS in December and make a final decision by January. Vineyard Wind is a joint venture between Copenhagen Infrastructure Partners and Avangrid Renewables.

However, early in December Vineyard Wind announced a supplier agreement with General Electric for 13-MW Haliade-X turbines, supplanting a previous deal with MHI Vestas and delaying final approval of the project for some months. (See Offshore Wind Looks at Crowded Future in New England.)

The preferred landfall site for the South Fork export cable (SFEC Route A) is at the parking lot at the southern end of Beach Lane, with a new terrestrial cable to be buried under paved roadways and the Long Island Railroad right-of-way to the interconnection facility.

A survey identified three archaeological sites or historic properties within or adjacent to proposed alternative landing sites and potential routes for the onshore cable, which are no longer being considered for the project and therefore will not be affected, BOEM said.

There are no previously reported archaeological sites along Beach Lane, and none were identified during shovel testing there, at the Hither Hills landing site or within the proposed onshore substation sites.

The East Hampton Town Board will hear public comments on its agreement to allow the export cable to come ashore under Beach Lane or elsewhere on Jan. 12 and will then vote on the contract.

January 10, 2021

Hairston Appointed BPA Administrator

Bonneville Power Administration acting administrator and CEO John Hairston will officially assume the top job at the federal power marketing agency, the U.S. Department of Energy said Thursday.

Hairston stepped into the role on an interim basis in September after former chief Elliot Mainzer left BPA to become CEO of CAISO Names Bonneville Power Administrator as New CEO.)

Like his predecessor, Hairston rose through the ranks during a long career at BPA, most recently working as chief operating officer and chief administrative officer.

“John has made a lasting and significant impact on the Bonneville Power Administration over the past 29 years, and I am proud to announce him as the new administrator,” Energy Secretary Dan Brouillette said in a statement. “BPA is an important provider of reliable, renewable hydroelectric and clean nuclear power to the Pacific Northwest, and John’s commitment to serve BPA will support the Department’s critical energy mission.”

“I am truly honored and humbled by the opportunity to lead Bonneville during this dynamic time, when we are not only challenged to meet the pressing needs of our customers but must also position BPA to be their long-term provider of choice for low-cost, reliable and responsible carbon-free power,” Hairston said.

At a November webinar hosted by the Committee for Regional Electric Power Cooperation (CREPC) on “Diverse Energy Leadership in the West,” Hairston said BPA has undertaken an “aggressive” program of cultural transformation. (See Industry Leaders Talk Diversity in the West.)

Bonneville Power Administration — BPA Administrator and CEO John Hairston | *CREPC-WIRAB*

“Part of that change was my ascent into the front office, which I think allowed … for folks to kind of see someone different in the front office and see themselves and maybe aspects of their culture reflected in the leadership,” said Hairston, who is African American.

Hairston takes over at BPA as the Pacific Northwest and broader West face looming capacity shortages, a fact made evident last August when a persistent heat wave forced CAISO to initiate rolling blackouts while other balancing authorities teetered on the brink of doing the same.

A joint analysis by CAISO and California agencies placed part of the blame on a growing shortfall in resource adequacy. (See WECC Says Extreme Events Require Forecast, RA Changes.)

“For us and our customers, resource adequacy is a pretty big deal,” Hairston said during the CREPC webinar.

He said the agency must find ways to work with its Western neighbors on RA; “for others to go through blackouts means [the region is] not cooperating.”

The Northwest Power Pool’s effort to create a formal RA program is a “really great opportunity” to collaborate with other regional utilities, he said. (See NWPP RA Effort Quickly Ramping Up.)

Hairston will also shepherd BPA through the final stages of a complex entry process into CAISO’s Western Energy Imbalance Market (EIM). BPA has a go-live date targeted for March 2022, pending the outcome of an extended stakeholder proceeding.

In November, Hairston said the EIM offers resource diversity and the ability to offset risk. It also provides BPA the opportunity to utilize its extensive hydroelectric system. Regarding the expansion of the EIM into a full RTO, he said “the governance issue is a challenge for us in the Pacific Northwest.”

Hairston’s appointment received praise from key stakeholders in the region.

“We are thrilled by the naming of John Hairston, and look forward to his continued leadership at the helm of BPA,” environmental group Northwest RiverPartners tweeted.

“Looking forward to working with John on building out our region’s clean energy future,” clean energy advocate Renewable Northwest tweeted.

January 8, 2021

FERC Fines Algonquin Plant $1M for Bungled Offers

FERC on Tuesday approved a civil penalty of $1 million against Algonquin Power & Utilities’ Windsor Locks gas plant in Connecticut for mishandling its multiple generators when offering into the ISO-NE markets in 2012-2013 (IN21-2).

The settlement between the commission’s Office of Enforcement and Algonquin also entails the plant disgorging $1.1 million in capacity payments to ISO-NE and being subject to compliance monitoring for up to two years.

The Windsor Locks plant is a 71-MW combined cycle cogeneration facility, with a 40-MW dual-fuel generator, a 16-MW steam turbine and a 15-MW Solar Titan 130 generator, the last of which, despite its name, is a gas turbine. The first two units came online in 1990, while the third was installed in 2012.

Algonquin Power & Utilities’ Windsor Locks gas plant primarily serves the Windsor Locks Paper Mill (above) in Connecticut, but it also bids its excess power into ISO-NE’s markets. | *Ahlstrom-Munksjö*

The plant sold excess power under a Public Utility Regulatory Policies Act agreement until 2010, after which it became a dispatchable resource in the ISO-NE energy markets and an intermittent power resource in the Forward Capacity Market. Algonquin initially hired a third party to serve as its lead market participant (LMP) and to provide bidding strategies and guidance on compliance matters.

But the company later moved this function in-house to subsidiary Algonquin Energy Services (AES), which “did not have sufficient experience scheduling resources in the ISO-NE markets or managing the attendant tariff obligations at the time,” the commission said.

After the plant installed the 15-MW generator, ISO-NE’s grid monitoring software recorded the electricity being generated by all three generators as one resource, instead of recording separate meter data for each of the generation facilities. As a result, ISO-NE’s software was not able to distinguish which generator was operating absent additional communication from the plant or AES and was unable to confirm how many megawatts of incremental energy would be available in a certain time period.

Meanwhile, plant staff and AES tried to continue operating according to the procedures that the third-party LMP had designed before the new generator was added, assuming that the ISO-NE control room would alert them if the plant was violating its compliance obligations. But because of the mismanaged modeling, ISO-NE found that the plant was underbidding its capacity into the day-ahead energy market, Forward Capacity Market (FCM) and Forward Reserve Market (FRM).

“Windsor Locks and AES lacked the internal knowledge, personnel and experience necessary to understand and manage compliance obligations after Windsor Locks added the Solar Titan generator,” FERC said. “Enforcement determined that the offers did not reflect the resource’s unit-specific operating characteristics. Moreover, it determined that Windsor Locks should be required to disgorge a portion of the capacity payments it received during the relevant period commensurate with the degree to which the offers fell short of the FCM offer obligation.”

January 8, 2021

NYISO Appeals FERC Rejection of BSM Proposal

NYISO last week filed a petition with the D.C. Circuit Court of Appeals asking it to review FERC’s rejection of the ISO’s proposal to exempt public policy resources from its buyer-side mitigation rules (ER20-1718-001).

FERC in September rejected NYISO’s proposal to allow public policy resources in New York City and zones G-I to avoid buyer-side mitigation if enough existing capacity exits the market or demand increases enough to boost capacity requirements. NYISO’s petition followed the commission’s denial of its request for rehearing in November. (See FERC Rejects NYISO Bid to Aid Public Policy Resources.)

NYISO Appeal — NYISO’s proposal would have allowed public policy resources in zones G-J to avoid buyer-side mitigation under certain conditions. | *NYISO*

To win an exemption from NYISO mitigation, a new entrant must pass one of two exemption tests. Part A allows exemptions if the forecast of capacity prices in the first year of a new entrant’s operation is higher than the default offer floor. Part B permits exemptions if the forecast of capacity prices in the first three years of a new entrant’s operation is higher than its net cost of new entry. NYISO’s proposal would have strengthened Part A by, among other things, performing the test before Part B and putting public policy resources ahead of other resources in Part A evaluations.

“We disagree that the prevalence of public policy resources in the future composition of New York state’s resource mix means they are not similarly situated to nonpublic policy resources for the purposes of the Part A test,” the commission said in its ruling.

After the rejection, NYISO CEO Rich Dewey said, “We worked closely with market participants on a design we felt addressed FERC’s jurisdictional obligations and New York’s right to implement renewable energy policies.”

The commission voted 3-1 to reject the proposal, with Commissioner Richard Glick dissenting. “The proposal received a supermajority of votes in the stakeholder process, and not a single party protested this issue before the commission, including any of the generator groups that have cheered on the commission’s slew of recent buyer-side mitigation orders,” Glick said.

January 8, 2021

ERO Pandemic-related Measures Extended Again

Expansions to the ERO Enterprise self-logging program, along with deferments of audits and other on-site activities, will continue through the end of June so that registered entities can focus on their response to the COVID-19 pandemic, NERC said on Wednesday.

The measures were introduced in May 2020, allowing all registered entities — regardless of whether they are already part of the program — to self-log instances of noncompliance that pose either a minimal or moderate risk to the bulk power system, as long as the noncompliance can be attributed to coronavirus mitigation actions. (See ERO COVID-19 Measures to Continue into 2021.)

Wednesday’s announcement indicates that despite NERC CEO Jim Robb’s talk in the Member Representatives Committee’s (MRC) informational session the same day of a “light at the end of the tunnel,” the ERO Enterprise still sees the pandemic as a long-term challenge.

ERO Pandemic Measures — Daily trends in number of COVID-19 cases in the U.S. reported to CDC | *CDC*

“During this challenging time, the ERO Enterprise recognizes the importance of prioritizing the health and safety of personnel and the continued reliability and security of the bulk power system. We will continue to evaluate the circumstances to determine whether additional guidance and extensions are needed,” the organization said.

Expiration of Pandemic Measures Uncertain

NERC and the regional entities’ decision to push back the expiration of the self-logging expansion and on-site activity deferments again fits with other pandemic-related measures that the organizations have extended.

The most visible of these are the remote work postures adopted by many organizations. A NERC representative confirmed to ERO Insider that the organization’s offices in Atlanta and D.C. are still closed, despite earlier plans to reopen them by the end of 2020. REs that plan to delay reopening their offices until at least the second quarter of 2021 include Midwest Reliability Organization, Texas Reliability Entity and SPP.

SERC Reliability is currently in a “soft opening,” in which employees may return to work voluntarily, and is planning to begin a phased “hard opening” on March 1 aimed at getting all employees back to its Charlotte, N.C., office. ReliabilityFirst is following a similar plan, with employees allowed to work from home through the end of the first quarter, though the office is “open to staff on a voluntary basis.”

WECC announced in November its Salt Lake City and Vancouver offices would remain closed until at least Feb. 1, with no in-person meetings or travel through the end of March.

NERC has canceled in-person gatherings in the spring as well, including the inaugural Electric Power Human Performance Improvement Symposium. The conference, a joint effort between the ERO Enterprise and the North American Transmission Forum, was originally deferred from September 2020 to March before being delayed again in October. The new date has yet to be determined.

Robb told Wednesday’s MRC session that NERC’s 2021 Board of Trustees meetings will likely all be held remotely. A return to in-person gatherings is possible next year; in a sign of the pandemic’s long-term impact, the organization is considering holding two of the four yearly events in a hybrid format, with some participants attending via conference call. (See NERC Considering Long-term Virtual Board Meeting Format.)

Other COVID-19 responses have been allowed to sunset. Seven reliability standards whose implementation dates were delayed last April have taken effect. (See FERC Agrees to Defer Standards Implementation.) CIP-005-6 (Electronic security perimeter(s)), CIP-010-3 (Configuration change management and vulnerability assessments) and CIP-013-1 (Supply chain risk management) became enforceable on Oct. 1, and the remaining provisions of PRC-002-2 (Disturbance monitoring and reporting requirements) and PRC-025-2 (Generator relay loadability) took effect Jan. 1.

PER-006-1 (Specific training for personnel) and PRC-027-1 (Coordination of protection systems for performance during faults) are scheduled to take effect by April 1. Robb said last year that NERC and No Further Deferments for NERC Standards.)

January 7, 2021March 9, 2025

Dems’ Senate Gains Raise Hopes for Biden Agenda

The Democrats’ victory in Georgia’s U.S. Senate runoff elections Jan. 6 means President-elect Joe Biden will have an easier time winning confirmation for his cabinet nominees and could open the door to some form of climate legislation.

The victories by Democrats Jon Ossoff and Raphael Warnock leave the Senate split 50-50, with incoming Vice President Kamala Harris able to break the tie. But unless the Democrats decide to eliminate the filibuster, they will need to win support of at least 10 Republicans to pass most legislation.

During the campaign, Biden proposed a $2 trillion plan to eliminate power sector carbon emissions by 2035 and make the U.S. the leader in electric vehicle production. (See Biden Offers $2 Trillion Climate Plan.)

Biden has not endorsed calls to end the filibuster. But in a note to clients Wednesday, ClearView Energy Partners suggested efforts by some congressional Republicans to contest the presidential election results might prompt Democrats who have opposed elimination of the filibuster, such as Sen. Joe Manchin (D-W.Va.), to reconsider their position.

Jon Ossoff and Raphael Warnock | Warnock for Georgia

“A post-filibuster Senate might not give Democrats party-line powers to enact a carbon tax or a sweeping climate law. But a filibuster-free Senate might still be able to enact transition-accelerating stimulus spending on renewables and electric vehicles with a price tag in the triple-digit billions (or maybe even single-digit trillions) of dollars. A national Clean Energy Standard might prove viable, too.”

The Democrats’ flip of the Senate “will translate into a bold centrist clean energy agenda focused on economic recovery and job creation,” Third Way’s Climate and Energy Program said. “Moving on this agenda is something, for example, that not only Sens. Manchin, [Mark Kelly (D-Ariz.), Kyrsten Sinema (D-Ariz.) and Jon Tester (D-Mont.)], but also Sens. [Ed Markey (D-Mass.) and Jeff] Merkley (D-Ore.) can take back to their constituents and demonstrate real progress, particularly on climate change and recovery from the COVID-19 recession.”

One thing for certain — assuming the preliminary vote counts in Georgia are confirmed — is that Sen. Mitch McConnell (R-Ky.) will not be able to block or slow-walk confirmation hearings on Biden’s nominees, including Rep. Deb Haaland (D-N.M.) as Interior secretary; former Michigan Gov. Jennifer Granholm as Energy secretary; Michael Regan, EPA administrator; Janet Yellen, secretary of the Treasury; and Neera Tanden, director of the Office of Management and Budget.

Role for FERC

There are also implications for FERC, which could remain controlled 3-2 by Republicans until Commissioner Neil Chatterjee’s term expires.

“The decisive FERC seat that will shift [the commission] from majority R to D will be open no later than July 1,” Ari Peskoe, director of the Electricity Law Initiative at the Harvard Law School Environmental and Energy Law Program, tweeted after the Georgia races were called. “Presumably, the nominee will be not be held up by the Senate majority leader, as I had anticipated.”

FERC will have a central role in implementing Biden’s energy agenda, whether or not Congress passes a clean energy standard (CES) such as he’s proposed, Peskoe said. In a paper published in November, Peskoe called for FERC transmission and market policies that support wind and solar power.

Raphael Warnock and Joe Biden | Warnock for Georgia

Although a CES would not direct FERC to take action, “Congress’s policy choice should lead FERC to ensure that its regulation is compatible with the national mandate,” he wrote. “If Congress passes a CES, FERC may be more likely to go further [than its proposed policy statement on carbon pricing] and declare that existing energy market rules are unjust and unreasonable because they do not include a carbon price.” (See Wide Support for FERC Carbon Pricing Statement.)

A CES would also increase demand for transmission, he said. “Under the current regime, utilities participating in a regional planning process face different renewable energy obligations or none at all. Utilities that do not need or want renewable energy may be reluctant to plan and pay for transmission expansions designed to facilitate new wind and solar. A federal requirement, such as the 100% clean energy by 2035 mandate that Biden proposed during the campaign, might eliminate or at least reduce the impact of such disparities among utilities and make it more likely that regional planners could reach consensus among their utility members on projects designed to unlock clean energy resources.”

Peskoe predicted a Democratic FERC majority will likely consider changes to the PJM, ISO-NE and NYISO capacity markets to eliminate barriers to renewables such as the minimum offer price rule. But he noted, “There is no consensus on what new state procurement program or RTO market design should replace or supplement FERC’s capacity market rules.”

‘High Hurdle’

The Democrats’ narrow Senate edge also means Manchin will assume chairmanship of the Energy and Natural Resources Committee.

“I think a Marshall Plan-like Clean Energy Plan for rural America is a must to maintain broad support — 50 votes — politically smart and allows Joe Manchin to deliver a win for West Virginia,” tweeted David Littell, senior adviser to the Regulatory Assistance Project and a former member of the Maine Public Utilities Commission.

Even without the Senate victory, Biden was expected to use his executive powers to reverse many of President Trump’s environmental policies. ClearView Energy said that reversing proposed rules that are not yet final, such as the revised 2008 ozone federal implementation plans, will likely be easy to accomplish. In contrast, undoing Trump’s replacement of the Obama Clean Power Plan with the Affordable Clean Energy Rule will be a relatively “high hurdle” because the matter is already under judicial review, ClearView said.

January 7, 2021

NY Panel Rethinks Wastewater, Renewable Gas

A panel of New York officials and industry experts on Tuesday discussed the basics of anaerobic digestion and the repurposing of wastewater treatment as a way to recover water resources and harvest renewable natural gases to help power the process.

New York Renewable Gas — Martin Brand, DEC | *NYDPS*

The New York State Climate Action Council (CAC) Waste Advisory Panel met Jan. 5 for the third time since its founding in November.

“There are so many cross-cutting issues; whether it’s transportation, local land use, local government, large-scale versus small-scale … the key is to keep focusing on the methane emissions reductions, and the hard part is going to be quantifying all of these things,” said Department of Environmental Conservation (DEC) Deputy Commissioner Martin Brand, who chairs the panel.

The DEC last month finalized the regulations to reduce greenhouse gas emissions, the first regulatory requirement of the Climate Leadership and Community Protection Act (CLCPA). The state in October completed its public hearing process on the proposed (Part 496) emissions limits. (See New York Holds Final CLCPA Emissions Hearings.)

European Experience

George Bevington, senior project manager at construction engineering firm Barton and Loguidice, outlined the process of anaerobic digestion, which he said uses “organisms from the primordial ooze” to break down organic compounds.

Even a septic tank in the countryside is an anaerobic environment, but industrial-scale operations are much more controlled within a set range of temperature and acidity levels.

“Never look at a methanogen cross-eyed because they’re very sensitive and everything has to be perfect,” Bevington said.

Germany covers about triple the area geographically as New York but has 6,000 anaerobic digestors (ADs) compared to an estimated 200 in the Empire State, “so the technology basically starts out in Europe and then comes here because they are much more densely populated,” Bevington said.

Casella Waste Systems CEO John Casella said the existing ADs are not able to handle organics.

“When we talk generally about handling organics, that’s a misnomer,” Casella said. “We need high-quality, high-quantity materials. One of the reasons why the de-packaging is going to be successful is that you’re going to be able to have that slurry supply where you’ve separated the packaging, the plastic and the other materials from that stream that could then go to a digestor. But to change culturally where we are right now to have a stream of organic directly to an AD would be pretty difficult.”

Bevington said a simple look at recycling bins in the U.S. will show a 10% error rate in sorting, “but if you have that rate going into an AD plant, they will tell the hauler they don’t want their product anymore.”

The 22-member CAC is working toward a fall 2021 target for completing a scoping plan for achieving the state’s energy and climate goals under the CLCPA, which mandates switching to 100% zero-emission electricity by 2040 and reducing GHG emissions to 85% below 1990 levels by 2050.

Rethinking Wastewater

Jane Gajwani, director of energy and resource recovery programs for the New York City Department of Environmental Protection, reported on the wastewater subgroup, consisting mainly of her and Bevington working with staff from the New York State Energy Research and Development Authority (NYSERDA) and the DEC.

One task was to support the transformation of wastewater treatment into water resource recovery, “and we feel this is a really important goal,” Gajwani said. “It’s something that the wastewater industry rebranded itself as a few years ago, but it’s not an instantaneous change. You can’t just snap your fingers, but it really does acknowledge the potential within wastewater in trying to rethink how we go about treating water to create a circular economy.”

The idea is to extract the full range of resources contained in wastewater as renewable bioproducts, displacing fossil fuel-based alternatives while minimizing GHG emissions, she said.

This requires maximizing recovery of the embedded energy and resources conveyed in wastewater; implementing systems to minimize fugitive methane and nitrous oxide emissions associated with wastewater; leveraging existing wastewater infrastructure to meet rising demand for organic management and co-digestion; recovering digestate and biosolids for beneficial use, leading to a significant reduction in the landfilling of these resources that contribute to methane emissions from those landfills. It also means distributing bioproducts and bioenergy that benefit communities, sequestering carbon and reducing GHG emissions throughout New York.

“That’s a lot to talk about, and the first piece we tackled as a group was the minimizing of fugitive emissions,” Gajwani said. “Wastewater in general has fugitive emissions associated with it of both methane and nitrous oxide, so the first thing is whether or not we should have reduction goals. We’re trying to figure out realistically what we can obtain by 2030 and by 2050. It’s actually a little bit easier for us to figure out how to reduce emissions of methane — we have our arms around this — than nitrous oxide, which we’re in the middle of studying.”

A few policies came to the forefront, such as comprehensive and continuous active monitoring for fugitive emissions, with full regulatory and financial implications; training of DEC inspectors to assess such emissions, which would not carve a regulatory change; and to urge conversion of home septic systems to sewer systems where feasible in densely populated areas, especially on Long Island, she said.

One important policy is to support the installation of anaerobic digesters at wastewater treatment plants throughout the state and facilitate 100% beneficial use of recovered energy in the form of biogas and biosolids, Gajwani said.

Michelle “Tok” Oyewole of the New York City Environmental Justice Alliance reported on the local scale diversion and climate justice subgroup, which has held one meeting and is focused on green jobs at the local level and employment benefitting marginalized communities.

It’s a real emphasis on building the programs that people tend to disregard the work of, such as the Inner City Green Team and micro hauling groups and community-scale composters who just look at resources a bit more and have a bit more vision overall than the traditional waste management world, Oyewole said.

January 7, 2021

NERC Considering Long-term Virtual Board Meeting Format

As NERC’s leadership sees “light at the end of the tunnel” of the COVID-19 pandemic, CEO Jim Robb is considering a partially online format for future meetings of the organization’s Board of Trustees inspired by the successful shift to remote work in 2020.

Under a framework proposed by Robb during Wednesday’s meeting of the Member Representatives Committee (MRC), the full board would meet in person every quarter, as it did until last spring when many participants were no longer able to attend because of pandemic-related travel restrictions.

NERC Virtual Meetings — NERC CEO Jim Robb | *NERC*

The February and August meetings would be open to stakeholders and accompanied by an in-person meeting of the MRC, while the May and November meetings would be open to in-person attendance by board members only. Stakeholders could still listen in via web conference, and the MRC would hold its quarterly meeting virtually, a format that Chair Roy Thilly said the organization was considering at the board’s online meeting last May. (See “COVID-19 Prompts Further Meeting Changes,” NERC Board of Trustees/MRC Briefs: May 14, 2020.)

Robb presented this new “rhythm” of stakeholder engagement as a way to reduce the cost of in-person meetings, which he said the organization estimated to be about $1 million when travel costs for all participants are factored in. But the proposal is also meant to extend the benefits that NERC has seen through the unexpected experiment in remote operations.

“[Over] the last nine months, through this format … we’ve been able, in general, to attract more participants to our meetings, and different participants than we’ve seen before have been able to speak,” Robb said, because of the fact that “now you don’t have to get on a plane” to participate in a meeting.

The limitation of in-person meetings allows other changes as well, Robb noted. With only two mass gatherings a year, each one becomes a more special event. For example, under the proposal outlined by Robb, the February meeting would function as an annual meeting “with a celebratory dinner and acknowledgement of outgoing/incoming trustees and stakeholder leaders.” The August meeting would still be held in Canada and would help with outreach to Canadian stakeholders.

NERC is also discussing with the heads of major stakeholder committees the possibility of similarly replacing some in-person gatherings with remote meetings. This could also help the organization reduce the meeting space requirements for its offices in Atlanta and D.C., though Robb said NERC has no plans for such reductions in the near future.

Responses Council Prudence, Boldness

Participants in the conference call were generally supportive of rethinking the meeting schedule. MRC Chair Jennifer Sterling, of Exelon, noted that the board has previously considered moving from four to three meetings a year, so Robb’s proposal is not unprecedented. (See “Board Seeking Cut to Three Meetings per Year,” NERC MRC Briefs: Nov. 5, 2019.)

Some cautioned against taking the virtual meeting approach too far, however. Board Vice Chair Kenneth DeFontes suggested that NERC’s success with remote operation was because of the existing relationships built over years between current members. He wondered if newcomers would have the same opportunities to build trust with their colleagues with a reduced amount of in-person meetings.

Bill Gallagher of the Vermont Public Power Supply Authority noted that while the proposed schedule would allow four in-person board meetings per year, the MRC would be limited to two.

If “we’re only meeting twice a year, and the rest of it is virtual, carrying out our own responsibilities may be compromised,” Gallagher said. “I don’t think that’s something we ought to do. The MRC has responsibilities that are distinct from the board, but no less important.”

Sylvain Clermont, director of operational technologies convergence at Hydro-Québec TransÉnergie, said that leadership should consider a bolder approach to incorporating technology rather than trying “to replicate the way we were doing business” before. He reminded participants that they have all grown familiar with online collaboration and video conferencing tools and suggested that NERC could explore how those products’ features could be used to enable greater productivity.

“I know that there’s probably technological challenges in that, but I would like us to think broader than just trying to replicate the formula with, in part, some virtual settings,” Clermont said. “I would like to see how we could make engagement … a frequent and dynamic and continuous process, so that ideas could be shared dynamically more often, and discussions happen more frequently.”

Robb emphasized that the schedule discussed Wednesday is a strawman intended to inspire discussion. NERC leadership will work on a proposal incorporating stakeholders’ suggestions ahead of the upcoming board and MRC conference calls in February.