From:                                         Sustainable Energy Advantage, LLC <sea-deliverables@seadvantage.com>

Sent:                                           Monday, December 6, 2021 5:54 PM

To:                                               Bob Grace

Subject:                                     SEA New England Eyes & Ears Flash No. 92.5, Week Ending December 3, 2021

 

New England Eyes & Ears Flash 92.5, Week Ending December 3, 2021

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2021 New England Legislative Tracking Spreadsheet Update

 

Massachusetts

Connecticut

Rhode Island

Maine

New Hampshire

Vermont

ISO New England

Regional and National Developments

2021 New England Legislative Tracking Spreadsheet Update

SEA's most up to date Legislative Tracking Spreadsheet can be found here. Please feel free to contact Jim Kennerly with any questions regarding New England legislative tracking.

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Massachusetts

DPU approves provisional interconnection cost allocation program for DG in current group studies, including potential for cost socialization; EDCs propose to socialize up to 100% of transmission costs, subject to DPU approval; Procedural conference call to be held December 10

On November 24, 2021, in Docket 20-75, the Massachusetts Department of Public Utilities (DPU) issued an Order establishing a provisional cost allocation program (Provisional Program) to facilitate the interconnection of distributed generation (DG) currently in the interconnection queue and facing atypically high interconnection costs.

In addition, on December 3, the DPU issued Notice issuing a correction to a reference made in the Order and scheduling a conference call to be held on December 10 at 1:30 pm to answer procedural questions posed by the utilities concerning implementation of the directives set forth in the Order. The conference call can be accessed via Zoom here.

As last discussed in Digest 90, Docket 20-75 was established to consider:

Specifically, the DPU's Straw Proposal proposed a long-term planning process to allow for the upfront financing by ratepayers of system upgrades necessary to accommodate the interconnection of DG. Subsequent interconnecting DG projects would be charged for the system upgrade costs on a pro-rata basis, based the ratio of on each project's MW to the total nameplate MW of interconnection enabled by the system upgrade, and these payments would be credited to ratepayers. The DPU's November 24 Order did not approve this long-term process, but rather approved, as the Provisional Program, the aforementioned cost allocation method for a limited set of near-term system upgrades, subject to DPU approval for each specific upgrade.

An overview of the DPU's Straw Proposal is provided below for context, as the Provisional Program utilizes concepts and terminology established in the Straw Proposal (for an even more detailed summary of the Straw Proposal, see Digest 85). As noted above, the Provisional Program mandated in the Order does not incorporate all of the elements of the Straw Proposal. Distribution System Planning: The DPU proposed that National Grid, Eversource and Until individually undertake distribution system planning efforts on an annual basis, with the goal of identifying system upgrades necessary to accommodate forecasted load growth and DG interconnection on a rolling ten-year basis. Cost Allocation Proposal for “Capital Investment Projects” based on Distribution System Planning Process: The DPU proposed that the planning process or interconnection studies would identify distribution system modifications (referred to as "Capital Investment Projects" (CIPs)) that, if approved, would be funded by the EDC using a Reconciling Charge to be included as a part of the distribution charge. Each DG facility benefiting from a CIP would then be charged an upfront $/kW fee (calculated as a proportional share of the cost of the modification relative to the total kW capacity the modification can enable to interconnect), which would be credited to the Reconciling Charge to offset the costs borne by ratepayers. The total annual Reconciling Charge would be capped at 1.5% of the EDC's total yearly revenue (or a greater amount determined by the DPU). Though not explicitly stated, the presence of the limit implied that if the limit is reached (and not expanded by the DPU), the DPU would cease qualifying CIPs for up-front ratepayer funding. The proposal would reduce individual DG project exposure to footing the entire cost of a modification faced by each project as it seeks to interconnect, instead spreading upgrade costs evenly over current and future DG projects that would benefit from the modification, while having ratepayers initially fund the upgrade costs . Preemptive construction of such facilities would also accelerate and streamline the interconnection process.

A summary of the DPU's Order, organized by issue area, is provided below:

Analysis and Next Steps Given that the Provisional Program was established with the express intent to address high interconnection costs resulting from these very studies, it is our expectation that many projects already in complex studies with functionally unaffordable upgrades for individual developers will be included in proposed CIPs, and will likely have their extension remain in effect until the EDCs propose such CIPs (assuming they do, given a lack of requirement to do so). At that point, the Order’s revisions to the Notice Period will take effect and provide the projects with an extension through 15 days from the DPU’s eventual order on such CIPs.

That said, and given that 1) our team is unaware of the extent of CIPs the EDCs will propose and 2) the EDC are not required to propose any CIPs at all, it is difficult to evaluate how impactful this Order will be for the hundreds of MW of projects already involved in complex and costly studies for which a departure from traditional cost allocation approaches is likely necessary to avoid mass attrition.

In addition, the four-year maximum timeline for CIP construction appears likely to conflict with the fact that all projects seeking the federal Investment Tax Credit (ITC) under current law must have all projects “placed in service” (PIS) no later than December 31, 2025, or must accept a 10% tax credit value. As such, if the Build Back Better Act (most recently discussed in Special Flash 92.4.1) or similar legislation extending the PIS deadline ultimately is not enacted, such a timeline is also very unlikely to prevent attrition amongst projects with tax equity investors who will not be satisfied with the uncertainty regarding their ability to monetize the credits. Perhaps most importantly, it is unclear the pace at which CIPs will be proposed and adjudicated by the DPU, given a lack of deadlines to issue determinations once CIP proposals are filed, as well as the constraints on EDC and DPU bandwidth to study and rule on CIPs. We note, for example, that the tariffs to expand the SMART program have been pending before the agency for more than a year. If such rulings follow even a fraction of that timeline, it is our understanding that these delays, coupled with the tax credit uncertainty (especially in the case that the Build Back Better Act does not pass), could drive even more significant attrition than the amounts already occurring in those cohorts group study cohorts under consideration will be unavoidable. It is also unclear if the EDCs or DPU will collectively prioritize (or possess the bandwidth to prioritize) the development, review and approval of proposed CIPs on timescales conducive to the successful development of these projects.

Given the issuance of an Order on the short-term provisional program, the next steps in this proceeding beyond the aforementioned conference call appear to be the issuance of an order on the long-term planning process described in the DPU's Straw Proposal, although it is possible that defining a long-term approach to allocating DG interconnection costs could be separately docketed. The DPU has not indicated when such an order could be expected.

 

ARPA spending bill funding port development, EV rebates and housing grants with preference for clean heating and on-site renewables passes in informal sessions, Baker expected to sign into law

On December 1, 2021, the conference committee of the Massachusetts General Court negotiated a consensus bill to allocate American Rescue Plan Act and state surplus funds last discussed in Flash Update 92.4, released H.4269- An Act relative to immediate COVID-19 recovery needs for final passage for enactment. The final bill allocates funds to a number of efforts relating to renewable energy, which we summarize below.

On November 2, 2021, the House of Representatives passed H.4269 in an informal session, meaning there was no roll call vote and no member objected to passage. On November 3, 2021, the Senate also passed the bill in an informal session on November 3, 2021. The bill is now before Governor Baker for his signature or veto. Given Governor Baker’s past statements expressing frustration with the delay of this bill’s passage, we expect Governor Baker to sign the bill into law. As there is an emergency preamble to the bill, the law will go into effect immediately upon signing. The next step after signing would be the disbursement of the funds.

 

DPU issues second Order in investigation of National Grid management audit: Orders company to implement all audit recommendations and file comprehensive update with next base rate case

On November 24, 2021, in Docket 19-117, the management audit of National Grid, the Massachusetts Department of Public Utilities (DPU) issued an Order that summarized the audit findings, addressed the responses of the parties, and directed National Grid to implement the audit recommendations. Many of the audit findings and recommendations relate to internal National Grid processes not directly related to renewable energy, however, the audit addressed National Grid's electric vehicle (EV) program and interconnection process around the transmission system impact studies (also called cluster studies or affected system operator (ASO) studies), which are relevant to renewable energy development and demand.

In examining the EV program, the audit found that while National Grid tracks useful metrics already, "...additional metrics aimed at early identification of any issues that may arise would be beneficial...." In particular, the audit observed that National Grid's 2018 restructuring "led to a loss of 25 percent of the EV program staff" and recommended that National Grid increase employee retention in the program by developing goals for employees in their annual reviews.

On the topic of the interconnection and cluster studies, the audit found that National Grid was overwhelmed by interconnection applications, and the decision to create an application portal while some interconnecting customers where in the midst of applying for interconnection added to the confusion. High employee turnover at National Grid also contributed to problems faced by project developers applying for interconnection, and developers also "expressed frustration at dealing with multiple job owners for multiple projects across different geographic regions, often leading to conflicting information." The audit recommended that National Grid track responses to developers and attempt to address the root causes of these issues.

The DPU ultimately ordered National Grid to implement all of the recommendations of the audit "in a timely, efficient, and prudent manner." The DPU noted that National Grid has not proposed a plan to address each recommendation, and that the timeframes provided by National Grid for addressing many of the recommendations are "unclear." The DPU clarified that it will assess National Grid's investments in implementing the recommendations for prudency and urged National Grid to accelerate solution timelines where feasible.

National Grid will file a comprehensive update on its implementation of the audit recommendations when it files its next base rate proceeding, the timing of which is currently unclear.

 

EDCs respond to stakeholder positions in reply briefs in SMART tariff review docket; considering some but opposing many proposed tariff changes

As last discussed in Flash Update 92.4, on October 25, 2021, the Massachusetts Department of Public Utilities (DPU) issued a Memorandum in Docket 20-145, the proceeding in which the DPU is considering the electric distribution companies’ (EDCs) Revised SMART Tariff and Petition for Approval of the Revised SMART Tariff, requesting comments relating to Phase II of the SMART Tariff review. Phase II of the Tariff review is considering provisions pertaining to metering, billing, Alternative On-Bill Credit (AOBC) allocation (including the transfer of AOBCs between Eversource’s eastern and western service territories), revisions to certain definitions, and National Grid’s Solar Access Initiative (SAI) proposal (see Digest 88). Phase I of the Tariff review considered all necessary revisions to allow for the 1,600 MW program expansion, and is currently awaiting an order from the DPU.

The Memorandum requests that parties provide responses to the following questions (listed verbatim):

Initial comments were discussed in Flash Update 92.4. On November 23, Eversource Energy and National Grid (the EDCs) filed their Joint Reply Brief. A summary of the arguments made in the brief (with references to relevant arguments to which the EDCs are replying) is provided below, organized by topic:

The remaining deadlines for submitting briefs are as follows:

 

EFSB opens consolidated docket to consider multiple petitions for approval of the transmission facilities in support of Mayflower Wind project

On November 17, 2021, the Massachusetts Energy Facilities Siting Board (EFSB) opened Docket EFSB21-03 to consider petitions from Mayflower Wind relating to the construction and permitting of transmission facilities in support of Mayflower Wind’s proposed offshore wind project in Lease Area OCS-A 0521. Mayflower Wind is a joint venture between Shell and Ocean Winds (itself a joint venture of EDP Renewables and ENGIE). Along with the petitions, Mayflower Wind filed a letter requesting that the petitions be considered in a consolidated proceeding, a request which the EFSB has honored with the establishment of Docket EFSB21-03.

Specific petitions under consideration include:

As last discussed in Special Flash Update 92.1.1, in 2020 the Department of Public Utilities issued an Order approving power purchase agreements (PPAs) with the electric distribution companies Eversource, National Grid, and Unitil, following the selection of Mayflower Wind’s 804 MW "Low Cost Energy Project" submitted in response to the Section 83C Round II Request for Proposals. On November 1, the Bureau of Ocean Energy Management (BOEM) published a Notice of Intent to prepare an Environmental Impact Statement (EIS) for the proposed Mayflower Wind project, which as proposed would interconnect at locations in Falmouth and Somerset, Massachusetts. The comment period for scoping the EIS closed on December 1, and BOEM’s current schedule anticipates announcing the notice of availability of the draft EIS in January 2023, with expectations to make the final EIS available to the public in September 2023.

 

Anbaric and Borrego protest ISO-NE FCA16 Information filing as it relates to treatment of their energy storage projects in FCA 16; Borrego requests that battery storage ORTP account for ITC in pending BBB Act

On November 24, 2021, Anbaric Development Partners, LLC (Anbaric) and Borrego Solar Systems, Inc. (Borrego) filed with FERC separate Protests and Requests for Expeditious Action regarding treatment of their respective energy storage projects in Forward Capacity Auction #16 (FCA 16) for the 2025-2026 Capacity Commitment Period (CCP). The protests were in response to ISO-NE's November 9 FCA 16 Informational Filing in Docket ER22-391 discussed in Flash Update 92.4. ISO-NE's Informational Filing included data for FCA 16 including determinations made by the Internal Market Monitor (IMM) regarding the requested offer price from each new resource.

Westover Energy Storage Center: Anbaric submitted for IMM review a New Resource Offer Floor Price for FCA 16 for its Westover Energy Storage Center, a proposed 100 MW battery storage project located in Ludlow, MA. The IMM rejected its Offer Floor Price (which is confidential), instead requiring the project to bid into FCA 16 at a level no lower than the Offer Review Trigger Price (ORTP) for a lithium-ion battery storage project of $2.601/kW-mo. Anbaric requested that FERC override the IMM determination and allow the Westover Project to bid into FCA 16 at its original proposed Offer Floor Price. Anbaric requested that FERC issue an order addressing their protests by January 21, 2022.

Wendell Energy Storage Project: Borrego submitted a New Capacity Qualification package for FCA 16 for its Wendell project with a confidential requested Offer Floor Price that assumed at 26.2% applicable Investment Tax Credit (ITC) based on expected passage of the Build Back Better (BBB) Act by the end of the year. As summarized in Flash Update 91.2 and last covered in Flash Update 92.4, the BBB Act, which passed the U.S. House of Representatives on November 19, includes a 30% energy storage ITC,. The Wendell Project is a proposed 100 MW, 400 MWh (4-hour) battery storage project located in Wendell, MA. The project intends to sell Clean Peak Energy Credits under the newly established Massachusetts Clean Peak Standard. However, the IMM mitigated the assumed 26.2% value to 0% on the basis that the ITC assumption was speculative. Borrego argued that should a change in tax law provide them access to an ITC prior to FCA 16, that most or all battery storage project bids will no longer reflect prevailing market conditions. Borrego requested that FERC issue a response no later than January 23, 2022 that:

If FERC rules in favor of Borrego, it could immediately enhance the economics for energy storage projects with bids accepted for participation in FCA 16 and future FCAs. FERC has yet to respond to either protest.

 

Other Massachusetts News of Note

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Connecticut

Stakeholders comment on new proposed RPS regulation that would implement financial security requirements for LSEs, potentially change the amount of allowable REC banking , and stop post-closing REC adjustments in NEPOOL GIS

On November 17, 2021, in Docket 19-10-26, several stakeholders filed comments on PURA-proposed Renewable Portfolio Standard (RPS) modifications . As discussed in Flash Update 91.7, on October 15 the Connecticut Public Utilities Regulatory Authority (PURA) issued a Notice of Intent to amend the Renewable Portfolio Standard (RPS). The proposed regulation is intended to update the RPS to reflect changes made to Conn. Gen. Stat. § 16-245a pursuant to Public Act 17-186, An Act Concerning Renewable Portfolio Standard Compliance Requirements (discussed in Digest 79). =The proposed regulation effectively requires EDCs to independently manage their NEPOOL GIS RECs, maintain security with PURA to cover certain financial shortfalls, provide final load settlement data to PURA before a specific date, change (and possibly eliminate) the amount of RECs that could be banked and used for compliance in future years, and remove the provisions that allowed for renewable energy trading of emission attributes. The below stakeholders filed comments:

The comments addressed a number of key themes described below:

Timing of Compliance Filings for EDCs vs. Electric Suppliers: The proposed regulations would require electric suppliers to complete their NEPOOL GIS settlement by June 15. NRG argued that electric suppliers can’t correct discrepancies if they receive EDC load data after this date. NRG argued that PURA should adopt a reporting process like that used by the Massachusetts Department of Energy Resources (MA DOER) and further proposed PURA adopt the following three recommendations.

NRG argued that these would help suppliers better manage their RPS compliance obligation and reduce Alternative Compliance Payments (ACP) because they could address REC shortfalls while the trading period is still open. Vistra, Calpine and RESA contended that PURA should maintain an RPS compliance reporting date that does not change from year to year, and further supported the current date of October 15 each year for suppliers to submit their compliance reporting, and a May 15 deadline for EDC reporting of a supplier’s total load. UI argued that August 15 should be the earliest date that electric suppliers can submit compliance filings, arguing that this date would give participating entities enough time to prepare compliance filings after the NEPOOL GIS settlement date of June 15. Eversource requested that PURA incorporate an opportunity each year for comment on the deadlines that PURA proposes into the proposed regulation.

Banking Provisions: The proposed regulation indicated that if PURA, after conducting an uncontested proceeding, determines it is in the public interest, it may increase or reduce the amount of allowable banking in future compliance years or terminate banking altogether. An electric distribution company or electric supplier currently may bank renewable energy certificates that it generated in one year to comply with the renewable energy portfolio standard requirements in either of the two following years, provided the electric distribution company or electric supplier, respectively, has complied with the renewable energy portfolio standard requirements each year by means of RECs. Calpine and Vistra and RESA expressed concern that the proposed regulation language would grant PURA the authority to reduce or terminate banking in an uncontested proceeding and argued, at minimum, that such a proceeding should be a contested docket. Constellation requested that PURA revise the regulation to clarify that any decision to reduce or terminate REC banking would not affect the qualification of existing banked RECs (given that terminating qualification for such RECs would require repurchase of all banked RECs at current market rates). UI asked for clarity on the meaning of “each year” in the proposed banking provision, which allows EDCs or electric suppliers to bank RECs provided that they have “complied with the [RPS] requirements each year by means of [RECs].” UI expressed concern that as written, it is unclear if UI would be prohibited from banking in future years if it had satisfied RPS compliance by paying the ACP in a prior year.

Financial Security Requirements: The proposed regulation would require electric suppliers to maintain a security deposit with PURA to cover shortfalls in the event they amass large (and unsettled) RPS obligations and either file for bankruptcy or leave the market without meeting those RPS obligations. The security would be in an amount equal to the full alternative compliance payment the electric supplier would be required to pay based on the forecasted year load. Constellation argued that the definition of “security” includes guarantees and that so long as suppliers can fulfill the requirement with a parent company guarantee, that Constellation does not oppose the new obligation. Calpine and Vistra also supported a broader and more flexible definition of security than what is described in the proposed regulation. However, Calpine and Vistra and RESA argued that PURA already addressed security requirements related to RPS obligations (such as those in Conn. Agencies Regs. § 16-245-4.4) and that additional security requirements would be duplicative. Calpine and Vistra further stated that if PURA does indeed want additional security for RPS obligations, it should use a narrower and lower security value, such as a percentage of the ACP that declines with the duration of a supplier’s successful compliance history. RESA argued that the financial security requirement should be waived for suppliers that satisfy certain credit rating thresholds, and that PURA should cap the amount of additional RPS-related financial security that should be required.

Independently Managed NEPOOL Account: The proposed regulation would remove PURA’s responsibility to accept or review requests from EDCs and electric suppliers to reallocate renewable energy certificates into or out of their New England Power Pool Generation Information System (NEPOOL GIS) accounts or subaccounts. Instead, EDCs and electric suppliers would be responsible for independently managing their New England Power Pool Generation Information System (NEPOOL GIS) renewable energy certificate accounts. Calpine and Vistra argued that this provision should be removed from the proposed regulation. Calpine and Vistra argued that NEPOOL GIS Operating Rules allow for post-closing REC adjustments but that, as a final step in the process, GIS Administrators request the relevant regulatory authority (in this case, PURA) confirm the adjustment. Calpine and Vistra argued that it would be detrimental to limit NEPOOL GIS Operating Rules through the proposed revision and argued that flexibility is needed to allow for use of RECs that would otherwise be lost. Constellation and RESA similarly requested PURA allow flexibility to continue, in some circumstances, reallocating RECs into or out of supplier NEPOOL GIS accounts so that suppliers are not left with losses and, by extension, increased RPS compliance.

Monthly Load Settlement Data: Calpine and Vistra requested quarterly, instead of monthly, requirements for EDCs to provide suppliers with their load settlement data given that REC trading is also quarterly.

 

UI submits updates Procurement Plan and budget for Year 10 LREC/ZREC including previously disqualified 64 Solar bid

On November 23, 2021, in Docket 19-06-36, the LREC/ZREC Year 10 procurement, United Illuminating Company (UI) filed its updated Procurement Plan for the solicitation. As last discussed in Flash Update 91.4, the Public Utilities Regulatory Authority (PURA) ruled that a previously disqualified Medium ZREC bid by 64 Solar should be selected for contract execution, and the updated filing by UI reflects the procurement results with the 64 Solar project included. The newest filings show that the Medium ZREC project category has $117,532.50 in remaining funds, whereas before the 64 Solar bid was accepted there were $147,613 in remaining funds. The other project size tranches remain unchanged from the previous Procurement Plan discussed in Flash Update 90.7, with $181,584 Large ZREC funds remaining and $674,856 LREC funds remaining. As Year 10 was the last year of LREC/ZREC procurements, there are no known next steps in the program for United Illuminating. The successor Non-Residential Tariff program last discussed in Special Flash update 92.3.2 will begin in February of 2022.

 

Other Connecticut News of Note

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Rhode Island

National Grid files its recovery factor for long-term contracting for renewable energy

On November 15, 2021, in Docket 5201, National Grid filed its proposed recovery factor for long-term contracting (LTC) of renewable energy pursuant to Rhode Island Public Utility Commission (PUC) Rule 810-RICR-00-00-1.10. National Grid proposed a recovery factor of 0.290¢/kWh for all customers effective January 1 through June 30, 2022. This is a decrease from the recovery factor of 0.680¢/kWh that was in place from July 1 through December 31, 2021. The proposed LTC recovery factor is designed to recover the estimated costs of the company's executed long-term contracts and the estimated administrative costs it will incur to bid the capacity of qualified customer-owned distributed generation facilities into the ISO-NE Forward Capacity Market. The proposed LTC recovery factor on a typical residential customer using 500 kWh/month would decrease by $2.04/month.

 

OER files recommendations for the 2022 Renewable Energy Growth Program Year with PUC

On November 29, 2021, the Rhode Island Office of Energy Resources (OER) filed its [http://www.ripuc.ri.gov/eventsactions/docket/5202-DGBoard-Recommendations%20for%20the%202022%20REG%20Program%20(11-29-21).pdf Recommendations for the 2022 Renewable Energy Growth Program Year] with the Public Utilities Commission (PUC) in Docket 5202. The filing includes proposed program classes (including the breakout of the medium solar class into two sub classes), updated ceiling prices for each proposed class, and discussion of National Grid's decision to discontinue the Solar Carport Adder pilot including a discussion of SEA’s (acting as consultant to OER) updated Solar Carport Adder benefit cost analysis (BCA, see the testimony of Jason Gifford). A table containing the recommended ceiling prices, followed by a table containing the recommended MW allocation plan, is provided below:

As discussed in Flash Update 92.1, unlike previous program years, the proposed ceiling prices for the 2022 Program Year have generally increased relative to the 2021 Program Year ceiling prices (with the exception of the Large Solar class). As discussed in Digest 91, these increases are a product of upward cost pressures resulting from the COVID-19 pandemic and other economic factors which resulted in increased capital, materials, labor and transportation costs relative to 2021. These cost pressures were offset somewhat by forecasted declines in solar prices, which, for the Large Solar class, was sufficient to reduce ceiling prices relative to 2021.

These cost pressures also contributed to a less-favorable benefit-cost ratio in SEA’s updated Solar Carport Adder analysis. Specifically, SEA found that, based on inflated capital costs, the calculated Carport adder revenue requirement under current market conditions ranged between 8.2 and 12.2 cents/kWh. Due to this increased cost, SEA’s updated BCA found the net-benefits of the program to be negative in most scenarios tested.

 

FERC Denies Green Development Request for Rehearing regarding arguments against National Grid DAF charges

As discussed in Digest 88, on February 10, 2021, Green Development filed a Complaint against the National Grid affiliates Narragansett Electric Company (which owns distribution and transmission assets in Rhode Island) and New England Power Company (which owns and operates bulk power transmission systems and operates some of Narragansett's transmission assets), arguing that National Grid passed on unauthorized Direct Assignment Facility (DAF) charges to Green Development solar projects. As discussed in Flash Update 91.4, on September 23, 2021, in Docket EL21-47, FERC issued an Order, rejecting the majority of Green Development's arguments. FERC agreed with Green Development that National Grid had failed to comply with one requirement for DAF charges, specifically the requirement that DAFs be "specified in a separate agreement among ISO-NE, the Interconnection Customer, and the Transmission Customer, as applicable, and the Transmission Owner whose transmission system is to be modified." FERC found that New England Power "may not assess [DAF] charges to Narragansett in association with the upgrades necessary for the Projects unless and until it complies with this part of the definition."

The ISO-NE Tariff defines a DAF as follows:

Facilities or portions of facilities that are constructed for the sole use/benefit of a particular Transmission Customer [in this case, Narragansett] requesting service under the [ISO-NE Tariff] or a Generator Owner requesting an interconnection. Direct Assignment Facilities shall be specified in a separate agreement among the ISO, Interconnection Customer and Transmission Customer, as applicable, and the Transmission Owner whose transmission system is to be modified to include and/or interconnect with the Direct Assignment Facilities, shall be subject to applicable Commission requirements, and shall be paid for by the Customer in accordance with the applicable agreement and the Tariff.

On October 25, Green Development filed a Request for Rehearing, arguing that Green Development met ISO-NE’s criteria to prove that "Facilities or portions of facilities that are constructed for the sole use/benefit of a particular Transmission Customer requesting service under the [ISO New England Inc. Transmission, Markets, and Services Tariff (“ISO-NE Tariff”)] or a Generator Owner requesting an interconnection."

On November 26, FERC issued a Notice of Denial of Rehearing, announcing that as FERC has not acted, the Request for Rehearing is deemed denied by operation of law and stating that it will address the subject matter of the rehearing request in a future Order.

 

Other Rhode Island News of Note

 

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Maine

DEP suspends NECEC permit, construction halted until Courts reach a determination

As discussed in Flash 90.4, on August 12, 2021, Melanie Loyzim, Commissioner of the Maine Department of Environmental Protection (DEP), sent a letter notifying Central Maine Power (CMP) that she would exercise her discretional authority to initiate proceedings to consider suspension of DEP’s May 2020 Order approving CMP’s applications for State land use permits for its New England Clean Energy Connect (NECEC) project. The NECEC project would be a 1,200 MW HVDC transmission line that would run from Québec to Lewiston, Maine. Commissioner Loyzim’s letter was issued after the Maine Superior Court Order in Black v. Cutko vacated a one-mile tract lease granted to NECEC Transmission (a subsidiary of CMP) for the NECEC project located in Johnson Mountain Township and West Forks Plantation (discussed in Digest 91).

As discussed in Flash Update 91.7, on October 19, the DEP held its first suspension hearing for the NECEC project. See Flash Update 92.4 for coverage of the post-hearing briefs that followed the suspension hearing.

As discussed in Flash Update 92.2, on November 2, a ballot measure that would ban construction of high impact transmission lines in the Upper Kennebec region, require legislative approval for such projects outside of the region and 2/3 approval for projects using public lands, passed in a referendum. On November 3, Avangrid and NECEC LLC (a subsidiary of CMP) issued a press release announcing that it had filed a lawsuit challenging the ballot initiative in Maine Superior Court, as well as a motion for a preliminary injunction. As discussed in Flash Update 92.2, on November 5, 2021, Commissioner Loyzim scheduled a public hearing for November 22, to consider whether “additional changes in circumstance” should cause the agency to suspend its construction permit if the referendum result becomes law. As discussed in Flash Update 92.4, On November 19, Governor Janet Mills proclaimed and certified the results of the referendum, earlier than expected and well within the 10-day time frame the Maine Constitution allows her to do so. The legislation will go into effect 30 days following the Governor’s proclamation (barring a Court injunction as a result of NECEC LLCs legal challenge of the referendum).

November 22 Hearing and November 23 Suspension

On November 22, the DEP held its second suspension hearing, this time focusing on whether the referendum results constituted a change in condition or circumstance requiring suspension of the May 2020 Order approving CMP's land-use permits. Recordings of the hearing are available here: Part 1 and Part 2.

At the hearing, NECEC LLC and its supporters argued that the referendum results did not constitute a change in circumstances that would require suspension of the May 2020 Order because:

The Natural Resources Council of Maine (NRCM), West Forks (made up of West Forks Plantation, the Town of Caratunk, Kennebec River Anglers, Maine Guide Service, LLC, Hawks Nest Lodge, and nine individuals )and the Friends of Boundary Mountains disputed the viability of alternative routes argued that the referendum results should be presumed constitutional until proven otherwise and argued that continued construction would create further environmental harm.

Stakeholders also disputed the definition of 'Upper Kennebec Region.' The legislation attached to the ballot initiative bans high impact transmission lines in the Upper Kennebec Region, requires legislative approval for the construction of high-impact electric transmission lines anywhere in Maine and requires approval of the legislature (by a two-thirds vote) if the transmission line crosses public lands, defined by Title 12, section 598-A. While the ballot measure bans the construction of high impact transmission lines in the Upper Kennebec Region, the region was not defined in law before the ballot initiative. The ballot measure defines the Upper Kennebec Region as "the approximately 43,300 acres of land located between the Town of Bingham and Wyman Lake, north along the Old Canada Road, Route 201, to the Canadian border, and eastward from the Town of Jackman to encompass Long Pond and westward to the Canadian border, in Somerset County and Franklin County." However, this definition does not provide an exact boundary of land included in the region. The PUC and courts will eventually determine what is included in the Upper Kennebec Region for the purposes of the ballot measure.

As announced in Special Flash 92.4.1, on November 23, Commissioner Loyzim suspended the May 2020 Order due to the referendum results, while deferring a decision on whether the Black v. Cutko ruling also required suspension. In her decision, Commissioner Loyzim determined that while the specific boundaries of the Upper Kennebec Region are not yet clear, NECEC LLC has previously acknowledged in litigation that the ballot measure ban would apply to the NECEC project. Loyzim also reasoned that alternative routes presented by NECEC LLC would not likely be viable. Loyzim concluded that "this point there is not a reasonable likelihood of the Project being able to deliver power." The suspension stopped construction immediately. The suspension is effective unless and until:

According to the Portland Press Herald, on November 29, the Natural Resources Council of Maine, the Sierra Club, and the Appalachian Mountain Club wrote a letter to the U.S Army Corps of Engineers and the U.S. Department of Energy asking for the agencies to suspend or stay their permits for the NECEC project.

 

PUC issues 2-stage RFP for Transmission and Generation in Northern Maine; transmission bids due March 1, 2022 generation bids due May 1, 2022

As discussed in Flash 89.5, on June 29, 2021, Governor Janet Mills (D) signed LD 1710 - An Act To Require Prompt and Effective Use of the Renewable Energy Resources of Northern Maine into law as Chapter 380. Among its initiatives, Act 380 requires the Public Utilities Commission (PUC) to issue two procurements:

These procurements are a very significant opportunity for the development of renewable energy resources and present one of the best chances for the development of large land-based wind projects in Northern Maine.

In Flash Update 91.4, we summarized the PUC's Notice of Inquiry (NOI) for the procurement in Docket 2021-00223 and the comments filed in response to the NOI. As announced in Special Flash Update 92.4.2, on November 29, 2021, in Docket 2021-00369, the PUC issued its RFP. Transmission bids are due March 1, 2022, generation bids are due May 1, 2022.

RFP Process

The RFP includes the following schedule:

The RFP seeks proposals for both renewable energy generation projects in Northern Maine (defined as Aroostook County and other areas in Maine administered by the Northern Maine Independent System Administrator (NMISA)) and the transmission line (or lines) that will carry power from the generation projects to the ISO-NE system.

The RFP will proceed in two phases. In Phase 1, the PUC will consider transmission project proposals. In Phase 2, the PUC will consider generation project proposals. Generation bidders will have access (under a Non-Disclosure Agreement) to Transmission Project Relevant Information (TPRI) provided by the transmission project bidders. The PUC noted that it will work to ensure that generation projects will have fair access to transmission project information, and that the PUC has structured the RFP to achieve that goal.

Transmission Project Requirements and Preferences

As required by Chapter 380, the PUC is requesting proposals for a 345-kV or greater capacity double circuit transmission line delivering power from renewable energy resources in Northern Maine to ISO-NE. The RFP states that the PUC prefers projects allowed under ISO-NE authority, processes, and tariffs. Acceptable projects include the following:

We provided an explanation of each of the above options in Flash Update 91.4. We note that to date, no METU or PPTU has ever been identified in ISO-NE, and that most comments responding to the NOI argued that an ETU approach is the most likely transmission option.

The PUC has not yet released the essential terms that it will expect to be included in an eventual Transmission Service Agreement (TSA) between the state’s transmission project and transmission and distribution (T&D) utilities, but will eventually release these terms on the RFP website.

The RFP outlines the minimum information that must be included in transmission project proposals, including, among other requirements, project design, approval processes, ratepayer impacts, and benefits provided towards Maine's energy goals. Additionally, the RFP requests that proposals address the topic of approval from the Maine Legislature following the results of the November 2, referendum. As discussed in Flash Update 92.2, Maine's November 2, 2021 election included a ballot question asking Maine voters “Do you want to ban the construction of high-impact electric transmission lines in the Upper Kennebec Region and to require the Legislature to approve all other such projects anywhere in Maine, both retroactively to 2020, and to require the Legislature, retroactively to 2014, to approve by a two-thirds vote such projects using public land?” The ballot initiative defines "high impact electric transmission lines" as transmission lines 50 miles or more in length for direct-current electricity or capable of operating at more than 345 kV, with the exception of generator interconnection transmission facilities or lines determined by the PUC to deliver electric reliability. To clarify the effect of the referendum, the ballot initiative legislation (accessible at the above link) bans high impact transmission lines in the Upper Kennebec Region, requires legislative approval for the construction of high-impact electric transmission lines anywhere in Maine and requires approval of the legislature (by a two-thirds vote) if the transmission line crosses public lands, defined by Title 12, section 598-A. On November 2, Maine voters passed the ballot initiative, and the legislation is set to become law on December 19 (30 days after Gov. Mills certified the election results), barring the issuance of a preliminary injunction requested by Avangrid, the parent company to Central Maine Power and New England Clean Energy Connect LLC, discussed in Flash Update 92.2 and further in this Flash Update.

The PUC noted that it would prefer transmission pricing to be structured on a $/kW/month basis. Additionally, any variable pricing structure (i.e., cost of service, indexed, non-fixed price) must include a cap for the costs to be paid by Maine’s T&D utilities under the terms of the TSA.

Each transmission project proposal must include a security deposit of $100,000, to be refunded if the project is not selected or replaced with the "Project and Performance Security" if the project is selected. Each transmission proposal must also include a completed Project Relevant Information Form, the content of which will be made available to generation bidders according to the above schedule.

Generation Project Requirements and Preferences

Qualifying generation projects must meet the following requirements:

Generation projects would sign PPAs with T&D utilities, and the PPA may include one or any combination of energy, capacity, and RECs. The PUC plans to post a standard form PPA on the RFP website. The PUC stated that it would prefer PPA terms of 20 years. Proposals may be structured as physical or financial transactions, and may have separate prices for energy, RECs and/or capacity. The PUC noted that it would prefer energy-only proposals.

Among other requirements, generation project proposals must indicate which transmission project(s) the generation project intends for interconnection, including contingencies if the PUC does not select the desired transmission project. The same generation project may submit multiple pricing proposals dependent on the generation project's preferred transmission project. All bids including an energy storage system must also submit a separate bid without energy storage.

Evaluation Criteria

The RFP does not divide the evaluation criteria between generation and transmission, nor attribute point values to specific criteria. Criteria include the following:

We note that Chapter 380 requires that the PUC show preference to proposals which favor the construction of transmission line(s) along existing utility rights-of-way and other existing transmission corridors.

Next Steps

The PUC will continue to upload forms and documents to the RFP Website.

 

CMP and MREA/CCSA file briefs on PUC jurisdiction related to cluster studies; reply comment period extended amidst ongoing settlement negotiations

On November 17, 2021, in Case 2021-00270, in which the Coalition for Community Solar Access (CCSA) and Maine Renewable Energy Association (MREA) are requesting transparency and efficiency improvements to Central Maine Power’s (CMP’s) cluster study process (last discussion in Flash Update 92.1), CCSA and MREA filed a brief on jurisdictional questions posed by the Public Utility Commission (PUC). The following day, on November 18, 2021, CMP filed its brief on the same jurisdictional questions. Generally, CCSA & MREA argued that the PUC has broad jurisdiction with regard to transmission cluster study investigation and prescribing remedies for cluster study timing, group formation, and the interconnection of generators to the distribution system, while CMP argued that PUC jurisdiction is limited to cluster study cost allocation, allocation of network upgrade costs, and the study attrition process.

Reply Briefs were scheduled to be due on November 24, 2021. However, on November 23, the PUC issued a Procedural Order granting CMP's Request for an Extension to file Reply Briefs until December 22, 2021. CMP’s Request for Extension noted that CMP, CCSA and MREA are engaged in settlement discussions on the issue raised in both the cluster study instant docket and Case 2021-0035, the investigation of CMP interconnection practices last discussed in Flash Update 92.3. CMP's Request for an Extension noted that though there have been multiple requests for extension in both dockets, CMP believes that "a settlement is feasible" and would be "in the interest of all stakeholders."

 

Agricultural Solar Stakeholder Group holds final meeting on December 16, releases draft report overviewing agricultural siting policies and recommending dual-use pilot program and incentives to preserve farmland

On November 12, 2021, the Agricultural Solar Stakeholder Group released its Draft Report on balancing farmland protection and renewable energy production in Maine. The initial report, once finalized, will be presented to the Department of Agriculture, Conservation and Forestry (DACF) and the Governor's Energy Office (GEO). The next and final meeting of the Agricultural Solar Stakeholder Group is scheduled for December 16, 2021, from 9:00 am - 12:00 pm and interested stakeholders can register to attend the virtual meeting here. We provide a summary of the report below.

The Draft Report observed that the Working Group was formed by DACF and GEO in response to L.D. 820 – Resolve, To Convene a Working Group To Develop Plans To Protect Maine’s Agricultural Lands When Siting Solar Arrays to recommend ways to protect agricultural land while also fostering the growth of solar in Maine consistent with the legislatively mandated greenhouse gas reductions and the "Maine Won’t Wait" climate action plan. The Draft Report gives an overview of both the photovoltaic solar programs and the economic contributions of the agricultural industry in the state.

Other States: The Draft Report reviews the agricultural solar siting policies in three other states, Massachusetts, New Jersey and Vermont, for lessons learned. The group found that the Massachusetts solar program has made changes to require solar on greenfields to be dual-use and document agricultural output, and while some aspects could be transferable to Maine, the two states differ significantly in ways that would affect solar siting on agricultural land. New Jersey faces similar agricultural land loss, and the report notes that New Jersey has a dual-use pilot program for 200 MW of solar with stipulations that the solar must be sited on "unprotected" (i.e., not prime) farmland in addition to other safeguards. The Vermont Public Utility Commission's (PUC's) Certificate of Public Good (CPG) process allows Vermont’s Agency of Food and Markets to weigh in on projects on farmland, and there are policy incentives to discourage siting on greenfields and encourage siting on parking lots, brownfields, and landfills. The Draft Report also notes that farms in Vermont can install solar arrays up to 500 kW and retain “current use” taxation status if at least 50% of the solar project output is consumed on the farm.

Stakeholder Perspectives: The Maine Audubon Society presented data from the GIS Maine Renewable Energy Siting Tool showing that of 180 projects that triggered Department of Environmental Protection (DEP) review, 43% are proposed to be on high-value habitat, 49% are proposed to be on large forest blocks, 58% are on high-value agricultural land, and 89% are on high-value agricultural blocks (the distinction between "land” and “blocks” is that blocks are contiguous areas of agricultural or forest land). Only 9% were proposed to be located on brownfields or landfills, which often lack access to transmission infrastructure.

The Maine Municipal Association (MMA) raised concerns that sheltering agricultural land with solar installed on it in current use tax status harms municipal revenue, and argued that "farmland developed for solar should be removed from current use tax programs." Additionally, MMA noted that volunteer planning boards are not always equipped to grapple with solar development in their towns.

Nexamp commented on the uncertainty of interconnection costs for solar projects, and outlined a number of policies that Nexamp supports, such as pollinator scorecards and mitigation fees for the lost value of farmland.

BlueWave Solar argued for a voluntary dual-use market for "agrivoltaics" and pointed to two projects under development by BlueWave in Maine that integrate agriculture and sheep grazing with the solar arrays as examples that solar siting can coexist with farming.

Clemedow Farm's presentation focused on the farm's process of attempting to install solar on 45 of 1000 acres of its farmland, and noted that local permitting has been challenging and that most farmers do not have the resources to research the legal and tax implications of installing solar on their land.

The Department of Environmental Protection (DEP) noted that projects over 20 acres trigger Site Law review, and that DEP is conducting a rulemaking to allow projects between 20-50 acres to obtain Permit by Rule instead of the traditional permitting process. Projects greater than one acre trigger stormwater management review. DEP also noted that it is developing pilot projects to examine grazing as a form of vegetation management for solar arrays. Recently enacted P.L. 2021 ch. 151 will require a decommissioning plan and decommissioning financial assurance from projects over three acres, as well as requiring the removal of inground solar components up to 48 inches deep.

The Maine Revenue Services Property Tax Division presented to the Stakeholder group that land is taxed at its highest and best use, which is generally not farming. However, the Farmland Tax Program can, if certain criteria are met, allow agricultural land to be taxed based on "current use" rather than market value. Generally, conversion to energy generation would take land out of the Farmland Tax Program, however, there is a legislative exception for solar projects under "5 MW which provides net energy billing credits solely to the farm." In these instances, the solar equipment is tax-exempt, the state reimburses the town for 50% of the lost revenue on the solar equipment (but not the land value). Dual-use projects not enrolled in the net energy billing (NEB) program would be removed from current use, but "it is unclear at this time" whether a project that offsets load on a farm through the NEB program but also exports power to the grid would be covered by the Farmland Tax Program.

The Working Group has tabled consideration of a siting scorecard and an in-lieu fee (where solar development on agricultural land would trigger some manner of payment).

Recommendations: The Working Group's Draft Report would adopt the following recommendations for solar siting on agricultural land:

The December 16, 2021 meeting mentioned above is the last meeting of the Working Group, after which the Working Group will present a finalized report to the DACF and GEO.

 

76.5 MW Farmington solar project in Maine has entered service, will supply power to five New England colleges

On October 27, 2021, the 76.5 MW Farmington Solar project went online. As first discussed in Digest 67, the project was initially a 49.36 MW project, but increased in size following the signing of a 20-year PPA with the New England College Renewable Partnership, made up of Bowdoin College, Hampshire College, Smith College, Amherst College and Williams College. The colleges' PPAs will help them achieve each of their climate action goals while also increasing the predictability of their electricity costs. A subsidiary of NextEra Energy Resources developed the project and Competitive Energy Services acted as an adviser to the colleges.

 

FERC issues NOI to prepare EIS for the four Kennebec River dams for effects on endangered Atlantic salmon

On November 20, 2021, FERC issued a Notice of Intent (NOI) to prepare a draft and final Environmental Impact Statement (EIS) to evaluate the effects of relicensing the Shawmut hydroelectric project (FERC Project No. 2322) and amending the licenses of the Hydro-Kennebec, Lockwood, and Weston hydroelectric projects. FERC previously issued a Draft Environmental Assessment (DEA) for relicensing the Shawmut project in July, which received numerous comments compelling FERC to complete a more comprehensive EIS to fully evaluate the impacts of the four projects on the migratory fish populations of the Kennebec River. Brookfield Renewables owns all four of the projects, which are located on the Kennebec River and have faced opposition surrounding their impact on Atlantic salmon populations in the river (as recently discussed in Flash Update 92.1). The NOI noted that FERC anticipates the relicensing-related actions to require a Water Quality Certification by the Maine Department of Environmental Protection (DEP), per the Clean Water Act Section 401, as well as an Endangered Species Act Section 7 Consultation by the National Marine Fisheries Service. As discussed in Flash Update 92.2, Brookfield Renewables submitted an application to the Maine DEP seeking a Water Quality Certification for the Shawmut Dam on October 15.

FERC is accepting public comment regarding how to scope the issues covered in the EIS until December 30, 2021, and details on how to comment can be found in the notice. The EIS will address previously raised concerns from the earlier Shawmut Project scoping process and DEA, so comments filed during those windows do not need to be resubmitted. FERC intends to issue the draft EIS in August 2022, and the final EIS by February 2023, though notes the possibility of schedule changes.

 

Efficiency Maine Trust reports that it issued 12 awards for installation of 58 Level 2 charging ports in EV charging pilot

As discussed in Digest 83, on August 28, 2019, in Case 2019-00217, as required by statute, the Maine Public Utilities Commission (PUC) issued a Request for Proposals (RFP) for pilot programs to support beneficial electrification in the transmission sector. On February 25, 2020, the PUC issued an Order approving a proposal by Central Maine Power Company (CMP), to establish a "Make Ready Pilot Program" that will distribute subsidies of up to $4,000 each to support the construction of sixty (60) Level 2 chargers (Level 2 chargers are 240v whereas Level 1 charges are 120v).

On November 17, the Efficiency Maine Trust (the Trust) released an interim update on the implementation of the proposed pilot program. In all, the Trust has held five rounds of RFPs for Level 2 chargers. See below for the list of projects awarded under Round three and round four:

In all, the Trust issued twelve awards totaling 58 charging ports, with the average total project cost per port landing at $7,031. Eligible locations included qualified multi-unit dwellings, workplaces, or locations open to the public (including government properties). EMT offered incentive amounts of up to $2,000 per port for non-networked chargers and $4,000 per port for networked chargers. Three of these installations have been completed and reimbursed to date, with the remaining Round 3 installations expected by January 6, 2022, and the Round 4 installation expected by the spring of 2022. Proposals for Round 5 are due on January 20, 2022, with awards expected in early February.

The Trust found that the electric vehicle and EV charger industry is undergoing rapid changes, with a greater adoption of networked chargers and a transition of charging equipment from the charger to electric vehicles themselves. They also noted that prior guidance and conventional wisdom suggested EVs would need to be charged at public chargers at similar rates as internal combustion vehicles (ICEVs), but it is becoming more clear that EV drivers prefer to charge overnight at home (generally, using Level 1 and 2 charging stations), and that Level 2 public charging infrastructure may not be as highly utilized as once assumed. Off-peak charging, the Trust added, should be encouraged through innovative rate to reduce strain on the electric grid. Finally, the Trust highlighted how the results of this pilot program can inform future EV charging incentive design. They suggested that $5,000 may be a more appropriate incentive amount for networked chargers, due to the $7,031 per port cost that they determined, while $2,000 or potentially less should be sufficient for non-networked chargers.

The Trust is currently in the process of creating a series of “guidebooks” for potential EV charging hosts, the first of which was released in September: “How to Select and Install a Home Electric Vehicle Charger”. The next guidebook, “How to Charge Your EV at Home and Away,” is scheduled for an early 2022 release.

 

ReVision submits comments arguing proposed Versant O&M cost methodology overallocates costs to interconnecting customers; PUC delays implementation of O&M costs until February 2022

On November 18, 2021, in Case 2021-00351, in which Versant Power (Versant) has proposed a new Section 42 of its terms and conditions (T&Cs), ReVision Energy (ReVision) filed comments taking exceptions to the proposed cost allocation methodology. As last discussed in Flash Update 92.2, Section 42 governs the monthly operations and maintenance (O&M) costs of non-FERC jurisdictional interconnection facilities and distribution upgrades installed under Chapter 324.

ReVision argued that:

On November 23, 2021, the Maine Public Utility Commission (PUC) issued a Suspension Order that suspended the proposed T&Cs until February 26, 2022 to give the PUC adequate time to review the proposal. As discussed in Special Flash Update 92.3.1, On November 32, 2021, the PUC held a technical conference on the O&M costs, (transcript of the technical conference can be viewed here) as well as a Notice of Filing, request for comment and opportunity to intervene. Post-technical conference briefs are expected to be the next step in this Docket.

 

Versant submits two Joint Offers of Settlement between itself and MPUC to resolve issues raised in response to Versant's Order 864 filing, 2020 annual transmission charges update

On November 19, 2021, Versant Power filed a Joint Offer of Settlement between itself and the Maine Public Utilities Commission (PUC) regarding issues raised to FERC by the PUC about Versant's annual transmission charges update for Bangor Hydro District filed on June 15, 2020 (the Annual 2020 Update) in Docket ER15-1434 under Section 21-EM of the ISO-NE Transmission, Markets, and Services Tariff. Through Schedule 21-VP of the ISO-NE Open Access Transmission Tariff (OATT), Versant provides service over non-Pool transmission facilities (non-PTF). On September 14, 2020, MPUC communicated to Versant certain disputes about its 2020 Annual Update, which the two parties were able to resolve. If the Joint Offer of Settlement is approved by FERC, it will resolve all issues raised by the PUC. Interested parties must comment on the Offer of Settlement by December 9, 2021, and Reply Comments must be filed by December 19, 2021.

On November 22, 2021, Versant Power filed a Joint Offer of Settlement between itself and the PUC regarding issues raised by the PUC regarding Versant's compliance with FERC Order 864. FERC issued Order 864, which was issued in November 2019 required that all public utility transmission providers with formula rates under an OATT "revise those transmission formula rates to account for changes caused by the Tax Cuts and Jobs Act of 2017 (TCJA)." The TCJA, which President Trump signed in December 2017, among other things, reduced federal corporate income tax rate from 35% to 21% effective January 1, 2018. Versant submitted a compliance filing with Order 864 on June 23, 2020 which spurred several back and forth requests for information and deficiency letters between itself and the PUC. Ultimately, in settlement discussions, Versant and PUC were able to resolve their differences, resulting in a stipulation included in the Joint Offer of Settlement. If the Joint Offer of Settlement is approved by FERC, it will resolve all issues raised by the PUC. Interested parties must comment on the Offer of Settlement by December 13, 2021 and Reply Comments must be filed by December 22, 2021.

 

CMP files Petition for advisory ruling on definition of "aggregated generation" when screening for Level 2 interconnections, argues definition should include all generation with an executed interconnection agreement

On November 19, 2021, in Docket Case 21-00372, Central Maine Power (CMP) filed a Request for Advisory Ruling seeking guidance from the Public Utility Commission (PUC) on how electric distribution companies (EDCs) should treat Level 2 Interconnection applications. Specifically, CMP requested clarification on how to implement the PUC's ruling in Case 2021-00084 (the Maynard Ruling), (summarized in Digest 89). In the Maynard Ruling the PUC found, in CMP's wording, that "utilities should disregarding other proposed interconnections when performing screening for proposed Level 2 interconnections" (Level 2 projects have a capacity of between 25 kWAC and 2 MWAC and receive faster interconnection processing times, Level 4 projects have a capacity greater than 10 MWAC and a longer interconnection process).

CMP argued that the Maynard Ruling is "untenable" for the EDCs. CMP's petition maintained that to operate the electric system safely and reliably, CMP must consider generation that may come online when studying the interconnection of generation facilities. In particular, CMP noted that facilities with a signed interconnection agreement have a legal right to reach commercial operation. But under the ruling in Case 2021-00084 as CMP interprets it, the EDC might encounter a situation where, if level 2 projects seek to interconnect ahead of Level 4 projects after the Level 4 project has a signed interconnection agreement, upgrades would be required to accommodate projects without a way to allocate costs to the interconnecting customer.

CMP argued that "aggregate generation" used in CMP interconnection screening and planning should include all generation with an executed interconnection agreement. CMP requested that the PUC, in an advisory ruling, answer the following questions (listed verbatim):

No other stakeholders have commented on the case so far, nor has the PUC issues a procedural schedule.

 

PUC issues advisory ruling denying Renergetica request for interconnection cost-sharing exemption for level 4 project

On November 18, 2021, in Case 2021-00297, the Public Utility Commission (PUC) issued an Advisory Ruling denying Renergetica’s request for interconnection cost-sharing exemption for its Level 4 Houlton Road Solar Farm (HRSF) project. Renergetica had requested that a Level 4 project be defined as "aggregate generation" or in the alternative, exempted from further cost allocation with level 2 projects (as last discussed in Flash Update 91.5).

Renergetica, had executed an interconnection agreement with Versant Power (Versant) and paid the interconnection deposit prior to the Maynard Ruling, but after the Maynard Ruling a Level 2 project interconnected ahead of the HRSF project on the same circuit as the HRSF project due to the Chapter 324 rules. (In the Maynard Ruling, the PUC ruled that the definition of "aggregate generation," for the purposes of performing a Level 2 screen, "does not include proposed generation other than that of the proposing generator" and therefore the HRSF project was not factored into the interconnection screening of the Level 2 project.) The Level 2 project's interconnection caused the HRSF project's interconnection costs to rise from $267,000 to an estimated $1.2 to $1.7 million, and delayed the interconnection timeline. After negotiations with Versant, Renergetica reduced its project by 250 kWAC to a total of 1.72 MWAC so that Renergetica would only be responsible for the initial interconnection upgrade costs of $267,000. However, Versant could not assure Renergetica that another Level 2 project would not enter into an interconnection agreement with Versant, leading to a similar situation. Therefore, Renergetica sought an Advisory Ruling that its project would either be treated as aggregate generation or receive an exception from the cost-sharing requirements for Level 4 projects, arguing that it cannot proceed with the project under the current uncertainty over development timelines and interconnection costs. (Level 2 projects have a capacity of between 25 kWAC and 2 MWAC and receive faster interconnection processing times, Level 4 projects have a capacity greater than 10 MWAC and a longer interconnection process.)

The PUC denied Renergetica's request to be shielded from further cost allocation, upholding its decision in Case 2021-00084 (Maynard’s Advisory Ruling). The PUC found that there was no justification for exempting the HRSF project from the same cost-sharing requirements as other Level 4 projects. However, in doing so, the PUC acknowledged that the issues raised by Renergetica are important and that they should be addressed in a rulemaking, likely referring to Docket 2021-00167 where the PUC is reviewing the screening of Level 2 projects for interconnection.

 

Maine DOT releases Searsport offshore wind port feasibility study

On November 23, 2021, Governor Janet Mills announced her administration’s plan to evaluate multiple port development options and offshore wind uses at the Port of Searsport, the Port of Portland, the Port of Eastport, as well as others. This announcement follows the Maine Department of Transportation’s (MaineDOT) November 18 presentation of the Feasibility Study and Concept Design Report to the Governor’s office. The study was produced in response to Governor Mills’ March 2020 request for the MaineDOT to study how the Port of Searsport (one of Maine's largest seaports) could contribute to offshore wind growth in Maine, as discussed in Flash Update 80.3.

The study, prepared for MaineDOT by infrastructure advisory firm Moffatt & Nichol, analyzed the physical and technical characteristics of various sites in the Port of Searsport and found that Mack Point and part of Sears Island could be considered for offshore wind hub locations. Sprague Put Parcel and the GAC Chemical site were also considered initially, though both sites were removed from consideration in the study due to dredging and related cost criteria. The study recommends that Sears Island be further studied for possible phased development, so that impacts and alternatives can be properly evaluated, as would be required by federal and state permitting. A broader study on offshore wind and ports in Maine that looks at Ports of Portland and Eastport is still underway, and is anticipated to be completed in a few months. According to the Governor’s announcement, New England Aqua Ventus’ demonstration project, slated for deployment in 2024, is expected to use the ports of Eastport and Searsport for assembly and transportation.

 

Nexamp requests that PUC allow access to customer records for NEB project sponsors

On November 22, 2021, Nexamp filed a Request for Waiver or Clarification with the Maine Public Utilities Commission (PUC) in Docket 2021-00375. Specifically, Nexamp requested a waiver of Chapter 815, Section 4 (Consumer Protection Standards for Electric and Gas Transmission and Distribution Utilities) stating that project sponsors of Net Energy Billing (NEB) projects can request information from utilities for customers who have given affirmative authorization. Alternatively, Nexamp suggested that the PUC could clarify that a prior waiver granted to Central Maine Power (CMP) in Docket 2020-00180, which allowed projects access to commercial and industrial customer information, applies to project sponsors who serve non-commercial customers. Nexamp stated that it needs the customer information "to ensure that customer subscriptions are appropriately sized to a customer’s historical usage, and that subscription bills (bills from Nexamp to customers for subscription charges) accurately reflect the interaction between customers’ NEB kilowatt-hour credits and their electric charges."

 

PUC issues procedural order denying EV rate design waivers to small utilities; VBLPD and EMEC respond to order by updating existing rate schedules to include EV charging

As discussed in Flash Update 92.4, on September 30, 2021, in No. 2021-00198, the PUC issued a Procedural Order requiring Maine’s transmission and distribution (T&D) utilities to file by November 1, 2021 proposed rate schedules for “nonresidential electric vehicle applications, including, but not limited to, those for light duty vehicles, medium duty vehicles, heavy duty vehicles and transit and other fleet vehicles.”

On November 1, 2021, Versant Power and Central Maine Power Company (CMP) filed rate schedules. Several smaller utilities, including consumer-owned utilities (COUs), made comments and requested waivers from submitting the rate schedules, citing various reasons why they shouldn’t be required to file rate schedules mandated by L.D.347, An Act To Facilitate Maine's Climate Goals by Encouraging Use of Electric Vehicles (Chapter 402, enacted by Legislature in 2021 session).

On November 17, 2021, the PUC issued a Procedural Order, noting that chapter 402 does not grant the PUC the authority to issue waivers. The Order notified the COUs that they will be out of compliance with Chapter 402 but announced that the PUC will review and consider proposed rate schedules received by December 10, 2021.

On November 19, 2021, the Eastern Maine Electric Cooperative (EMEC) and the Van Buren Light & Power District filed responses to the procedural order. EMEC altered their Residential Rate (Rate R) to include availability for electric vehicle charging, energy storage, and heat pumps, without altering the existing rate structure. Similarly Van Buren proposed the application of its existing delivery rate to EV charging, reiterating its stance that small utilities should not be required to dedicate limited resources to designing all new rates that would see limited adoption in their service territories.

 

Efficiency Maine Trust submits petition for approval of Triennial Plan; Projects three-year energy cost savings of over $1.57 billion from heat pump, demand management, and electric vehicle infrastructure measures

As discussed in Flash Update 90.4, on June 9, 2021, the Efficiency Maine Trust (The Trust) submitted its draft Triennial Plan V (“the Plan”) (which spans fiscal years 2023, 2024, and 2025 from July 1 to June 30). Initially, the development of the Plan was not highly pertinent to renewable energy markets. However, with the addition of energy storage, heat pump and electric vehicle incentives and other programs to the Trust’s slate of programs, the development of the plan is now a material demand driver for new renewable resources in Maine (and region-wide).

On November 29, the Trust filed a Request for Approval of the Triennial Plan with the Public Utilities Commission (PUC) in Docket 2021-00380. The Trust calculated that the measures installed under this plan over the next three years would lead to energy cost savings exceeding $1.57 billion, $783 million of which would be saved through avoided electricity costs (these savings estimates come with the addendum that $25 million of American Rescue Plan Act funds allocated to efficiency measures were not included in the benefits calculation due to a lack of specified end uses). The final version of the Triennial Plan has a total budget of $302 million over a three-year period. The Trust’s final submission to the PUC for approval included a Program Roll-Up, which breaks down planned expenditures per measure throughout the course of the plan.

In Flash Updates 90.4 and 90.6, we outlined some of the plan’s most renewable energy-relevant provisions, focusing on initiatives dealing with Clean Heating & Cooling, Electric Vehicles, and Demand Response (for which battery storage systems are eligible), and discussed the appendices for these initiatives that used testimony from various individuals within the organization to provide more background and considerations that inform these initiatives. The final versions of these appendices appear to be unchanged from the draft versions that were released in August:

For more in-depth coverage on the provisions and incentives contained in this plan, see our coverage in Flash Updates 90.4 and 90.6.

 

Versant files executed agreement for 40 MW Goose Cove from Tranche 2 procurement

As discussed in Digest 87, on January 15, 2021, in Case 2021-00004, the Public Utilities Commission (PUC) issued an Order (the “January Order”) announcing the issuance of a Tranche 2 Request for Proposals (RFP) seeking energy and/or RECs from Class IA eligible generation units. As discussed in Digest 90, on June 29, the PUC issued an Order (the “June Order”) approving term sheets for the Tranche 2 RFP (individual project term sheets can be found here). The June Order instructed Commission Staff to work with Central Maine Power Company (CMP), Versant Power and the approved developers to develop final contracts.

As discussed in Flash Update 92.1, on October 26, the PUC issued an Order to approve final contracts, and contract reports for Walden Renewables' 40 MWAC Goose Cove Solar project located in Trenton, Maine. The project will receive $28.50/MWh in an energy-only contract in its first year of operations, escalating by 2.5% in each subsequent year. On November 24, Versant Power filed its Executed Agreement with the project.

 

Versant to restudy steady-state analysis for Bangor Hydro District cluster study due to more than 20 MW attrition in the group, study on track for completion in January 2022

On November 29, 2021, in Case 2020-00014 (the proceeding tracking ongoing cluster studies), Versant Power (Versant), filed an update on Cluster Study 3. The update notes that the initial steady-state analysis did not demonstrate any needed upgrades. However, because more than 20 MW of capacity have dropped out of the study, ISO-NE rules require that the cluster be restudied to ensure that there will still be no adverse impacts on the bulk power system.

Versant expects to complete the steady-state reanalysis alongside the dynamic study, with the overall Cluster Study 3 expected to be complete by "mid-January." After study completion, Versant will request review and approval of the applicable proposed plan applications for the impacted projects from the NEPOOL Reliability Committee. Versant attributed the MW attrition to both the reduction in project size to qualify for the Net Energy Billing (NEB) program that caps eligible project size at 2 MW, and projects reducing their size to mitigate interconnection upgrade costs.

 

NEB Good Cause Exemption and Discrete Facility Advisory Ruling trackers updated

SEA’s tracker of good-cause exemption requests to qualify for net energy billing under Chapter 390 can be found here. The tracker tracks exemption petitions, scheduled conferences and related PUC decisions. As discussed in Flash Update 89.6, on July 1, 2021, the Legislature enacted LD 936 - An Act To Amend State Laws Relating to Net Energy Billing and the Procurement of Distributed Generation as Chapter 390 which, among other actions, provides that any project from 2 MW to 5 MW would be “safe harbored” for eligibility under the current net energy billing (NEB) program if the project meets certain requirements and deadlines. As discussed in Flash 90.2, on July 21, 2021, the Public Utilities Commission (PUC), in response to inquiries about how the legislation will be interpreted and how requests for relief will be handled, issued a Notice to provide guidance. The PUC advised that entities which do not meet every statutory requirement to participate in net energy billing should file a good cause exemption petition and cite external delays outside of their control.

SEA's tracker of requests for advisory rulings that projects qualify as discrete facilities can be found here. Chapter 312 (the distributed generation (DG) procurement rule) and Chapter 313 (the net energy billing (NEB) rule) define discrete electric facilities as systems that "cannot be collocated or in geographic proximity to either (1) another eligible facility or (2) a distributed generation resource as defined in Chapter[s] 312 and 313 of the Commission's rules." SEA’s tracker includes all previous requests that fall under the purview of the most recent update to the safe harbor. The tracker will also track requests for advisory ruling and the corresponding PUC orders.

 

Other Maine News of Note

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New Hampshire

PUC rejects utility energy efficiency plans, ordering transition to "market-based" energy efficiency

On November 11, in Docket DE 20-092, the last day of outgoing Chairwoman Dianne Martin, the Public Utilities Commission (Commission) issued an Order, denying the petition of New Hampshire’s gas and electric investor-owned utilities (the Joint Utilities) for approval of their 2021-2023 Statewide Energy Efficiency Plan (Plan), which was originally submitted on September 1, 2020. The Joint Utilities had been awaiting a ruling on their Plan since a December 29, 2020 Order in which the Commission approved a “Short-Term” extension of 2020 energy efficiency programs and the charges that funded them. The Commission ruled on the 2018-2020 energy efficiency plan on January 2, 2018, or nearly a year earlier in the three-year planning cycle than the Order discussed in this article. In its Order, the Commission rejected the Joint Utilities’ filed plan, instead ordering them to submit a new plan based in system benefit charges (SBCs) mandated by the Commission. The Commission further ordered the charges that fund the energy efficiency programs to return to their 2017 levels by 2023. As a result, incentives for activities such as demand response (including storage) and space heating electrification are likely to decrease or possibly be eliminated.

Energy Efficiency Plan Description: The total, 2021-2023 gas and electric budget of the filed Plan was $393 million, up from a total of $176 million for the 2018-2020 period. While electric SBCs varied by utility, according to the Commission’s analysis, by 2023, they would have reached an average of 1.259¢/kWh for commercial and industrial (C&I) customers and 0.862¢/kWh for residential customers, up from 0.528¢/kWh for all customer classes in 2020. For perspective, the current energy efficiency SBC for Massachusetts National Grid customers is 0.938¢/kWh for C&I customers 1.729¢/kWh for residential customers, both of which are expected to increase as Massachusetts enters its 2022-2024 energy efficiency period. While the Joint Utilities’ Plan introduced some new elements, such as an increased focus on electrifying space heating, the proposed increased budget largely reflected more aggressive savings targets for established programs. The filed Plan reflected a Settlement Agreement reached by the Joint Utilities, the Office of the Consumer Advocate, the Conservation Law Foundation, The Way Home, Southern New Hampshire Services, and Clean Energy New Hampshire which was also supported the Acadia Center and the Department of Environmental Services. The recently created New Hampshire Department of Energy did not support the Settlement Agreement.

Commission Findings and Orders: At a high level, the Commission cited a need for ratepayer-funded programs to focus on aiding a “transition to market-based energy efficiency.” In doing so, it cited its own orders, as well as relevant statute, such as RSA 374-F:1, which calls for energy utility-sponsored energy efficiency programs to target “cost-effective opportunities that may otherwise be lost due to market barriers.” We note that the prevalence of market barriers and failures in energy efficiency are well studied and documented and further that quantifying the effects of reducing barriers (often called spillover or market transformation – see an example here) is a key focus in designing and evaluating energy efficiency programs. In supporting its denial of the filed Plan, the Commission also included the following in its order:

  • Allocation of Costs and Benefits: The Commission found that the Plan failed to ensure that it would provide benefits to all customers and would not “benefit one customer class to the detriment of another,” noting the substantially higher C&I SBC. While the Joint Utilities charged the same SBC to residential and C&I customers in previous cycles, they proposed to create different SBCs to fund different residential and C&I budgets in the 2021-2023 Plan. We would note that setting separate residential and C&I budgets and SBCs is common practice, and allows budgets to scale based on cost-effective opportunities available by sector.
  • Planned Energy Efficiency as Least Cost Resource: The Commission found that the joint utilities failed to “establish that the suite of EE program offerings is least cost,” citing a lack of direct comparison to supply-side resources. We would note that exhibits accompanying the Plan showed that for all years, fuels, and utilities, estimated energy benefits (excluding other benefits) far exceeded program costs.
  • Cost Effectiveness Tests: The Commission rejected new cost-effectiveness tests included in the Plan, referring to them as a “complicated series of tests” that are “overly dependent upon subjective factors.” On December 30, 2019, the Commission issued an order approving these tests and requiring the Joint Utilities to adopt them for screening energy efficiency investments effective January 1, 2021.
  • Utility Performance Incentives: The Commission found that Performance Incentives, which allow utilities to earn profit in excess of cost recovery by attaining specified objectives, “are no longer just and reasonable and in the public interest in the context of ratepayer funded EE.” Without Performance Incentives, the Joint Utilities have little or no direct financial incentive to deliver energy efficiency.

Implications and Stakeholder Reaction: The Commission’s rebuke of the filed Plan drew swift criticism from the New Hampshire Consumer Advocate, Don Kreis who, according to reporting by Utility Dive, called the Commission’s decision “the most remarkable, outrageous, uncalled for and frankly astonishing thing I have seen any utility regulator do anywhere.” Kreis also stated an intent to challenge the Commission’s Order and potentially seek legislative action. According to reporting by New Hampshire Public Radio, the Order resulted in Eversource and other utilities immediately new enrollments in various energy efficiency programs. Even if any portion of the Order is overturned, this level of regulatory volatility is likely to hamper future energy efficiency efforts, as both utilities and energy efficiency contractors may see investing in the state’s energy efficiency programs as a risk.

 

CENH to challenge PUC energy efficiency decision in superior court

On November 30, 2021, Clean Energy New Hampshire (CENH) issued a press release, stating that they will be filing a lawsuit in conjunction with local communities and contractors in the state Superior Court following the Public Utilities Commission’s (PUC) recent ruling denying the petition of New Hampshire’s gas and electric investor-owned utilities (the Joint Utilities) for approval of their 2021-2023 Statewide Energy Efficiency Plan (as discussed above in this Flash Update).

CENH highlighted a "bipartisan consensus" in the state on the importance of an energy efficiency-focused energy policy, and raised concern that higher projected energy costs for this winter could exacerbate the need for the cost-saving measures that this decision jeopardizes. They criticized the PUC's delay in reaching this decision, adding that it has created an uncertain environment in the energy efficiency industry. The PUC, as CENH pointed out, only has one currently sitting commissioner, and the two nominated commissioners will likely need to recuse themselves from this ruling because they were involved in creating the settlement that was rejected. CENH concluded that a decision on the order is unlikely to be reached before layoffs begin.

CENH, alongside attorneys from BCM Environmental and Land Law with support from Sheehan Phinney Bass & Green, is planning to make a filing by the end of the week asking the Court for a stay of this order until a long-term solution can be reached.

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Vermont

Climate Action Council approves final Climate Action Plan recommending 100% renewable/carbon-free electricity by 2030, 100% ZEV sales by 2035, adoption of Clean Heat Standard, and potential future participation in TCI (or a similar program); DPS releases draft 2022 Comprehensive Energy Plan with many overlapping recommendations

At its meeting on December 1, 2021, the Vermont Climate Council (the Council) voted to adopt the final Climate Action Plan (CAP). As discussed in Digest 83, H.688 - An Act Related to Addressing Climate Change required the Vermont Climate Council to deliver the CAP to the legislature by December 1, 2021. The CAP includes a variety of recommendations to address the climate crisis and is organized according to five areas of action, which are further organized into tiers of pathways, strategies, and actions.

Relatedly, on November 19, 2021, the Vermont Department of Public Service (DPS) released its Draft 2022 Comprehensive Energy Plan (CEP). The draft 2022 CEP provides detail on Vermont’s pathways, strategies, and recommendations towards achieving energy adequacy, reliability, security, and affordability goals articulated in 30 V.S.A. § 202a and builds on renewable energy targets and greenhouse gas (GHG) emission reduction goals set in the 2011 and 2016 CEPs. The CEP also includes the state’s 20-Year Electric Plan and meets the state requirements of Sections 202 and 202b of Title 30 of Vermont Law, and includes information responsive to Act 174 (2016) relevant to regional energy planning.

The draft 2022 CEP is the culmination of a year-long process that reflects close coordination between the DPS and the Vermont Climate Council, which developed the Climate Action Plan (CAP) as required by the 2020 Global Warming Solutions Act (GWSA). The CAP was prepared through a different process and under different statutory requirements, with a focus on GHG emission mitigation, GHG sequestration, and climate change adaptation strategies. The CEP, by contrast, reviews the energy system in ways that are beyond the scope of the GWSA. While the CEP and CAP have areas of overlap, they are distinct planning processes with different objectives. The draft CEP provides new goals for achieving energy and GHG reduction goals in each sector, with a focus on reducing transportation and thermal loads and converting remaining demand to high efficiency electric technologies such as heat pumps and electric vehicles:

Below, we summarize the pathways, strategies, and actions outlined by the Vermont Climate Council in the final CAP relevant to renewable energy markets in New England and highlight areas of overlap with the draft 2022 CEP.

Electricity System Pathways As last summarized in Flash Update 92.4, below are the Climate Action Council’s recommended strategies for reducing emissions from the power sector in the final Climate Action Plan (CAP).

100% Carbon-Free or Renewable Electricity by 2030: The CAP notes that a key mechanism for reducing greenhouse gas (GHG) emissions will be electrification of transportation and building sectors. The Council noted that Vermont's current Renewable Energy Standard (RES) target of 75% by 2032 is sufficient to meet the Global Warming Solutions Act (GWSA) goals for 2025 and 2030, but that the target should be increased to 100% carbon-free or renewable electricity by 2030 to enable deeper carbon reductions. However, rather than calling for the adoption of rules to do so (a power delegated by the GWSA to relevant agencies, as summarized in Digest 83) the Council further recommended that the General Assembly adopt a carbon reduction policy that directs the Public Utilities Commission (PUC) to research the needed design parameters for such a target. This goal was also included in the DPS draft 2022 CEP.

Develop Programs and Incentives to Enable Beneficial Electrification: The Council recommended that the legislature, utilities, private sector, and nonprofits develop programs and ensure direct financial support within 1-2 years for implementation of upgrades to 200-amp electrical services and related building upgrades coordinated with weatherization, efficiency, and incentive programs to encourage adoption of electric vehicle (EV) charging infrastructure, heat pumps, and energy storage. The CAP specified that on-bill repayment was a potential financing source that the Council was considering after completion of pilot projects for weatherization improvements currently underway This goal was also included in the DPS draft 2022 CEP.

Load Management/Grid Optimization: The Council recommended supporting and expanding programs delivered by electric utilities and energy service companies to encourage load management and grid optimization through Integrated Resource Plan (IRP), regulation and rate design proceedings, as well as innovation pilots that fall under existing PUC jurisdiction and oversight. The Council stressed that rapid technological change necessitates similarly rapid program (and regulatory) evolution and a willingness to adapt to and try new things. The Council stressed considering the below strategies:

  • Supporting ongoing direct utility load control programs with the purpose to more cost-effectively manage customer-sited distributed energy resources (DERs) across the grid. The Council stressed using existing tools to effect these programs including utility Integrated Resource Plan (IRP) proceedings, regulation proceedings, rate designs, innovative pilots, and other existing PUC oversight and
  • Encouraging dynamic rate offerings, including those designed to encourage direct load/generation matching, and rate design to support electrification through shared customer savings. The Council stressed that care must be taken to consider who will have the opportunity to benefit from an equity perspective, seeking to avoid shifting rate increases to those who do not share increased load benefits with all customers. The Council further indicated stressed using existing tools to effect these programs including utility Integrated Resource Plan (IRP) proceedings, regulation proceedings, rate designs, innovative pilots, and other existing PUC oversight.

Transportation Pathways

100% Zero Emission Vehicle (ZEV) Sales by 2035: The Council pointed to Vermont's adoption of California's Advanced Clean Cars (ACC) standards in the early 2000s as being pivotal to driving innovation and customer access to cleaner light duty vehicles. As such, the Council recommended that the Agency of Natural Resources (ANR) no later than December 31, 2022 adopt rules to amend Vermont's Low and Zero Emission Vehicle regulations by adopting California's Advanced Clean Cars II (ACC II) regulations, which includes a 100% ZEV requirement for light-duty vehicles, more stringent criteria pollutant emission standards, a vehicle durability standard, and battery state of health standardization and labeling. We note that this is authorized under the GWSA and would not need authorization from the General Assembly. This goal was also included in the DPS draft 2022 CEP.

  • Increase Percent of Heavy-Duty ZEV sales: The Council recommended that ANR immediately adopt California's Advanced Clean Trucks Rule (which sets an increasing percentage of ZEV sales for manufacturers), the Low NOx Omnibus Rule (which includes more stringent NOx emission standards), and the Phase II GHG Rule for Truck Trailers no later than Model Year 2025. The Council further indicated it should leverage federal funding for purchase incentives for medium and heavy duty vehicles. The Council also recommended funding programs to incentivize electric auxiliary systems. This goal was also included in the DPS draft 2022 CEP.

Electric Vehicle Purchase Incentives:' The Council recommended the General Assembly and Agency of Transportation continue current incentive funding for electric vehicles and e-bikes authorized in the 2021 Transportation Bill while analyzing its effectiveness to scale it to anticipated future EV deployment and equity goals in future transportation bills. The Council also recommended the General Assembly and Department of Taxes design and implement vehicle efficiency price adjustments linked to the "purchase and use" tax for new vehicles within a vehicle class, and ensuring the program mitigates impacts to low-income purchases. Our understanding of the implication of this recommendation would be to have higher purchase and use taxes for internal combustion engine (ICE) vehicles and lower taxes for electric vehicles, plug-in hybrid electric vehicles, battery electric vehicles. This goal was also included in the DPS draft 2022 CEP.

Public Investment in Electric Vehicle Supply Equipment (EVSE): The Council recommended the General Assembly pass legislation directing the PUC consider and develop beneficial EV charging rates to incentivize EV adoption through lower fuel costs in coordination with utilities to inform rate design. Setting EV specific charging rates that are lower than normal residential rates and based on shared savings would further incentivize EV adoption. The Council recommended that the legislature continue to fund and support the buildout of DC Fast Charging (DCFC) and Level 2 EVSE, prioritizing multi-family, workplace charging and associated infrastructure. This goal was also included in the DPS draft 2022 CEP.

Join the Transportation and Climate Initiative (TCI) when Regional Market Viability Exists: The Council acknowledged that while the regional implementation timeline of the TCI is uncertain, it remains a critical part of its emission reduction strategy by requiring fuel suppliers to purchase CO2 allowances equal to the amount of fuel they deliver for sale in Vermont. The Council and recommended the state "remain at the table" in finding a path forward on implementation. The Council stated that funds from the federal Infrastructure Investment and Jobs Act (IIJA) (summarized in Flash 90.4) passed into law on November 15 will soon be available for clean transportation investments and that these funds will make the TCI even more critical as a source of state or local matching funds (a 20% match is typically needed). As summarized in Flash Update 92.4, the IIJA allocated $21 million over five years to the state of Vermont, which would suggest that approximately $5.25 million in public funds would be needed for a match over five years. The Council recommended Vermont join the TCI when regional market viability exists and indicated revenue from the TCI could be used to implement other strategies outlined in the CAP Transportation pathway here described. The future of the TCI has grown uncertain as other states including the November 2021 withdrawal of Connecticut, Massachusetts, and Rhode Island last discussed in Flash Update 92.4.

Buildings and Thermal Pathways

  • Implementation of a Clean Heat Standard: The Council recommended that the General Assembly adopt consistent with the recommendations of the Clean Heat Standard Working Group. We note that this is authorized under the GWSA and would not need authorization from the General Assembly. This goal was also included in the DPS draft 2022 CEP.
  • Electric Water Heater Demand Response: The Council recommended that the DPS no later than July 2022 initiate discussions with neighboring states to require electric water heaters for sale have a modular demand response communications port. This would complement a Clean Heat Standard and enable transition of fossil-fuel water heating to energy efficient water heaters whose heating can be timed to off-peak times of electricity use.
  • Residential Building energy codes: The Council recommended the Public Service Department (PSD) update statewide residential building energy codes by the next scheduled update of September 2023 and then every three years thereafter, as well as a Zero Energy Ready building energy code no later than 2030.

Non-Energy Emission Pathways:

  • Explore efficiencies in Semiconductor Manufacturing: The Council highlighted an ongoing petition by GlobalFoundries with the PUC to operate as a self-managed utility (SMU), summarized elsewhere in this Flash Update. The Council recommended that, depending on the PUC proceeding outcome, that the ANR and DPS work with GlobalFoundries to implement technologies for the reduction of emissions and potential use chemical substitutions in its semiconductor manufacturing process to be consistent with GWSA GHG emission reduction requirements.

To summarize, the Climate Action Council recommended the General Assembly take the below actions, and we expect all of these to be taken up, many of them likely in the next legislative session. • Increase the current 75% RES to a 100% carbon-free or renewable electricity standard by 2030; • Provide funding for beneficial electrification incentive programs to encourage adoption of EV charging infrastructure, heat pumps, and energy storage; • Continue current incentive funding for electric vehicles and e-bikes authorized in the 2021 Transportation Bill while analyzing its effectiveness to scale it to anticipated future EV deployment and equity goals in future transportation bills; • Design and implement vehicle efficiency price adjustments linked to the "purchase and use" tax for new vehicles within a vehicle class to incentivize the purchase of hybrid and electric vehicles; • Continue to fund and support the buildout of DC Fast Charging (DCFC) and Level 2 EVSE, prioritizing multi-family, workplace charging and associated infrastructure; • Direct the PUC to consider and develop beneficial EV charging rates to incentivize EV adoption through lower fuel costs in coordination with utilities to inform rate design; • "Remain at the table" in finding a path forward on implementation of the TCI when market viability exists; • Leverage federal funds allocated to Vermont from the IIJA for clean transportation investments, including for incentives for the purchase of light-, medium-, and heavy-duty vehicles. • Authorize the PUC by May 2022 to administer a Clean Heat Standard

Below, we summarize the DPS recommendations in the draft 2022 Comprehensive Energy Plan. Electric Sector: The Plan would require the state to meet 100% of energy needs from carbon-free sources by 2032, 75% of which must come from renewable energy. The report indicated that such a requirement must consider and include transparent information about the costs and benefits of different design considerations including the addition of new resources, time and locational considerations, and resource size and diversity.

Transportation Sector: meet 10% of sector energy needs from renewable energy by 2025 and 45% by 2040, and ensure that 100% light-duty vehicle sales in Vermont are zero-emission by 2035. The 2022 draft CEP sets further transportation goals strategies and goals:

  • Accelerate battery electric vehicle market share through incentives such as new and used vehicle incentive programs and continuation of programs such as MilesageSmart, Replace your Ride, etc.
  • Facilitate increased EV market share through supporting infrastructure and policy through various mechanisms:
    • Support for both Direct Current Fast Charging (DCFC) and Level 2 charging until a sufficient free-market charging network can stand on its own.
    • Continued emulation of California’s Advanced Clean Car program’
    • Establish a rulemaking process that would adopt California’s Clean Cars II regulations which will require 100% of light-duty vehicles available for sale in Vermont to be zero-emission vehicles
  • Manage electric grid impacts driven by electrification through efficient rate design, including appropriate addressing of demand charges.
  • Increase vehicle fuel efficiency by supporting increasingly stringent federal standards, and continue to explore and improve the average fuel economy of the state’s fleet.
  • Increase targeted use of low-carbon fuels and biofuels.
  • Enhance integration of land-use planning into transportation decision making frameworks.
  • Provide safe, reliable, and equitable public and active transportation options.

Thermal Sector: meet 30% of sector energy needs from renewable energy by 2025, 45% by 2032, and 70% by 2042. The 2022 draft CEP sets further thermal sector goals strategies and goals:

  • Set a new target of weatherizing 120,000 households by 2030, relative to a 2008 baseline.
  • Set a new target to achieve net-zero ready construction for all newly constructed buildings by 2030 through building efficiency standards.
  • Calls for formal consideration of a Clean Heat Standard which, similar to a RES, would seek to create a technology- and fuel-neutral performance-based obligation on heating fuel providers (either wholesale or retail providers) to procure an increasing percentage of their retail sales from low-carbon thermal solutions at a pace set by the legislature.
  • Continue to encourage cleaner technologies and fuels through the promotion of electrification of thermal loads, development of the advanced wood heat market, and support for district heat, biofuels, and alternatives to natural gas such as renewable natural gas, syngas, and hydrogen.

DPS is accepting comment on the draft CEP plan until December 20. Comments may be submitted electronically to PSD.ComprehensiveEnergyPlan@vermont.gov.

 

Parties file legal briefs in case regarding GlobalFoundries petition seeking to become independent energy utility, exemption from GWSA

On November 22, 2021, several stakeholders filed briefs with the Vermont Public Utility Commission (PUC) in Case 21-1109-PET regarding a March 17 Petition by GlobalFoundries requesting a Certificate of Public Good (CPG) (pursuant to Section 231 of Title 30 (30 V.S.A. § 231)) for its Essex semiconductor manufacturing facility to operate as a Self-Managed Utility (SMU). As discussed in Digest 91, under the proposed SMU arrangement, instead of purchasing electricity from Green Mountain Power (GMP), GlobalFoundries' Essex semiconductor facility would supply only its own load through the region's wholesale electricity market beginning on October 1, 2022. If approved, GlobalFoundries would be the first SMU in the state. At issue is whether and how GlobalFoundries would be subject to Renewable Energy Standard (RES) and greenhouse gas (GHG) reduction targets if its petition is approved.

In its Petition, GlobalFoundries stated that it would not serve customers as a traditional utility, and that it would not be a "retail electricity provider" within the meaning of 30 V.S.A. § 8002(23). As such, GlobalFoundries requested that so long as it does not sell electricity to retail customers that the PUC exercise its discretion to apply de minimis regulation to GlobalFoundries as an SMU. In effect, this means that while the PUC would still have jurisdiction over GlobalFoundries under Title 30, it would have discretion to exercise its regulatory authority over GlobalFoundries only to the extent it deems necessary. Our understanding is that GlobalFoundries would seek exemption from Renewable Energy Standard (RES), self-managed energy efficiency program (SMEEP), and GWSA requirements and instead submit a Memorandum of Understanding (MOU) setting aspirational (and nonbinding) GHG emission reduction targets. On September 21, GlobalFoundries filed a Letter of Intent (LOI) that it executed with the Vermont Department of Public Service (DPS) and the Agency of Natural Resources (ANR) formalizing their intent to negotiate and execute a more definitive MOU.

As discussed in Flash Update 92.4, on November 12, 2021, GlobalFoundries sent a Letter notifying the PUC that it (along with DPS and ANR) were continuing to collaborate on developing an MOU and requested the PUC's permission to submit a proposal at a later date. On November 19, the PUC issued an Order amending the schedule to remove the deadlines for submission of an MOU but preserving the previously ordered deadlines for consideration of the two below legal issues on which the PUC seeks briefing:

  • Does the PUC have jurisdiction to grant GlobalFoundries' request to operate as an SMU under de minimis regulation?
  • Are GlobalFoundries' tenant customers such that if GlobalFoundries' operations, if it continued to provide electricity to those tenants, would constitute a public service business?

In its Reply Brief, GlobalFoundries argued that PUC does have jurisdiction to regulate it under de minimis regulation, pointing out that the PUC has routinely found jurisdiction over, issued a certificate of public good pursuant to Section 231, and exercised de minimis regulation of companies whose operation in Vermont fall within the PUC’s jurisdiction but will not involve sales to retail customers. GlobalFoundries further stated that while it would not be subject to the RES if its petition is approved, it has committed to greater GHG reductions than would be achieved with the RES (under current law) alone. We note, however, that as discussed elsewhere in this Flash Update, that the Climate Action Council has recommended adoption of a 100% renewable or carbon-free standard by 2030, which would, if enacted, eclipse the 75% by 2032 renewable target in current law.

In its Reply Briefs, the Conservation Law Foundation (CLF) and AllEarth Renewables contended that GlobalFoundries and GMP did not establish a lawful basis for regulation as an SMU under which the PUC can exercise jurisdiction. They explain that under Section 231 the PUC may issue a certificate of public good only to “a business over which the Public Utility Commission has jurisdiction under the provisions of [Chapter 5]” of Title 30, which includes public service companies but not SMUs. CLF further argued the Petitioners did not identify a lawful basis for incidental jurisdiction for the PUC to create and regulate SMUs. Finally, CLF explained that GlobalFoundries’ proposal to be regulated under de minimis regulation would allow it to undermine state GHG goals and the states’ decision to reject retail choice when it comes to electricity procurement by individual customers.

In its Reply Brief, DPS contended that the PUC retaining jurisdiction over this proceeding “ensures that GlobalFoundries’ immediate proposal to operate as a self-supplied, regulated business remains firmly fixed to the public good standard and subject to the Commission’s broader gatekeeper role in controlling which entities have authority to supply electricity for distribution and use within Vermont. It will also ensure that any future, similar requests from any other entities receive the same degree of regulatory scrutiny.” DPS further argued that the pressing jurisdictional issue is whether the PUC has the authority to issue a certificate of public good to a proposed public service business that doesn’t intend to serve retail customers. The DPS noted that having retail customers is not necessarily indicative of whether the PUC can issue a certificate of public good or retain jurisdiction over a regulated utility, pointing to several telecommunications providers that have active certificates of public good but no retail customers in Vermont.

 

Vermont Supreme Court decision would no longer require Act 250 permits for projects that disturb less than one acre of land in towns without zoning; decision opposed by Natural Resources Board and Council, case to be reargued

A September 2021 unanimous Decision by the Vermont Supreme Court could, if upheld upon rehearing, exempt development in towns without zoning (referred to as one-acre towns) from the need to acquire an Act 250 permit if the disturbed land is under one acre. The clause of Act 250 at issue in the case is the provision that, in one-acre towns, developers need a permit for “improvements for commercial or industrial purposes on more than one acre of land.” In this case the court found that "'the construction of improvements for commercial or industrial purposes on more than one acre of land’ refers to the land actually used for the construction of improvements, rather than the size of the parcel on which the construction of improvements will be located.” Previously, Act 250 has been interpreted to require an Act 250 permit in one-acre towns when the parcel containing an "improvement" is more than one acre, but this court case would mean that any project that disturbs less than one acre of land, regardless of parcel size, would not need an Act 250 permit. The court decision would not relieve energy projects of the need for a Certificate of Public Good, only the Act 250 permit requirements. We note that as a rule of thumb, one acre of land could contain around 133 kWAC of solar capacity.

The Vermont Supreme Court has opened the case for reargument, meaning the finding may not stand. According to VTDigger, the parties opposing the original Decision include two of the original defendants, a neighbor to a proposed stone quarry that sued over the need for an Act 250 permit in the first place, the Natural Resources Board that enforces Act 250, and are joined in their opposition to the Decision by the Vermont Natural Resources Council and seven former Environmental Board and Natural Resources Board chairs. The opposing parties argue that the Decision, if upheld, would allow any form of commercial development in towns without zoning so long as the development has a footprint under one acre, which is contrary to the legislative intent and precedent around Act 250.

Rehearing briefs have been filed with the Supreme Court and we anticipate that reargument is the likely next phase of the case.

 

WEG files Petition to build 4.99 MW battery energy storage system in South Hero

On November 23, 2021, in Case 21-5049-PET, WEG Electric Corp. (WEG) filed a Petition for Certificates of Public Good with the Vermont Public Utility Commission (PUC) to install, own, and operate a 4.99 MW/14.94 MWh battery energy storage system adjacent to the existing Vermont Electric Cooperative (VEC) substation on Eagle Camp Road in South Hero, VT. The project would be contracted to VEC through an energy storage service agreement (ESSA) that intends for the project to be operated in such a way as to reduce VEC’s regional network service costs and capacity load obligations owed to ISO New England. The ESSA would allow WEG to participate and operate in the ISO-NE markets at times when not providing contracted services to VEC.

 

PUC issues order approving utility 2020 RES filings

On November 23, 2021, the Public Utility Commission (PUC) issued an Order approving the 2020 Renewable Energy Standard (RES) compliance filings, which are summarized in Flash Update 91.5. Electric distribution utilities are required by Rule 4.419 to file RES compliance reports by August 31 of each year. As discussed in Flash Update 91.5, on September 30 the Department of Public Service (DPS) reviewed each electric distribution utility's compliance filing in Docket 21-1045-INV and recommended the PUC find all distribution utilities in compliance with the RES for 2020.

The purpose of DPS’ comments was to make recommendations to the PUC on each utility's compliance and to highlight any areas of concern. The PUC's order closed the docket.

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ISO New England

FERC issues Order modifying Mystic ROE Order by reducing base ROE to 9.19%: ENECOS and NESCOE challenge Mystic's informational filing related to its cost-of-service agreement

As last discussed in Flash Update 91.3, in December 2018, in Docket No. Docket ER18-1639, FERC issued an Order (the December 2018 Order) accepting the cost-of-service agreement between ISO-NE and Constellation Mystic Power, LLC (Constellation) to compensate Constellation for continued operation of its Mystic Generating Station Units 8 and 9, and allowing for payments to the Distrigas liquefied natural gas (LNG) facility. Constellation Mystic Power is a plant-specific subsidiary of Exelon. As discussed in Digest 68, in May 2018, ISO-NE filed a Petition for Waiver of Tariff Provisions to allow ISO-NE to retain Mystic Units 8 and 9 for the 2022/23 and 2023/24 winter periods to maintain fuel security, rather than allowing them to retire, thus prompting the need for the cost-of-service agreement.

On July 15, 2021, FERC issued an Order (the July Order) which found, among other things, that Mystic is of average risk and that the just and reasonable return on equity (ROE) for Mystic is 9.33%. On August 13, Mystic filed a request for rehearing of the July Order, arguing that:

  • FERC's determination that Mystic will be of average risk is not correct;
  • The precedent that FERC relied upon in drafting its Order was nonsensical; and
  • FERC erred in excluding Avangrid, Sempra, and Dominion from its proxy group that was used to examine "similar" facilities.

Additional rehearing requests were submitted by:

On November 18, 2021, FERC issued an Order Addressing Arguments Raised on Rehearing (Order on Rehearing), and setting aside the July Order, in part. In the Order on Rehearing, FERC agreed with an aspect of the Request for Rehearing submitted by the Connecticut Parties, which contended that FERC failed to apply the natural break analysis to the results of the Discounted Cash Flow model (DCF) and should have excluded Otter Tail Corp. (Otter Tail), which, at 11.07%, had the highest DCF result of the proxy facilities to which FERC was comparing Mystic (natural break analysis, as defined by FERC, "gives the Commission the flexibility to determine whether a given proxy group company is truly an outlier, or whether it contains useful information, in light of the particular array of ROEs presented by the potential proxy group companies"). When Otter Tail was excluded from comparison analysis, the average of the medians of DCF, the Capital Asset Pricing Model (CAPM), and risk premiums was 9.19%. Therefore, FERC directed Mystic to submit a compliance filing within 30 days revising the Mystic Agreement to reflect a 9.19% base ROE.

Unrelated to the proceeding pertaining to Mystic's ROE, on September 15, 2021, Mystic submitted the first of five Annual Informational Filings, that are designed to predict, track and ultimately true up Mystic’s costs for the two-year Term of the Mystic Agreement (discussed above). The First Filing provided support for capital projects that Mystic proposes to put in service between June 1, 2022 and December 31, 2022 and collect through the Mystic Agreement as an expense. On November 17, the Eastern New England Consumer-Owned Systems (ENECOS) and the New England States Committee on Electricity (NESCOE) submitted formal challenges to Mystic's September 15 informational filing. The ENECOS and NESCOE claimed that Mystic’s September 15 Informational Filing failed to support Mystic’s claimed Annual Fixed Revenue Requirement, Maximum Monthly Fixed Cost Payment, and Fixed Operations & Maintenance/Return on Investment component of the Monthly Fuel Cost Charge for the period from June 1, 2022, through December 31, 2022. On November 17, Mystic submitted a response to the challenges, but the document has been entirely redacted.

 

FERC releases NOI seeking comment on reactive power capability compensation, initial comments due January 31, 2022

On November 18, 2021, FERC issued a Notice of Inquiry (NOI) opening Docket RM22-2 and seeking comment on reactive power capability compensation and market design. In 1999, when FERC began regulating reactive power capability compensation under Order 2002, most reactive power filings were made by synchronous resources owned by public utilities. However, today the majority of filings are made by owners of non-synchronous resources such as solar, wind, and battery storage, the services of which have created voltage support and grid balancing challenges because these non-synchronous resources produce reactive power differently and in different quantities than traditional generators did. This docket seeks comment on alternative approaches to compensating the reactive power different resources provide.

Real vs. Reactive Power: Most electricity is generated, transported, and consumed in alternating current (AC) networks, elements of which supply and consume two kinds of power: real and reactive. Real power—measured in kW—accomplishes work in the real domain, such as running motors and lighting lamps. Reactive power—measured in kVAR—s supports the voltage that must be controlled for system reliability. Resources must either supply or consume reactive power to maintain the voltage levels needed to supply real power from generation to load, and thus the presence of reactive power is necessary to move real power. Inadequate reactive power lowers voltage and, as voltage drops, current must increase to maintain the power supplied, causing the line to consume more reactive power and the voltage to drop further, eventually leading to reliability problems. Having too much reactive power, however, is detrimental to system reliability and efficiency because most electric meters only measure real power. Thus, having high quantities of reactive power can increase the load on the grid without grid operators being aware of the high load, which can also jeopardize system reliability.

FERC History of Regulating and Compensating Reactive Power: There are two approaches for supplying reactive power to control voltage: 1) installing facilities as part of the transmission system, and 2) using generation resources. FERC concluded in Order 888 issued in April 1996 that the costs of the former would be recovered as part of basic transmission service and wouldn’t be an ancillary service. FERC concluded that the costs of the latter would be considered a separate ancillary service that must be unbundled from basic transmission service. In Opinion 440, FERC approved a method developed by the American Electric Power Services Company (AEP) for allocating the cost of generator equipment as well as O&M costs between real and reactive power capability. AEP developed an allocation factor to sort annual revenue requirements of four key components of the generation plant between real and reactive power production, listed below. Reactive power capability is measured in megavolt amperes reactive capability (MVAR). FERC indicated that all resources that have actual cost data and support should use AEP’s method pursuant to individual cost-based revenue requirements.

  • Generator and its exciter;
  • Generator step-up transformer;
  • Accessory electric equipment that supports operation of the generator-exciter; and
  • Remaining total production investment required to provide real power and operate the exciter.

In Order 2003, FERC adopted standard large generator interconnection procedures (the Large Generator Interconnection Agreement (LGIA)), which required payment by the transmission provider for reactive power to an interconnection customer only when transmission providers request that the interconnection customer operate its generating facility outside the established power range of 0.95 lagging to 0.95 leading (wind was exempt from this requirement). Order 661 issued in December 2005 established the technical requirements for interconnecting large wind resources and maintained the exemption from providing reactive power, except where the transmission provider showed that reactive power capability was required to ensure safety or reliability. In Order 2006 issued in May 2005, FERC adopted identical power factor and compensation requirements for small generating facilities (less than or equal to 20 MW) but exempted small wind generators from the reactive power requirement. In Order 827 issued in June 2016, FERC eliminated the exemption for wind resources from the requirement to provide reactive power. Order 827 also clarified that the amount of reactive power required from non-synchronous resources should be proportionate to the actual (real) power output. FERC further stated that any non-synchronous resource seeking reactive power compensation would need to propose a method for calculating the compensation as part of its filing.

Existing Approaches to Reactive Power Capability Compensation: In RTOs where transmission providers compensate for reactive power capability, the compensation is either:

  • Based on individual reactive power revenue requirements determined in cases for individual resources (or fleets of resources) established pursuant to a cost-based method (e.g. the AEP method) using a resources MVAR capability (PJM and MISO generally use AEP method); or
  • Paid on a flat per-MVAR region-wide bases based on testing for the maximum MVAR capability of the resource (ISO-NE and NYISO typically use this approach).

In the NOI, FERC is seeking comment on a variety of issues that have arisen regarding reactive power capability compensation and market design relevant to New England, specifically:

Questions about AEP method:

  • Does compensating resources based on cost of investment in reactive power capability continue to be appropriate? If so, does the AEP methodology accurately reflect a resources investment cost? Does this depend on the type of resource?
  • What is the appropriate time period for compensation from a rate developed under AEP methodology? Should payments be limited based on the useful lives of the plants at issue?
  • The power factor design criteria in FERC’s pro forma LGIA specifies that the generating facility should be designed to maintain composite power delivery at ‘’’continuous’’’ rated power output, either at the point of interconnection for synchronous resources, or at the high side of the generator substation for non-synchronous resources. Over what minimum amount of time should a resource be required to maintain its maximum real power output while operating across its claimed reactive power factor range? How does this vary by resource type?
  • To the extent that reactive power capability requirements are not addressed in a resource’s interconnection agreement (IA) and a resource seeks compensation for its reactive power capability, how should FERC address this? Should FERC require the resource and transmission provider propose updates to the IA?
  • Reactive power filings set for hearing and settlement judge procedures often don’t have active intervening parties other than the market monitor and RTO/ISO – why do other parties not participate more in these proceedings?
  • Degradation:
    • How does a resource’s reactive power capability degrade over time? Does it follow a predictable pattern? Does this vary by generation type? Should resources receiving reactive power capability compensation undergo periodic testing to demonstrate their compensation remains accurate?
    • Should the AEP methodology be modified to account for degradation over the life of the resource and, if yes, how so?
    • Over what time period does the NERC MOD-25-2 Reliability Standard accurately represent a resource’s capability to provide reactive power?
    • Are there maintenance activities needed to maintain reactive power capability that don’t also contribute to real power capability?
  • Non-Synchronous Resources (e.g., wind, solar, batteries):
    • Is the existing AEP methodology appropriate to allocate the cost associated with reactive power revenue requirements of non-synchronous resources? What changes could be made if not?
    • Please identify what non-synchronous resource equipment used in the AEP methodology corresponds to the synchronous resource equipment used in the AEP methodology and how that equipment is related to the production of reactive power and real power.
    • Which, if any, of the four groups of costs under the AEP methodology do costs associated with the collection system of non-synchronous resources fall into, and why? Should those costs related to the collection system be recovered and, if so, why?
    • Please explain whether it I necessary for a Type 3 or 4 wind turbine or solar PV facility to produce real power at a particular time in order for that resource to provide reactive power capability at that time.
    • Should the AEP methodology be altered to account for the intermittent availability of some non-synchronous resources?
    • Solar resources can be designed with power factors much lower than those of synchronous resources, which implies a much higher reactive power capability and results in higher revenue requirements under current application of the AEP methodology. Should AEP method be altered to account for this difference?
  • Evidentiary Support:
    • What options are available to collect independently verifiable cost information from Market-Based Rate (MBR) sellers that have received a waiver of accounting and FERC Form No. 1 requirements? How should MBR sellers that receive reactive power capability compensation track their equipment costs and support their proposed reactive power revenue requirements?

Questions about Alternative Methodologies:

  • Should alternative methods to the AEP method be considered for calculation of reactive power capability revenue requirements? If so, what alternate method could be used that would accurately capture the cost of providing reactive power capability, and would this vary by resource type including non-synchronous resources?
  • Should a flat rate approach to reactive power compensation differ by resource type?
  • Under a flat rate approach, how should the rate initially be set and how would it be adjusted over time (e.g. for inflation)? How often should a resource’s reactive power capability be tested?
  • Under a replacement cost approach, what alternative technology should be used to establish the rate and how should that alternative technology be determined?
  • Would a change to a flat rate or replacement rate approach require resources to change any of their accounting, recordkeeping, or other administrative processes? Would such changes impact capital investment decisions?

Questions about Distribution-Connected Resources:

  • For a distributed-connected resource, is reactive power dispatchable by direction of the transmission provider? Does this depend on whether the resource has a FERC-jurisdictional IA with the transmission system owner or operator? Does this depend on whether the resource is synchronous or non-synchronous?
  • If reactive power produced by a distribution-connected resource can’t be dispatched by the transmission system operator to provide voltage support, should it be compensated through transmission rates for its reactive power capability?
  • If distribution-connected resources are dispatchable for reactive power by the transmission provider, to what extent can the resource provide reactive power capability service to the transmission system? Are there physical characteristics (e.g., resource characteristics and location, system topology, etc.) or other indicators that could be analyzed to accurately determine whether a distribution-connected resource can provide such service?

Initial comments are due January 31, 2022 and reply comments are due February 28, 2022.

 

ISO-NE publishes FCM resource terminations data

On November 23, 2021, ISO-NE published a public workbook with information regarding Capacity Supply Obligation (CSO) terminations that have occurred in the Forward Capacity Market (FCM) for non-commercial new capacity resources as a result of either participant's request to withdraw their capacity or the termination of their capacity by ISO-NE from Critical Path Schedule (CPS) monitoring. The workbook contains all resources that have had all or part of their CSO terminated and information regarding their terminations. Pursuant to Tariff Section III.13.3.4A, ISO-NE has the right to terminate resource non-commercial CSOs for any future Capacity Commitment Period (CCP) for resources that are on CPS Monitoring, and fail to meet critical milestones. The termination of CSOs may be due to:

  • Withdrawal from CPS monitoring;
  • Termination from CPS monitoring by ISO-NE;
  • Participant suspension under Billing or Financial Assurance Policy;
  • Withdrawal from the Interconnection Queue.

We note that the list of full CSO terminations includes several standalone storage resources located in Massachusetts, totaling more than 400 MW, which would have qualified for the Massachusetts Clean Peak Energy Standard (CPS). The withdrawal of these resources from the FCM may indicate that, even with the introduction of CPS, the economic viability of transmission-connected, standalone storage is challenging. If, as these actions would suggest, these resources are not constructed or are delayed, this will have a substantial impact on the overall supply in the CPS market.

 

ISO-NE presents revisions to Transmission 2050 study at PAC Meeting

On November 17, 2021, ISO-NE presented to the Planning Advisory Committee (PAC) revisions to the preliminary assumptions and methodology underpinning the 2050 Transmission Study Scope of Work. The study is the first effort undertaken in the longer-term transmission planning process that ISO-NE intends to incorporate into Attachment K of its Open Access Transmission Tariff (OATT) and is responsive to recommendations offered by the New England States in their Vision Statement. The study will ultimately analyze long-term transmission scenarios through 2050. Future load and resource assumptions will be based on the "All Options" pathway in the December 2020 Massachusetts Energy Pathways to Deep Decarbonization Report, which is the basis for Scenario 3 in the Future Grid Reliability Study (FGRS) Phase I. As summarized in Flash Update 91.3, ISO-NE accepted the FGRS as the 2021 Economic Study under Attachment K. The FGRS is distinct from the Transmission 2050 study in that it is an economic study, not a transmission study, and will focus on examining reliability and market issues that may arise in New England in the coming years given state decarbonization policies. ISO-NE presented clarifications and updates to the FGRS Phase 1 study along with an assumptions workbook at the September 22 NEPOOL Joint Markets (MC) and Reliability (RC) Committee meetings where it laid out assumptions including those underpinning Scenario 3, which formed the basis for many of the 2050 Transmission study assumptions. Below, we summarize the 2050 Transmission study:

Study Objectives: Determine the following for the years 2035, 2040, and 2050:

  • Transmission needs to serve load while satisfying NERC, NPC, and ISO-NE reliability criteria; and
  • Transmission upgrade roadmaps to satisfy those needs, considering both constructability and cost.

Snapshot Identification: The study will review a total of 12 cases (four cases each for 2035, 2040, and 2050) based on the highest coincident loads in New England, from reviewing hourly load data from the "All Options" pathway:

  • New England Winter Peak
  • New England Summer Daytime Peak
  • New England Summer Evening Peak
  • Northern New England Summer Evening Peak Conditions (this single additional scenario was added because the summer peak load in the northern New England states was non-coincident with the New England summer peak load).

Assumptions:

  • Transmission Topology: Transmission topology from Year 10 of the Summer Peak Load Needs Assessment case (2031 NA case) in the 2021 Transmission Planning Base Case Library will be used, in addition to two additional transmission upgrades based on the First Cape Cod and Final Second Maine resource integration studies. The 2031 NA case features:
    • All in-service, under construction, planned and proposed reliability projects on the ISO-NE project list and ISO Asset Condition list from March 2021, and known Local System Plan projects from October 2020;
    • Upper Maine and New Hampshire preferred solutions;
    • A1 and B2 reconductoring project
  • Load: Projected peak "All Options" pathway load is significantly higher than the 2021 CELT forecasted load for 2030, with the difference largely due to electric vehicle (EV) charging and heating. The 2050 Transmission Study will use 2 categories of load: EV load and non-EV load.
    • To restrict the scope of the study, all loads will be modeled at substations operated at 69 kV and above.
    • Load will NOT be taken from the 2031 NA case and instead new loads will be placed at each load-serving transmission substation for each Snapshot using the percentage of each state's load by bus from 2019 historical data, and total state loads from the "All Options" pathway.

  • Resource Modeling:
    • Nuclear and biomass will be assumed at 100% available for all 4 snapshots and all 3 study years.
    • Hydro generator dispatch in the summer peak snapshots will be consistent with ongoing practice in Needs Assessments. Winter peak snapshots will be dispatched based on historical outputs in 2019 under winter peak load conditions.
    • Natural Gas will be assumed at 100% availability for all 4 snapshots and all 3 study years.
    • Rooftop solar is modeled as negative load for all rooftop solar PV and as generators for all ground-mounted solar PV (GM PV). This study adopted the approach in the Transmission Planning for the Clean Energy Transition (TPCET) Pilot study (which ISO-NE initiated to update the assumptions used in transmission planning studies under a 10-year timeframe and is still ongoing), which mapped rooftop PV to cities and towns in New England by substation. GM PV is modeled in this study based on existing and planned resources in the 2031 NA Case, with the remaining GM PV distributed evenly by state across transmission substations in New England in cities and towns with a population density less than 3,000 per square mile. Below is a summary of the assumed PV availability, developed in the TPCET Pilot study by snapshot.

    • Onshore wind generation is modeled from the "All Options" pathway and 2031 NA case. Below is a summary of the assumed onshore wind availability, developed in the TPCET Pilot study by snapshot.

    • Offshore wind (OSW) is modeled from the "All Options" pathway and 2031 NA case. New additional offshore wind units will be interconnected to 345 kV stations or major 115 kV stations. The maximum size for a single OSW plant is assumed to be 1,200 MW, with no more than 2,400 MW of OSW being interconnected to the same bus. Below is a summary of the assumed offshore wind availability, developed in the TPCET Pilot study by snapshot.

    • Energy Storage is modeled from the "All Options" pathway and 2031 NA case. All planned battery energy storage systems in the 2031 NA case were assumed to have 2 hours of storage. For this study, planned future storage not modeled in the 2031 NA case will be modeled as 4 hours of storage, consistent with the assumption for new battery storage in the FGRS Scenario 3, and will be located at major 345 kV stations or at generator stations with expected retirements. The availability of pumped storage hydro will be similar to that of batteries. Below is a summary of the assumed energy storage availability, developed in the TPCET Pilot study by snapshot.

Resource Adequacy: To perform a transmission planning study there must be sufficient capacity resources, which is not the case in several of the snapshots. To address this resource insufficiency, the 2050 Transmission study added proxy generators at offshore wind locations in proportion to the size of the wind farm for these snapshots. For the snapshots where there was sufficient resource adequacy, excess resources were assumed to be curtailed, in order, from imports on the NY-NE AC ties, natural gas combustion turbines (CT), and natural gas combined cycle combustion turbines (CCGT).

The 2050 Transmission study will perform the initial analysis and identify thermal violations, after which it will evaluate transmission upgrades and estimate the associated costs 

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Regional and National Developments

Vineyard Wind breaks ground on Vineyard Wind I project

On November 18, 2021, Vineyard Wind (a joint venture between Avangrid Renewables and Copenhagen Infrastructure Partners) broke ground on the Vineyard Wind I offshore wind project. Initial construction steps will include laying the two transmission cables that will connect the project to the mainland at Barnstable, MA, according to the Department of the Interior’s press release. As discussed in Digest 88, the Bureau of Ocean Energy Management issued its Record of Decision approving the Construction and Operations Plan for the 800 MW Vineyard Wind I project earlier this year, and the project is anticipated to begin delivering power to Massachusetts in 2023. Vineyard Wind’s press release about the groundbreaking notes that the project will consist of 62, 13 MW General Electric Haliade-X wind turbines. Vineyard Wind was selected to enter into power purchase agreements with Massachusetts electric distribution companies as part of Massachusetts’ Section 83C solicitation in 2018.

 

Solar Trade Updates: Federal trade court strikes down tariff on bifacial solar and reinstates exclusion; International Trade Commission recommends that Biden Administration extend of solar panel tariffs

On November 16, 2021, the U.S. Court of International Trade (CIT) issued a ruling, reinstating the bifacial solar module tariff exclusion to the Section 201 global safeguard tariffs on solar cells and modules. The CIT ruling also reduced the Section 201 tariff rate back to 15% after President Trump raised it to 18% in 2020 (discussed below). While the ruling was criticized by some domestic solar manufacturers, the Solar Energy Industries Association’s (SEIA)president and CEO commended the ruling as “clearly the right decision.” On November 24, the U.S. International Trade Commission (ITC) recommended an extension to the Section 201 solar cells and modules tariffs, leaving the final decision to President Biden. The ITC argued that the U.S. solar panel manufacturing industry continues to need protection while it continues to make positive adjustments to import competition. Bifacial panels will still be excluded from the tariff if the extension is granted. As discussed in Digest 85, on October 10, 2020, President Trump issued a proclamation directing the U.S. Trade Representative (USTR) to reinstate Section 201 tariffs on bifacial panels in a continuation of the Administration's attempt to withdraw an exclusion for this type of panel. As discussed in Digest 86, on November 19, 2020, Judge Gary Katzman of the U.S. CIT issued an Order, lifting a Temporary Restraining Order on President Trump's presidential proclamation, and allowing the USTR to remove the tariff exemption for bifacial solar panels. This led to a lawsuit from three solar developers and SEIA, who argued that Trump’s proclamation violated trade laws. In March 2021, the Biden administration asked a federal judge to dismiss this challenge to Trump’s tariffs, arguing that Trump “acted lawfully and fully within his authority” in reinstating tariffs on bifacial solar. The ITC will be forwarding its full report on the issue to President Biden by December 8, 2021.

 

Illinois regulators begin implementation of CEJA provisions, including provisions related to energy storage, electric vehicles, and REC procurement

Illinois regulators have taken the first steps towards implementation of the recently enacted omnibus energy legislation known as The Climate and Equitable Jobs Act (CEJA). The Act contains a wide range of provisions, including wind and solar development, public utility company ratemaking and operations, and emissions and efficiency standards at coal- and gas-fired power plants. Per a summary distributed by law firm Quarles & Brady Initial actions in response to CEJA’s provisions include the following:

  • The Illinois Commerce Commission (ICC) has:
    • Initiated a competitive selection process for experts to support the development of a Renewable Energy Access Plan, which will determine zones throughout the state that could support renewable energy facilities and propose transmission solutions;
    • Commenced formal workshops to identify and measure energy storage costs, benefits and barriers;
    • Invited stakeholders to participate in an Interconnection Working Group;
    • Created an application for customers with high electricity usage to opt-out of utility energy efficiency programs and develop their own plans;
    • Hired a facilitator for “Beneficial Electrification” workshops (next one is set for December 15, 2021) that will focus on electric vehicle (EV) related topics; and
    • Initiated a competitive selection process for a facilitator to lead Integrated Grid Plan workshops.
  • The Illinois Power Agency (IPA) has:
    • Issued draft revisions to the standard form REC contract for the Adjustable Block Program (ABP) for community solar and small and large distributed generation (DG) solar projects, in response to the CEJA effectively doubling the state’s investment in renewables through an increase in REC procurement requirements; and
    • Issued a request for stakeholder feedback on its Long-Term Renewable Resources Procurement Plan, which covers “utility-scale projects, the ABP, and the Illinois Solar for All Program applicable to low-income projects.”

CEJA’s overall objective is to put Illinois on track to reach 100% carbon-free energy by 2050.

 

DOE issues RFI on energy sector supply chain

On November 29, 2021, the U.S. Department of Energy released a Request for Information on supply chains in the energy sector. The RFI is issued in accordance with Executive Order 14017, which required the Secretary of Energy to submit to the President a report on supply chains for the energy sector industrial base. The RFI seeks responses to numerous questions regarding supply chain development across the following topics:

  • Crosscutting topics relating to the energy sector industrial base
  • Solar PV Technology
  • Wind Energy Technology
  • Energy Storage Technology
  • Electric Grid - Transformers and HVDC
  • Hydropower and Pumped Storage Technology
  • Nuclear Energy Technology
  • Fuel Cells and Electrolyzers
  • Semiconductors
  • Neodymium Magnets
  • Platinum Group Metals and other materials used as Catalysts
  • Carbon Capture, Storage, and Transportation Materials
  • Cybersecurity and Digital Components
  • Commercialization and Competitiveness

Interested stakeholders can submit comments here, and the comment deadline is 5:00pm on January 15, 2022.

 

Other Regional and National News of Note

  • Vestas announces modular nacelles for offshore wind turbines: On November 17, 2021, wind energy manufacturer Vestas announced the introduction of a modularized wind turbine nacelle design as a step towards reaching full wind turbine modularity. The new nacelle design takes general industry logistics standards into account, allowing them to be transferred with less specialized handling needed. Vestas is promoting a “simple click-on system,” which allows for easy servicing and upgrade possibilities over the lifetime of the system. The modular nacelle is already in use in Vestas’ V236-15MW turbine and will be utilized in future turbine variants.
  • Gas Utility Symposium set for December 7 and 8: The Brattle Group is holding a virtual Future of Gas Utilities Symposium on December 7 and December 8, 2021. The Symposium will explore the role that natural gas utilities can play in the transition towards decarbonization, featuring experts from across the country. Those interested in participating can register for day one and day two.
  • FERC and NERC researchers release Report on Texas power outages; Provide 28 recommendations for future prevention: A team made up of staff from the FERC, the North American Electric Reliability Corporation (NERC), Regional Reliability Entities Midwest Reliability Organization (MRO), Northeast Power Coordinating Council (NPCC), ReliabilityFirst Corporation (RF), SERC Corporation (SERC), Texas Reliability Entity (Texas RE) and Western Electricity Coordinating Council (WECC), as well as the U.S. Department of Energy and the National Oceanic and Atmospheric Administration (NOAA), have released a joint report entitled “The February 2021 Cold Weather Outages in Texas and the South Central United States.” The report provides an exhaustive timeline on the events in February 2021 that led to power outages across Texas and other southern states, and offers explanations and recommendations based on the analysis of the event. The Report found that 49 generating units (15% or 1,944 MW of nameplate capacity) in the Southwest Power Pool (SPP) and 26 units in ERCOT (7% or 3,675MW) did not have any winterization plans. Freezing issues caused 44% of unplanned outages, while fuel issues caused 31%. Wind turbines experienced 117 outages between SPP and ERCOT, with freezing being the main issue 98% of the time. The report issued a total of 28 key recommendations to prevent future widespread outages, including:
    • Revising the mandatory Reliability Standards to require steps such as retrofitting existing generation units to operate in colder temperatures, conducting annual trainings on winterization plans, and determining the percentage of total generating capacity that can be relied upon during cold weather events;
    • Requiring natural gas facilities implement cold weather preparedness plans;
    • Creating a forum led by FERC to identify actions to improve the reliability of the natural gas infrastructure system;
    • Analyzing behind the meter (BTM) intermittent generation effects to improve load forecasts; and
    • Deploying demand response measures and energy efficiency incentives.
  • NERC releases Winter Reliability Assessment; Identifies New England as region with high risk: On November 22, 2021, the North American Electric Reliability Corp. (NERC) released its 2021-2022 Winter Reliability Assessment. The Report found that regions vulnerable to extreme weather, natural gas supply disruptions, and low hydro conditions are facing elevated reliability risk this winter, and recommended proactive steps for extreme weather operation. The Assessment identified New England as one region with elevated risk, because its natural gas transportation infrastructure can be constrained in times of peak demand for generation and consumer heating needs. New England also competes for liquefied natural gas supply on the world market, and this winter is anticipated to bring an unprecedented demand for liquefied natural gas. NERC recommended that stakeholders review NERC’s Generating Unit Winter Weather Readiness Guideline. They also advised balancing authorities to poll the generating units periodically and in advance of severe weather to better understand their readiness level, and to work with reliability coordinators to conduct drills on alert protocols. Finally, they recommended that distribution providers and load-serving entities review rolling blackout procedures and non-firm customer inventories to ensure that critical infrastructure loads are not affected. ISO-NE subsequently issued a press release in which they shared concerns that “fuel supply issues may threaten ability to meet consumer demand if the region sees extended periods of extreme cold weather.” While ISO-NE expects to have sufficient supplies if the winter is mild, they cautioned that an extended cold snap could put the region in a perilous position.
  • First Solar signs deal with Lightsource bp and bp for 5.4 GW of solar panels: On November 22, 2021, U.S.-based solar panel manufacturer First Solar announced that solar company Lightsource bp and energy company bp have ordered 5.4 GW of their panels for delivery between 2023 and 2025 (firm orders for 4.4 GW and options for an additional 1 GW). The deal is for First Solar’s “ultra-low carbon thin film solar modules.” Jeff Dennis, managing director and general counsel for Advanced Energy Economy, noted that this may be a precursor to more solar developers stocking up on essential supplies ahead of increased demand from favorable government policy and price volatility in traditional energy sources.
  • New report projects 500,000 new jobs will be created by microgrid expansion by 2030: A new report from Guidehouse found that by 2030 renewable microgrids in the country will generate half a million new jobs, $72 billion in GDP growth, and $146 billion in sales across the supply chain. The study assumed that 32 GW of microgrids will be installed by the end of the decade.
  • MIT researchers find new semi solid flow battery solution that could compete with lithium-ion technology: Researchers at the Massachusetts Institute of Technology (MIT) have announced a new energy storage technology called a semi solid flow battery, which they claim will be a cost-competitive form of energy storage that can complement variable renewable energy sources including wind and solar. Their solution utilizes cheaper chemical components than other flow battery systems, and has beat out lithium-ion batteries and vanadium redox flow batteries in tests where batteries are discharged longer than a day.
  • New storage study finds that ConnectedSolution payments should be increased: According to a new report from the Applied Economics Clinic (AEC) and the Clean Energy Group (CEG), customer-sited battery storage is by far the cheapest new winter peaking resource available to Massachusetts utilities. The report found that payments to customers in the ConnectedSolutions demand response program should be increased by at least 33%, and program budgets should be expanded immediately to reflect their efficacy. Winter electric peaking capacity, the report adds, is vital for the grid because it helps to prevent winter blackouts.

 

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Best regards,

The SEA Team

 

 

A picture containing windmill Description automatically generatedSustainable Energy Advantage, LLC

Jim Kennerly – Director, Policy Analytics Practice Lead

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Eyes & Ears Terms and Conditions

Eyes & Ears Service is provided to the Subscriber for the Subscriber’s internal use only, and may be distributed to employees, officers and directors of Subscriber or Authorized Affiliate who have been made aware of the Limitations on Use under the Subscription Agreement. Subscriber agrees not to distribute materials received under the Eyes & Ears Service, whether by written, oral or electronic means, to any other person, including consultants engaged by Subscriber, except with specific written permission from SEA or as required by applicable law, regulatory proceeding or exchange rule. Subscriber is subject to additional terms and conditions stated in the Subscription Agreement.