Wave Hello to Interconnection Cost Waivers

IREC report on interconnection of small solar and storage projects points the way forward for interconnection in Maine

On March 11, 2022, the Maine Public Utilities Commission (PUC) issued a Notice of Inquiry in Docket 2022-00071, containing a Report prepared for the PUC by the Interstate Renewable Energy Council (IREC) and Shute, Mihaly & Weinberger, LLP. The two entities were hired to review Maine’s behind the meter (BTM) generation interconnection procedures and cost allocation. The Report was produced as a result of P.L. 2021, ch. 264 which requires the PUC to open a proceeding and issue an order related to IREC’s evaluation by April 18, 2022, and to adopt cost allocation methods addressed in the Act by October 18, 2022.

We summarize the Report’s “priority considerations” below (but note there are “additional considerations” beginning on page 72 of the report), organized by subject matter and presented in order of the priority given each subject and attendant recommendation in the Report. (Please note that throughout we refer to definitions and processes contained in Chapter 324, the current Small Generator Interconnection Procedures):

Distribution Upgrade Cost Exemption: P.L. 2021, Ch. 264 directed the PUC to ensure that the costs of interconnecting distributed energy resources (DERs) (notably solar or paired solar and storage projects) that serve a customer’s load, are “limited to interconnection facility upgrades and do not include the cost of distribution upgrades.” Maine currently uses a cost-causation model for DER interconnection, which can sometimes lead to allocation of distribution upgrade costs (i.e., work to the distribution system beyond the Point of Common Coupling) to interconnecting DER customers.

The Report noted that California, New York, Minnesota, and Massachusetts have implemented (or are currently implementing) reforms to cap, socialize, or otherwise pre-pay all or a portion of the interconnection costs for small generators, and recommended that the PUC identify:

• Which projects will be eligible for a distribution upgrade cost waiver;
• What work qualifies as a distribution upgrade; and
• How distribution upgrade costs that fall under the exemption would be recovered.

Aggregate Generation Definition: The Report included an extended discussion of how the definition of aggregate generation, used when the electric distribution companies (EDCs) calculate interconnection costs, impacts the distribution of costs to projects of different sizes. As recently revised in an Order amending several elements of Chapter 324, the PUC defined aggregate generation as all existing generation, plus the generation from the proposing generator, plus projects with a signed interconnection agreement that have paid 100% of their costs to interconnect.

The Report noted, similar to arguments made by Central Maine Power (CMP) in its Request for Reconsideration that the revised definition of aggregate generation could fail to account for (mostly Level 3 and 4) projects ahead of the proposed interconnecting small project in the queue that will likely be built but have not yet paid all their interconnection cost. This in turn could lead to unallocated costs and/or restudy of the other projects.

However, the Report also noted that including all projects in the interconnection queue as part of aggregate generation could lead to smaller projects being assigned unnecessarily high interconnection costs when projects ahead of the interconnecting customers may well drop out and free up capacity on the line. The Report observed that every other jurisdiction surveyed includes all queued generation ahead of a given project as aggregate generation despite this potential drawback.

The Report recommended that a cost waiver, discussed above, could alleviate many of the issues identified. Alternatively, the PUC could carve out a certain percentage of every distribution circuit for small projects or direct the EDCs to conduct “proactive upgrades” to the distribution system.

15% Penetration Test: Pursuant to section 7 of Chapter 324, the aggregate generation on a Radial Distribution Circuit cannot exceed 15% of a line segment’s annual peak load. The line segment is defined as a section that is bounded by “automatic sectionalizing devices or the end of the distribution line.” The Report argued that:

• The 15% of a line segment’s peak load is intended as a conservative approximation of a safe level of DER penetration, using 15% of peak load as a proxy for 50% of the minimum load on a circuit under the assumption that minimum load is usually 30% of peak load. However, this benchmark was set before much was known about DER impacts. More data is now available about actual minimum loads on a circuit. Given these factors, the 15% test is likely is too conservative and leads to projects failing a screen that would not have negative impacts such as unintentional islanding, voltage deviations, or protection miscoordination;
• Versant Power inappropriately defines a fuse as an automatic sectionalizing device, leading to smaller line sections and projects failing screens when they pose no risk to the distribution system; CMP, on the other hand looks at “total circuit peak load compared to total generation on the circuit” for purposes of the 15% test.

The Report recommended that the PUC clarify that an automatic sectionalizing device means an interrupting device such as a recloser, and that aggregate generation for the purposes of the 15% screen should only count the DER export capacity, not nameplate capacity, as it is only the power that enters the distribution grid that has distribution grid impacts (and can potentially be mitigated by storage or other export controls).

Shared Secondary Screens: The screening test for a single-phase shared secondary conductor assumes negative impacts occur at twenty kilovolt-amps (20 kVA), however, the actual transformers (and therefore kVA able to be accommodated from DERs) ranges from 15-167 kVA. The Report recommended setting the allowed kVA at 65% of the given transformer before further study is needed rather than a fixed value. Like the above recommendation, the Report recommended that the screen should be based upon export capacity, not nameplate capacity.

Level 2 Project Size: The Report recommended moving away from a flat 2 MW or less size cap on Level 2 screens and instead use the FERC Small Generator Interconnection Procedures chart, which considers line capacity and placement of the resource on the line, as shown below. The Report also recommended that the EDCs prepare hosting capacity maps and that projects be allowed to elect to proceed directly to study.

Additional Review: Maine’s small generator interconnection rules require the EDCs to offer “additional review” if a project fails a screening test (most often the 15% test described above) to determine if there will actually be safety impacts to the grid. The Report notes, however, that EDCs are inconsistent in the scope and detail of such reviews, and don’t consistently offer them. The Report notes that “Supplemental Review” processes have been adopted in multiple other states and recommends that Maine adopt such a program in lieu of the Additional Review. Under Supplemental Review, a project that fails an initial screen is then tested to determine:

• Whether aggregated generation on the line section exceeds 100% of the line section’s minimum load;
• Whether there will be negative impacts to voltage regulation; and
• Whether there will be impacts to safety and reliability.

Upon failure of any of these Supplemental Review tests the project and proceed to detailed study (which is more in-depth than Supplemental review). The Report recommends a flat fee for Supplemental Review.

Technical Requirements: The Report noted that EDC technical requirements are not uniform or specific and that, especially in Versant territory, they do not reflect industry best practices. The Report recommended a technical working group to develop specific, statewide interconnection standards.

Screen Failure Information: The Report notes that the information provided by the EDCs upon a screen failure is often insufficient for a developer to make business decisions about whether to modify the project or proceed to a Level 4 screen. The Report recommends that in addition to the information the PUC ordered the EDCs to provide in its recent Order revising Chapter 324, the EDCs should provide (listed verbatim):

1) [the EDC’s] definition of the line section and identification of the automatic sectionalizing device that bounds the line section, and

2) the aggregated generation of the line section.

The EDCs should also provide further specificity on the technical reason for screen failure and the limitations or thresholds that cause that failure (such as how the line section is defined or details on how aggregate generation is determined), similar to language adopted in Illinois and Massachusetts.

Storage: The Report observes that there are no mentions of energy storage in the Maine interconnection rules and that they “lack important technical and process details” for how storage systems will be reviewed, failing to address storage’s flexibility and ability to control exports to the grid. The Report recommended that the PUC establish storage-specific interconnection specifications, and recommended the PUC review the forthcoming Building A Technically Reliable Interconnection Evolution for Storage (BATRIES) report (which will be partly produced by IREC and Shute, Mihaly & Weinberger, LLP, the authors of the instant Report, with several co-authors and funded by the U.S. Department of Energy Solar Energy Technologies Office).

Interconnection Upgrade Construction Timelines: IREC’s Report asserted that while the interconnection rules set out timelines for steps in the interconnection process, tracking compliance with these timelines is “limited and inconsistent” across the EDCs. Developers interviewed indicated that the interconnection process slows to “four to ten months beyond the expected timeline” if an upgrade is required. Delays in field planning appointments for transformer upgrades were confirmed by CMP. The Report recommended that compliance with interconnection timelines should be reported by the EDCs, and that a construction schedule should be included with an interconnection agreement.

Dispute Resolution: The current dispute resolution procedure prescribes a three-step process: 1) good-faith negotiation, 2) informal dispute resolution with PUC staff and, if necessary, 3) adjudicatory proceeding. Both developers and the EDCs expressed that the current process is time-consuming and cost-intensive, and often ends in formal proceedings despite attempts at mediation. They also asserted that the PUC staff are not empowered to make binding decisions, are sometimes insufficiently resourced, and do not have the requisite technical knowledge. The Report recommended that Maine establish a process similar to Massachusetts’s three-step system in which an Ombudsperson staff position is involved in the second step of mediation with the assistance of a technical advisor if necessary and specific timelines are established for each step.

Next Steps: The PUC has requested comments on the IREC report by April 4, 2022.

We note this is once piece of a larger movement to reform the interconnection process in Maine. These include Docket 2021-00039, the PUC Investigation of the Design and Operation of Maine’s Electric Distribution System which includes multiple reports form Electric Power Engineers, and a recent PUC Order approving a settlement agreement between CMP and several solar developer stakeholders. To track these proceedings and more, consider subscribing to Sustainable Energy Advantage’s Eyes and Ears subscription service.