MREA and RENEW NE

Mr. Harry Lanphear
Administrative Director
Maine Public Utilities Commission
18 State House Station
Augusta, ME 04333-0018

Subject: Docket 2021-00223 – Comments on Notice of Inquiry

Mr. Lanphear:

The Maine Renewable Energy Association (MREA) and RENEW Northeast (RENEW) jointly submit the attached comments in response to the Commission’s August 4, 2021, Notice of Inquiry regarding issues raised by the procurement of transmission and renewable energy for northern Maine pursuant to an Act To Require Prompt and Effective Use of the Renewable Energy Resources of Northern Maine, P.L. 2021, Chapter 380 (Act) and its Procedural Order dated September 15, 2021, extending the date for comments to September 24, 2021.[1]

We strongly support the goals of the Act and encourage the Commission to move expeditiously with the required procurements. Discussions around a public policy solution to unlock the renewable resources of northern Maine have been occurring for many years, and this Act provides a way for Maine to move swiftly to meet important goals including more renewable energy, economic development, and greenhouse gas reductions.

Due to the statutory deadlines in the Act, Maine should proceed independently with the transmission and generation procurements while, in parallel, pursuing with the other New England States coordinated transmission planning and cost sharing to determine if a regional effort is possible within the timeframe set by the Act. Any delay could also cause Maine to miss out on the benefits of the Build Back Better Act, which has passed the U.S. House Energy and Commerce Committee. Should it become law, under in Section 30461, $8 billion in grants will be available for large scale transmission lines (above 1000 MW), and other lines deemed to be in the national interest by the Secretary of Energy. Should this legislation become law, other New England States might also be financially motivated to act swiftly as a region in making transmission investments.

When the Commission considers whether proposed transmission meets the public interest requirement in the Act, it should carefully consider how the transmission solutions offered can not only unlock Maine’s renewable energy potential but do so without resulting in curtailment of existing renewable resources in both northern and southern Maine. This will benefit consumers by reducing the generation overbuild needed to meet reliability and emissions reduction requirements.

Thank you for opportunity to offer our perspective on implementation of these procurements.

Sincerely,

Jeremy N. Payne
Executive Director
Maine Renewable Energy Association

Francis Pullaro
Executive Director
RENEW Northeast

A. Federal and State Jurisdictional Issues 

  1. Please comment on the nature of the jurisdictional authority, roles, and relationships that are presented (or potentially presented) by the Act with respect to the Commission, ISO-NE and FERC. Please include in these comments issues presented at the point decisions regarding the procurement awards are made, as well as ongoing issues throughout the terms of the awarded contracts. Please address in these comments the potential for the Act, or specific provisions of the Act, to be preempted by federal law, such as federal statutes, regulations or regional rules and tariffs that govern the procurement, interconnection, cost allocation and other aspects of transmission service.  
  • Under the ISO New England (ISO or ISO-NE) Tariff, Maine has several approaches to secure the transmission upgrades needed to deliver new renewable energy out of Northern Maine: a participant-funded Elective Transmission Upgrade (ETU); a Public Policy Transmission Upgrade (PPTU) that could possibly be coupled with a Voluntary State Agreement (VSA) among the New England States; or as Market Efficiency Transmission Upgrade (METU).  
  • A benefit of the ETU option is that Maine retains control over project selection, whereas under a PPTU or METU, the transmission would be procured through the requirements set by the ISO-NE Open Access Transmission Tariff (OATT). The participant-funded ETU approach would, however, require Maine ratepayers to cover all of the costs unless an VSA was reached.
  • If the transmission were a PPTU or METU, then these have pre-defined cost allocation mechanisms in the ISO Tariff as they are not participant funded. There is also a competitive process in the Tariff to select transmission solutions for those types of upgrades so it is not clear that the states’ RFP selection decision would even be accepted by the ISO. 
    • Under the METU Process, the ISO conducts a study to see whether the benefits of a proposed upgrade outweigh the costs of such an upgrade. If it finds that the benefits do outweigh the costs, then those costs are regionalized. 
      • With a METU, the ISO must conduct its own competitive RFP process, which takes the decision making out of Maine’s hands.
      • While unlikely for the upgrades required to interconnect generation, a METU for ancillary upgrades could reduce congestion and make capacity deliverable. See the response to question C4 for further discussion of this topic. A METU would be a long process as ISO would need to study the need, conduct an RFP, and select a solution.
    • PPTU process
      • Once the public policy process has kicked off, the states lose control and ISO becomes the decision maker. 
      • To request a public policy upgrade, it must come from NESCOE, which means that all states must agree, and Maine cannot identify a public policy upgrade need on its own.
      • Cost allocation is predefined in the Tariff, though states can propose alternate cost allocation methodologies
      • Like a METU it would be a long process as ISO would need to study the need, conduct an RFP, and select a solution.
  • The only other transmission planning process in ISO’s Tariff is for reliability, but ISO will not identify this as a reliability issue
  • FERC has issued a new policy statement that clarifies the opportunity for the states to conduct transmission procurement through voluntary agreements. Whether as an ETU or a PPTU:
    • In conjunction with other New England states or on its own, Maine would propose an arrangement to plan and allocate costs for transmission.
    • FERC would approve the arrangement
    • The scope could be limited to transmission within Maine, or facilitate delivery outside of the state
    • In FERC’s June 17th, 2021, Policy Statement on State Voluntary State Agreements to Plan and Pay for Transmission Facilities, it interpreted the Federal Power Act to affirm the authority for any state or states to enter into such voluntary agreements with regional grid operators, and invited states interested in utilizing a Voluntary Agreement to engage with FERC staff. A novel approach would be for Maine to test this policy statement by developing transmission through a VSA with ISO-NE and any other interested states. Under this approach, Maine might craft a legal agreement with ISO-NE that would empower Maine to determine the transmission need and determine project selection, with ISO-NE serving as technical consultant to evaluate project bids.  The language could be adapted from the existing PPTU approach established in Attachment K of the OATT, with need determination, bid evaluation criteria and project selection authorities vested in Maine.  The costs of a project selected through the procurement could be allocated according to the default cost allocation methodology for PPTUs or an alternate cost allocation methodology proposed by states (e.g. Maine could pay for 100 percent of the cost, or share costs with other states, reflecting the likelihood that a share of renewable energy generation in Maine would be developed to serve the needs of other states). The legal agreement between Maine, any other interested states, and ISO-NE would be filed with FERC for approval, thus granting Maine and ISO-NE respective authorities within the procurement.  We encourage Maine to investigate this approach, in parallel to proceeding with a single-state ETU procurement.
  1. The statute specifies the procurement for a 345-kilovolt double circuit generation connection line, or, in the Commission’s discretion, a transmission line or lines of greater capacity. What characteristics would determine whether a line would qualify as an Elective Transmission Upgrade (“ETU”) pursuant to the rules and processes set forth by ISO-NE? If so, please describe what approvals, such as I.3.9 approvals, would be necessary to allow for interconnection in the ISO-NE system. If the line procured does not meet the ISO-NE definition of an ETU, what would be the nature of the line procured? 
  • The process for interconnecting an ETU, as well as its definition, is in Schedule 25 of the OATT
  • It is a participant-proposed and funded line that ISO would study to determine that it either has no adverse impacts on the system or what additional facilities are needed to achieve no adverse impact. This includes I.3.9 approval and an ETU Interconnection Agreement. The line can then be built and interconnected according to the terms of its interconnection agreement.
  • If the line is not an ETU per the ISO Tariff it could be:
    • A generator lead line. If a generator in northern Maine were to have a point of interconnection on the transmission system, then the generation project’s transmission line to deliver its energy to its point of interconnection could simply be part of the generator’s facilities. This is not uncommon. It is also possible for that line to be a shared use facility with other generators. This has been done before. Stetson I, a Maine wind facility, built a ~40-mile generator lead to interconnect and then entered into contractual arrangements with Stetson II and Rollins to interconnect using that line.
    • If ISO were to determine there is a market efficiency benefit of the line it could prusue a METU but this would spur a competitive RFP by ISO. Consequently, ISO could not simply select the project selected by Maine as the upgrade. 
    • If the states identified a public policy need for Maine transmission, then this line could be a PPTU. That would also kick off an ISO-led RFP.
  1. What factors would be relevant to a determination of whether an entity seeking to develop, construct and operate a transmission line pursuant to this procurement would be required to be part of the New England Regional Transmission Organization (RTO)? 
  • An ETU project sponsor will need to be, prior to commencement of service, a Market Participant (i.e., is a signatory to an ISO-NE Market Participant Service Agreement.
  • An ETU project sponsor must enter into an Elective Transmission Upgrade Interconnection Agreement for the purpose of interconnecting the Elective Transmission Upgrade to the Administered Transmission System. Prior to achieving Commercial Operation, the Elective Transmission Upgrade must be under the Operational Authority of the System Operator pursuant to a Transmission Operating Agreement and establish a schedule under the ISO OATT pursuant to which service will be offered over the Elective Transmission Upgrade. 
  • Any entity that intends to submit a proposal in response to an ISO identified need for a METU or PPTU must first be recognized by the ISO as a Qualified Transmission Project Sponsor (QTPS), in accordance with Section 4B of Attachment K to Section II of the Tariff.
  1. What would the relationship be between the Commission and the ISO-NE with respect to (1) decision making processes; (2) approval; and (3) ongoing oversight in the context of a procurement for such a line?    
  • If it is an ETU then ISO would have to study to determine it would pose no adverse impact on the grid. 
  1. What would the relationship be between the Commission and FERC with respect to (1) decision making processes; (2) approval; and (3) ongoing oversight in the context of a procurement for such a line? 
  • See response to A-4.
  1. Please comment on the requirements and/or necessary provisions for any transmission line(s) and any authorized contract(s) procured or ordered by the Commission pursuant to the Act with respect to FERC open access-related rules/policies/tariffs, including  the ISONE Open Access Transmission Tariff (OATT). For example, what jurisdictional issues (if any) would be presented by the relationship between the awarded transmission line and energy projects/contracts resulting from the procurements? 
  • See responses to question A-3. The interconnection agreement would get filed with the FERC. A TSA between the ETU owner and the buyer (e.g., Maine EDC) would be approved by FERC.
  1. How would charges associated with the ongoing operation of such a line, once developed and constructed, be reflected in FERC approved tariffs? What would be the process for determining such charges and ensuring resolution of disputes relating to such charges? 
  • A TSA provides the terms for a Maine EDC to purchase firm transmission service for the delivery of energy from the PPAs with the generators. The EDC’s costs of the TSA would be recovered in the same way that the PPA costs are recovered. If the EDC’s realized market prices are lower than its contracted prices, the EDC will seek Commission approval for recovery of “stranded costs” arising from the PPAs and TSAs.
  1. What form(s) of Transmission Service Agreement(s) (TSA) could potentially be required with respect to any transmission line(s) or energy project(s) procured by the Commission pursuant to the Act, and what factors would be relevant or determinative with respect to the TSA? 
  • In a TSA between the transmission developer and, for example, Maine EDCs, the transmission developer should commit to significant and effective cost containment requirements that protect consumers from cost overruns and other risks.

B. Applicability of Other Maine Statutory Provisions 

  1. The statute specifies the procurement for a “345-kilovolt double circuit generation connection line” (or line of greater capacity). The purpose of this line is clearly described in the Act. Given that purpose, what factors determine whether this line would meet the definition of a “generator interconnection transmission facility” set forth in 3132(1-B) of Title 35-A? At what point in the procurement processes would such definitional clarity be evident?  
  • The Act provides for the commission, in its discretion, to issue RFPs for a transmission line or lines of greater capacity. For that reason, the commission is not constrained to issue an RFP for only a generation interconnection line.
  • If a transmission facility is built to deliver power solely from a generator to the transmission system then according to 35-A MRS 3132 (1-B), it should be considered a generator lead. If the transmission facility should provide any other benefit other than delivering power from the generator to the transmission system, then by statute, the project would require prior Commission approval.
  1. But for the exception noted above for generator interconnection facilities, Section 3132 of Title 35-A requires any person proposing to erect a transmission line capable of operating at 69 kilovolts or more to file a petition with the Commission seeking a certificate of public convenience and necessity and approval for construction of the line. How do these statutory provisions relate to the procurement process set forth in the Act? What process, and process sequence, should the Commission use to ensure that the line complies with all applicable provisions in Maine law with respect to the erection of a transmission line and facilities?  
  • Any proposal for a transmission line would require the commission to grant a CPCN. Section 3132(6) provides, in part, that the Commission shall make specific findings as to the public need for the proposed transmission line. In determining public need, the Commission must consider several factors in Section 3131(6). The Commission’s CPCN evaluation of a transmission line submitted in fulfilment of the requirement of the Act would also need to consider the Act’s additional guidance on the public benefits of a project. According to the Act, “Advancing the renewable energy and climate policies and goals of the State, the near-term development of the transmission and other infrastructure necessary to reduce greenhouse gas emissions is in the public interest.”
  1. What other state, federal, regional, or other approvals may be required for the construction of the transmission line or lines and/or any potential agreement with a utility related to this procurement?  What would the nature and timing be for each such approval? Please address this question for the following entities and any others that may be involve related approval processes: FERC; ISO-NE; NMISA; Army Corp of Engineering; Maine DEP or other applicable State or local siting/environmental/permitting entity. What involvement or approval, if any, may be required of private or other entities (other than the bidder) related to this procurement, including but not limited to for issues such as right-of-way ownership and usage?  
  • As the Act encourages rights-of-way ownership and usage, the Commission should ensure that rights-of-way assets developed with ratepayer funding are utilized to the greatest benefit of ratepayers.
  • As we understand 35-A M.R.S. Section 3132 (1-B), the determination of whether a generator interconnection transmission facility “that is constructed, owned and operated by a generator of electricity solely for the purpose of electrically and physically interconnecting such generator to . . . the transmission system of a transmission and distribution utility” would not require generation developed in the footprint of NMISA to obtain any NMISA approvals if it is connected electrically with ISO-NE and not NMISA. (Several stakeholders discussed this issue in comments in submitted under Docket 2014-00048)
  1. What factors would be relevant to a determination of whether an entity seeking to develop, construct and operate a transmission line pursuant to this procurement is required to be a utility? Please also comment on the process and timing for approvals of any utility status. 
  • A generator-lead line or an ETU project sponsor is not required to be a utility. A market efficiency or public policy upgrade can only be proposed by a QTPS.
    • Definition of QTPS is in Section 4B of Attachment K, list of QTPS is in appendix 3 of Attachment K 
  • In contrast to ETU or other non-utility solutions, the Commission does not have direct jurisdiction as it would over a utility with respect to reliability in that utility’s service territory. Nevertheless, developers will meet the highest reliability standards through their compliance with ISO requirements. Competitive transmission proposals as an ETU also require developers to provide a significant non-refundable deposit that will give the Commission assurance that projects are viable and likely to reach commercial operation.
  1. Does the Act allow for a Maine T&D Utility, or an affiliate or Special Interest Entity (SPE) related to a Maine T&D utility, to participate as a bidder in this procurement? If a Maine T&D is awarded a project under the procurement, how does the Commission meet the Act’s requirement that it approve a contract between the T&D utility and a selected bidder if the entity selected is a Maine T&D utility or an affiliate of a Maine utility? 
  • The PUC should draft the terms of the RFP to maximize competition and transparency in project selection to minimize the risk of self-dealing. The commission alone should be responsible for project selection.

C. Right of Way Use Rights, Local and Land Use Issues 

  1. The Act requires the Commission to favor the use of existing utility and other rights-of-way and transmission corridors. What existing rights-of-way and corridors currently exist that would accommodate a transmission line pursuant to the Act? What issues should be considered during the procurement process regarding the rights associated with use of such existing rights-of-way, what processes should be used for such consideration, and what approvals could be required?  
  • See response to B3. In previous Maine PUC dockets and through non-Maine state procurements, developers have identified numerous pathways to make gigawatts of new and existing renewable energy deliverable. Some of the proposals have included use of existing rights-of-way. 
  1. What consideration, if any, should the Commission give during the selection process to the potential for land use-related disputes relating to siting of the transmission or generation projects? What consideration, if any, should the Commission give during the selection process to the objections of citizens or interested persons in the proposed location of proposals to build the transmission line? If such concerns should be considered, what process would be appropriate for soliciting and considering comments? 
  • All transmission projects should be responsibly developed. In addition to scenic, historical and recreation values, the Commission needs to consider a host of statutorily required factors including those specifically listed in the Act (35-A MRSA 3210-H (1)(A-D) and more broadly, the “public interest” as required by 35A MRSA 3210-H (2)(D). The public may submit comments at any time in any docket related to the Act. 
  1. What steps should be undertaken, either by potential bidders or the Commission, to allow a transmission line approved in this process to be “regionalized” as part of the ISO-NE transmission tariff? Should such regional treatment by required or preferred as part of the procurement process? 
  • Regionalization of transmission planning and cost allocation should not be required otherwise Maine is unlikely to meet the statutory deadlines for the procurements.  
  • Specially for meeting the deadlines in the Act, insufficient time exists to change the ISO-NE Tariff to accelerate the timetable under a PPTU for that process to meet Maine’s statutory deadlines. For a PPTU, 70 percent of costs would be regionalized while 30 percent of costs would be allocated to the state(s) that drive the public policy planning need (OATT Schedule 12 B.6).  The States have objected to this rigid formula and one or more states could block Maine from deploying the PPTU process for a Maine transmission upgrade. With the FERC policy statement on the SVA approach, the States should ultimately be successful in seeing the Tariff’s strict cost allocation requirement though not in time for the upcoming Maine procurement. Another shortcoming is that neither a METU nor PPTU have a process to have the winning bid in the Maine RFP selected as the solution for a METU or PPTU need. In those cases, ISO-NE would be required to run its own RFP.
  • Currently the ISO-NE Tariff has not provision to regionalize the cost of an ETU or generator lead line. Under an ETU, Maine could come to “side agreement” on cost allocation with other states without having to change the Tariff. Maine should engage with other states to explore these approaches in case an agreement can be reached but do so in parallel to Maine-only RFP to ensure the statutory deadlines are met.
  • During the development of a Maine-only RFP, it should keep in mind potential opportunities to find immediate funding from the federal government or, in later years, from other states. Congress is now advancing legislation that, in one bill, could result in the Department of Energy severing as an anchor tenant to large transmission lines while, in another bill, it could provide billions of dollars in grants for transmission development. Waiting for other New England states to partner with Maine could result in a delay that could result in other regions securing the limited $8 billion in federal transmission grants. On the other hand, the availability of significant funding might motivate one or more states to partner with Maine on transmission upgrades to capture the federal dollars.
  • The ISO in its ETU Tariff has a latecomer provision for one type of ETU development that can allow Maine to claw back costs from subsequently interconnecting generators building under contracts to fulfill the clean energy needs of other states. The late-comer provision will refund Maine’s share of the line, reducing its risk of initially overbuilding the line compared to the amount of generation that is initially procured. 
  • There is the potential that additional upgrades beyond the line contemplated in this legislation could be considered for a METU although the triggering need for METU has never been met. Historically, the ISO has only looked at production (fuel) cost savings for METU studies and not, for example, capacity. As fuel costs continue to come down, it is harder and harder to justify transmission upgrades solely based on production cost savings. For a METU to be viable, the ISO would need to change the way it does its METU studies. If successful, the cost of the transmission upgrades would be regionalized.
  1. What are the preferred points of interconnection of any transmission line with the ISO-NE system? Please comment on how the Commission should and could ensure that the value of energy (or other products) delivered over the line is not diminished due to the point at which it is delivered.  

In addition to the upgrades required to interconnect generation procured under the Act, both those new resources and existing generation in Maine would benefit from additional upgrades into southern Maine and increased export capability to the rest of the pool to address congestion that may be created or exacerbated by this new line. Such congestion, if not addressed according to ISO studies, could significantly reduce the value of energy produced by the northern Maine resources procured in this solicitation and by existing clean energy resources in Maine as well as lead to curtailed production from these resources. This, in turn, could lessen the greenhouse gas reduction benefits desired from this procurement, and potentially the economic viability of uncontracted renewable resources in Maine. If wind, solar, and hydro resources that do not have a marginal fuel cost for producing the next MWh of energy need to compete to determine which will be asked to produce and which will be asked to turn off, this is a recipe where one non-emitting resource will be displacing another non-emitting resource, which would contravene with the public policy goals to reduce the greenhouse gas emissions.[2] This would very likely require a new transmission line from Surowiec to a point closer to the southern Maine border.

Further, the congestion could prevent the newly procured Northern Maine resources from qualifying to sell their capacity into the Forward Capacity Market (FCM). Absent major changes to the transmission system, ISO cannot approve new generation projects to interconnect north of the Orrington-South interface according to detailed presentations it has made over the past several years. As depicted in the figure below, the ISO has suggested in recent studies that any new substantial interconnection of resources in northern Maine would best occur in the vicinity of Pittsfield to the north of the existing 345 kV Albion Road substation. However, bringing the new line to Pittsfield is an incomplete solution. In the northern Maine cluster interconnection studies, ISO-NE has identified the need for a new 345 kV transmission line from Pittsfield to Maine Yankee, with a connection between the two at Coopers Mills. The New England Clean Energy Connect (NECEC) project is responsible for building the southern portion of this line, from Coopers Mills to Maine Yankee. Assuming that project is completed, a new interconnection from northern Maine would be left with the requirement to build the section of line from Pittsfield to Coopers Mills. Though the Point of Interconnection for the new northern Maine line might be Pittsfield, these prior ISO studies indicate that a 345 kV line would be needed at least as far south as Coopers Mills.

If the Commission wishes to enable the new resources from this procurement to maximize its benefits to consumers, it would need a solution that helps these resources qualify to participate in the FCM, and in so doing the Surowiec-South interface limit would need to be increased. If the Surowiec-South interface limit is not increased further, the ISO’s analysis indicates that a high level of congestion could become commonplace on this interface. Even if improvements are made to the Surowiec-South interface to allow the new resources from this procurement to qualify for the FCM, the value of that capacity as well as all capacity in Maine would be severely diminished unless transmission upgrades are made that allow greater exports from Maine, a significant quantity of existing resources inside Maine retire- preferably ideally fossil-fuel units- and/or electricity demand in Maine is substantially increased such as through socalled “beneficial electrification” of Maine’s transportation and space heating sectors.

  1. With respect to the interconnection or delivery point, how should the Commission consider and evaluate (as part of the selection process) the potential impact a line and the associated generation to be delivered over it would have on congestion, losses, generator curtailment, or other locational implications? 
  • For years, the existing renewables in Northern New England, especially in the north of Maine, have experienced higher levels of congestion and curtailment than those in the rest of the region due to transmission limitations and the archaic operating procedures that render energy imports, such as those from New Brunswick, largely inflexible in the real time energy market. Adding significantly more clean generation in Maine without any retirements of fossil-fueled generation or transmission system upgrades would only exacerbate this congestion and cause it to spread to the entire state. Major transmission upgrades will be needed to make the significant additional clean energy supply in the state deliverable, including nearly 5,000 megawatts of solar in the ISO-NE and distribution level interconnection queues, the New England Clean Energy Connect, and the new northern Maine clean generation contemplated in the Act. Absent upgrades, market conditions could force Maine-based generation to compete against itself, instead of growing Maine’s output of renewable energy to further Maine’s policy goals.
  • Transmission upgrades developed under the Act and the terms of generation contracts should ensure new clean generation does not curtail existing clean generation and measures net benefits to carbon emissions (considering displaced existing clean generation).
  • The evaluation of any transmission proposal should assess the quantity and type of generation connected to the new transmission line. For example, significantly more than 1200 MWs nameplate generation that is comprised of a diversity of generation types (wind, solar, biomass, batteries) could be connected to the line such that the line is highly loaded in most hours. This will impact the resulting congestion that would be expected differently than a more infrequently loaded line resulting from just 1200 MW nameplate of one type of variable generation.
  1. How should the Commission consider any positive and negative implications from a proposed line that would interconnect the NMISA and ISO-NE regions?  
  • It should consider net benefits to carbon emissions (including how it affects displaced existing clean generation in Maine), system reliability, and economic (lower energy and capacity costs). However, any proposal to connect the two systems raises an additional set of complications and considerations for the PUC. It is worth noting that the Act does not require or provide preference to any proposal that interconnects NMISA and ISO-NE.

[1] The comments expressed herein represent the views of MREA and RENEW and not necessarily those of any particular member of either organization.

[2] See e.g., ISO New England, 2016/2017 Maine Resource Integration Study 43-45 (March 12, 2018), https://smd.iso-ne.com/operations-services/ceii/cluster-studies/final_maine_resource_integration_study_report.pdf (Critical Energy Infrastructure Information access required).

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