AriSEIA filed direct testimony today in the Trico rate case, making the following recommendations:

• Reject Trico’s proposal to eliminate net metering for all non-residential systems, entirely.
• If the net metering proposal is approved, reject Trico’s proposal to close the non-residential net metering tariff on the effective date of the order in this docket.
• Reject Trico’s proposal to eliminate the 10-year export lock for new non-residential DG systems.

May 9, 2025
 
Arizona Public Service
400 N 5th Street
Phoenix, AZ 85004
 
RE: AriSEIA Comments on the APS Interconnection Manual Draft Rev. 10
 
Dear APS Interconnection Team,
 
As agreed, we are submitting this summary of the five specific handbook topics of present concern to AriSEIA in advance of APS filing the revised manual with the Commission. We would like to reach resolution prior to filing, if possible.

Section 8.2, Utility Disconnect

Supply side connections of non-residential systems and the use of the National Electrical Code (NEC)-required external Fused Service Disconnect as the approved Utility Disconnect – Rev. 9.0 to the manual allows the Fused Service Disconnects for customer GF supply side connections in section 8.2(A) to be used as the Utility Disconnect. This language was explicitly negotiated and agreed to by APS during the 2021-2022 manual revisions and was approved by the Commission in November 2022. The use of a Fused Service Disconnect also as a Utility Disconnect is ubiquitous across the country, with those requiring redundant disconnects being the exception rather than the rule. Notably, Tucson Electric Power (TEP) allows the Fused Service Disconnect to serve as the DG Disconnect (see TEP’s Interconnection Manual for Distributed Generation, Section 9.2.1.b) as does Salt River Project (see SRP’s DER Technical Requirements, Section 2.8.1.b). All California utilities also allow for Fused Service Disconnects to serve as the Utility Disconnect – see PG&E’s Supply Side Interconnection Requirements for reference.
 
An additional Utility Disconnect for line-side/supply-side taps beyond a Fused Service Disconnect per NEC is redundant, arbitrary, and a costly requirement, and ARISEIA objects to the Rev. 10 proposed language that limits the dual-purpose potential of Fused Service Disconnects to residential single-phase systems. Moreover, the unilateral and retroactive enforcement of changes to the approved APS Interconnection Manual language, which were negotiated in good faith and approved by the Commission, is a significant oversight by APS management and has led to countless thousands of dollars of additional cost burdens on its customers since approval in 2022. APS staff should immediately adhere to the original intent of the language as previously approved, and attached to these comments are an exhibit demonstrating the written and clear intent to modify the language to remove unnecessary equipment from customer-owned GF installations (See Comment 3 and Response).
 
Furthermore, the verbal comments offered by APS that non-residential GF installations have greater public access than residential systems is specious, as requiring separate fused disconnects and utility disconnects results in double the number of devices the public can access and operate. Locking provisions are readily accessible for both residential and nonresidential versions of Fused Service Disconnects and are a simple solution to the otherwise costly approach administered by APS requiring an additional Utility Disconnect.
 
The NEC is the governing standard for the safe installation of electrical wiring and equipment in the United States. It is fundamentally a safety standard. Its primary purpose is to protect people and property from electrical hazards by preventing electrical fires, reducing risk of shock, setting clear installation standards, ensuring safe use of new technologies, promoting uniformity, and setting guidelines for inspections and permits. The NEC does not require a second utility disconnect for commercial-scale solar projects that are interconnected on the utility side of a customer’s meter; the only equipment required for safety purposes is a single fused service disconnect in accordance with NEC 2017 230.82(6), 705.12(A), and 705.31. Therefore, an additional Utility Disconnect is not necessary for the safe operation of a solar photovoltaic system, and APS should align with its state and national utility counterparts by removing this requirement.
 
Section 9.2, Production Metering Requirements

APS requires production metering for Static Inverter based Energy Storage Systems unless they are co-located with a PV system and properly configured, or unless the customer agrees to provide equivalent data hourly.  AriSEIA has consistently objected to metering battery discharge, including Rev. 9 of the manual which limited the requirement to standalone battery systems. Note that an Energy Storage System does not produce power at all, so the need for a “production meter” is nonsensical. This requirement will prove even more excessive as APS continues to progress toward adopting electric vehicles as an additional means of balancing the load on the electric grid. Meter disconnects further exacerbate the cost of this requirement. Short of an optional utility program to monitor or dispatch customer battery discharge and compensate customers, the customer’s site meter is sufficient to support the financial transaction for exported energy from battery systems. Utilities do not need real time measurement of battery usage any more than for sub-metered loads turned on or off. AriSEIA recommends that section (C) be removed in its entirety.

Section 10.4, Inadvertent Export or Active Power-Limiting Protection Requirements

The second sentence says “For GF’s with kVA rating greater than POI kVA rating protection requirements…” This sentence is missing a limiting kVA rating value separate from the POI rating. The value should be above the Commission limits that apply to Inadvertent Export Systems considered Fast Track.

Section 4.1, Separate System

The revision to include all Non-exporting systems as separate systems needs adjustments. Unlike backup systems, they do serve customer loads in parallel to the utility system on a continuous basis. The language confuses the issue of needing a Transfer Switch, which only applies to those Non-exporting systems incorporating a Backup System operating mode. The non-exporting feature can be provided by control systems and/or relays instead of a transfer scheme. Other sections deal with Non-exporting systems and appropriate exemptions from requirements for exporting systems. AriSEIA suggests limiting the Separate System definition to Non-exporting systems that can function as a Backup system. The new provisions of section 4.1(D) are appropriate for Non-Exporting systems regardless of the Backup capability, which should be clarified as part of the discussion.

Section 2, Definitions

The new definition for Point of Service describes the identical location as the current definition for Point of Interconnection, except without a GF operating in parallel. Is it needed in the Interconnection Manual? Also, the current definition claims the POI is also known as the Point of Common Coupling. In the industry, the POCC refers to the connection that could be at a different location than customer service equipment, such as a utility transformer. Even in the absence of a deregulated generation market, a change to this language could be useful for developers of APS distributed solar systems and future Community Solar systems.

Thank you for considering these comments. We would appreciate a response before filing the manual revision.
​
Sincerely,
/s/ Autumn T. Johnson
Executive Director
AriSEIA 
(520) 240-4757
[email protected]
 

AriSEIA filed direct testimony in the Sulphur Springs (SSVEC) rate case today. Our testimony makes the following recommendations:

• Reject SSVEC’s proposal to eliminate net metering for all non-residential systems, entirely.
• If the net metering proposal is approved, reject SSVEC's proposal to back date the effective date of a net metering freeze to the date of filing.
• If the net metering proposal is approved, reject SSVEC’s proposal to limit grandfathering to November 17, 2037.
• Reject SSVEC’s proposal to eliminate the 10-year export lock for DG systems.
• Approve the elimination of the DG meter fee.
• Require SSVEC to provide a bill credit to all residential DG members for the difference between the export rate and the actual avoided cost rate for all exported energy in 2023, plus interest. 

Navajo County
100 East Code Talkers Drive
Holbrook, AZ 86025
 
RE: Navajo County Zoning Ordinance Update, Article 12: Renewable Energy
 
Supervisors, Commissioners, and Community Development Staff,

The Arizona Solar Energy Industries Association (AriSEIA) appreciates the opportunity to provide comments on the draft zoning ordinance for renewable energy facilities in Navajo County. AriSEIA is a nonprofit trade association representing the solar and storage industries across Arizona. We advocate for thoughtful, streamlined, and effective land use policies that enable renewable energy development while respecting community values and local priorities. We have previously engaged on the City of Eloy, Mohave County, City of Buckeye, Town of Chino Valley, Yavapai County, City of Surprise, and Apache County solar/storage ordinances.

We commend the County’s efforts to develop a regulatory framework for renewable energy and offer the following comments and recommendations to improve clarity, reduce unintended burdens, and ensure alignment with industry standards and legal precedents.

I. General Legal and Process Concerns
1. Entitlements Should Not Require BOS Approval to Transfer

We recommend against the provision requiring Board approval for the transfer or assignment of an approved Special Use Permit (SUP). Land use entitlements run with the land—not the landowner—and cannot be subject to reassignment approvals. Requiring discretionary approval for every property transfer introduces legal uncertainty and would significantly chill investment. If the original conditions remain in effect and are adhered to by the new owner, no additional approval should be required.

2. Clarity on the Relationship Between SUPs and Development Agreements
The draft appears to treat Development Agreements and SUPs as overlapping but does not clearly delineate the requirements for each. Specifically, it is unclear whether the Development Agreement will incorporate requirements from Section 1201(2)(u). Greater clarity is needed to avoid duplicative or conflicting obligations.

II. Comments on Draft Article 12 – Section 1201 (Solar and General Renewable Energy)
3. Impervious Surface Designation
We strongly urge the County to clarify that solar arrays are not considered impervious surfaces and are exempt from the Maximum Lot Coverage standards in A-General (50%) and RU-20 (3%) zones. The definition of “impervious” should be revised or clarified to exclude structures like solar arrays, particularly when vegetation or non-compacted soils are preserved beneath the panels.

4. Underground Collection Line Requirement (1201(2)(d))
We recommend flexibility in the siting of collection lines. While undergrounding may reduce some visual impacts, it can increase cost and site disturbance. These lines typically run within the array footprint and are low-profile. Allowing above-ground options where appropriate could reduce environmental disruption and construction costs.

5. Fence Height Discrepancy (1201(2)(r))
The draft permits fences up to 8 feet in height for renewable energy projects, but the general zoning standards cap fence/wall height at 7 feet. This inconsistency should be resolved to avoid ambiguity in enforcement.

6. Decommissioning Bond Timing and Beneficiaries (1201(2)(s))
We recommend phasing the decommissioning bond over the first 10 years of operation, with full bonding (minus salvage value) required by year 10. This balances financial feasibility with long-term accountability. Additionally, we urge the County to designate a single bond beneficiary—typically the County—to streamline administration and avoid disputes.

7. Tribal Consultation Guidance (1201(2)(v))
We request that the County provide clear expectations for what constitutes adequate tribal consultation. This includes what documentation will be accepted and what level of engagement is required.

8. Public Communication Requirements (1201(2)(x))
The requirement for lifetime responsiveness to inquiries is operationally unfeasible. We suggest limiting real-time responsiveness to the construction phase. For long-term operations, we propose a 24/7 emergency hotline, a publicly available online form, and a monthly response requirement for general inquiries.

9. Public Outreach and Project Changes (1201(2)(u))
We request clarity on whether the outreach described in 1201(2)(u) is a prerequisite to the public hearing process and what happens if key project features change after notifications are sent to surrounding landowners. A mechanism for reasonable updates should be included.

10. Avoid Regulatory Overreach into Federal or State Jurisdiction (1201(2)(j), 1201.1)
The ordinance appropriately avoids regulating projects on federal or state land but then attempts to impose technical standards (e.g., on experimental components or wildlife policy) outside the County’s expertise. Sections referencing FAA, USFWS, and other federal authorities should defer to their standards rather than impose independent criteria.

11. Problematic Language and Ambiguities
We recommend removing vague or subjective standards such as “minimal visual impact,” “low wildlife habitat value,” or “maximum extent possible.” These terms lack clear metrics and create enforcement risk. More appropriate phrasing would be “to the maximum extent feasible” with reference to applicable regulatory guidance.

12. Feedback Cards and Tabulated Results (1201(2)(u)(ii))
The ordinance calls for tabulating community feedback, but such data often reflects opposition bias due to self-selection. It should be considered informational, not determinative.

13. Decommissioning Enforcement (1201(2)(aa)(ii))
The ordinance should include standard cure period language to protect against subjective enforcement or abrupt bond forfeiture. This provides fairness and legal clarity in the event of a dispute.

III. Comments on Draft Article 12 – Section 1202 (Wind-Specific Provisions)
14. Noise Standards (1202(1)(a) & (b))
We recommend adopting standard sound thresholds of 45 dBA at night and 55 dBA during the day, based on EPA guidance. The “baseline plus 5 dBA” approach is difficult to measure and legally risky due to inconsistent baseline data.

15. Low-Frequency Noise (1202(1)(c))
We strongly recommend removing all references to low-frequency noise. There is no peer-reviewed scientific evidence supporting its health impacts, and this provision responds to misinformation rather than substantiated risk.

16. Wind Turbine Setbacks (1202 generally)
The proposed setbacks are excessive and unsupported by public health data, effectively amounting to a ban on wind development. AriSEIA has provided the below table of commonly accepted setbacks that maintain public safety while allowing viable project siting. 

Occupied Community Buildings
Nearest Structure
2.1x tip height (meters)

Participating Residences
Nearest Structure
1.1x tip height (meters)

Non-Participating Residences
Nearest Structure
2.1x tip height (meters)

Non-Participating Property Lines
Property Line
1.1x tip height (meters)

Public Road Rights-of-way
Centerline+60 feet
1.1x tip height (meters)

Setback from publicly managed lands
Property Line
2.1x tip height (meters)

County Roads
Center Line+30 feet
1.1x tip height (meters)

Overhead communication lines
Centerline+50 feet
1.1x tip height (meters)

Shadow Flicker
Tower Base
30 (hrs/yr at receptor)

Transmission and Distribution lines
Centerline+50 feet
1.1x tip height (meters)

Railroads
Centerline+50 feet
1.1x blade length (meters)

Public use areas/buildings, office buildings
Nearest Structure
1.1x tip height (meters)

Boundaries of Incorporated Communities
Boundary Line
1.0 (mile)

O&G pipelines
Center Line+30 feet
1.1x blade length (meters)

Sound emissions - daytime
Tower Base
55 (dBA)

Sound emissions - nighttime
Tower Base
45 (dBA)

Ice-Throw Setback
Tower Base
1.1x tip height (meters)
 
IV. Final CommentsThis draft ordinance includes several constructive elements but also introduces significant risks of legal challenge, development delays, and regulatory overreach. AriSEIA urges the Commission and/or Board to revise the ordinance to ensure clarity, legal consistency, and feasibility for renewable energy developers while maintaining appropriate community safeguards. We remain available to support the County in this process and provide additional detail upon request.

Thank you for your consideration.

Respectfully,
Autumn Johnson
Executive Director
AriSEIA 
(520) 240-4757
[email protected]

Arizona Corporation Commission
1200 W. Washington Street
Phoenix, AZ 85007
 
RE: Response to Staff Proposed Framework for IRP License Reimbursement; IRP Docket No. E-99999A-25-0058
 
Chairman and Commissioners,
 
AriSEIA is a member of both the TEP/UNSE and APS Resource Planning Advisory Councils (RPAC). We have been engaged with the last two TEP and APS Integrated Resource Plans (IRPs). In addition to being on the RPACs, regularly attending the meetings, submitting detailed comments on the plans, presenting at the IRP workshop and IRP open meeting; we also participated in the modeling process last time.
 
AriSEIA filed comments on the original Staff recommendation on October 4, 2024.[1] AriSEIA continues to maintain that it is a mistake to require stakeholders to pay for their own modeling licenses. AriSEIA also filed comments refuting utility statements at the IRP workshop that stakeholders had not properly utilized their licenses on August 27, 2024.[2] AriSEIA filed comments on the 2023 IRPs on January 31, 2024 as required. That filing was 142 pages long.[3] AriSEIA also filed 263 pages of joint comments with Vote Solar and Advanced Energy United as to the 2023 IRPs on January 31, 2024.[4] That filing included 124 slides as to RMI’s analysis of TEP and APS’ IRPs, based on their use of the modeling licenses. RMI was our consultant in that matter. AriSEIA filed joint comments in the same docket supporting the need to move the IRP deadline due to modeling delays on May 2, 2023.[5] AriSEIA filed a letter to the docket expressing concerns that APS and TEP were violating the 2020 IRP Order in delaying the release of the modeling tools on April 28, 2023.[6] We note these filings now to draw attention to our robust participation in IRP dockets, but also to highlight that issues with the modeling licenses plagued all of 2023. AriSEIA does not recommend changing the process yet again, as we had just barely worked out the issues with the prior process.
 
Nevertheless, we highlight the following concerns with the Utilities Division Staff Proposed Framework for IRP License Reimbursement filed on May 9, 2025.[7] First, it is important this issue is addressed as soon as possible. It was very clear last time that waiting until the calendar year in which the IRP is due is too late to obtain the modeling licenses and corresponding NDAs, etc. This resulted in significant delays last time, which resulted in the IRP deadline having to be postponed. Second, it is important that the utilities are negotiating down the price of the licenses and provide that price imminently. It is not clear how many licenses we need, how much they cost, or how long we would need to forgo recouping that deposit.
 
It is still unclear what problem this policy is trying to solve. It has been stated that “some” stakeholders, apparently including AriSEIA, did not do enough work to “deserve” a modeling license, despite all of the work described above. However, there were no articulated requirements we failed to meet. The Commission could simply set requirements and not require stakeholders to upfront the cost. There is no articulated reason that small nonprofits need to expend tens of thousands of dollars in advance to provide an essential service to this Commission (i.e., critical review of portfolios that cost ratepayers billions of dollars). That being said, if the Commission proceeds on its current course the requirements should be a floor. It is very strenuous to require stakeholders to run three separate portfolios just to be reimbursed for the licenses.
 
RECOMMENDATION 1: Require One Model
 
AriSEIA recommends the policy require a stakeholder to run the base case scenario or one (not two) distinct portfolio. Staff’s concerns about ability to hire consultants, Staff capacity as to time, and their lack of any modeling in the 2023 IRP process highlight how onerous this work is. There is no substantiation as to why stakeholder need to run three models. One should be the floor. If a stakeholder has the time or resources to run more, then there is nothing stopping them from doing that.
  
RECOMMENDATION 2: Create a Data Request Process
 
Further, there were data limitations from the utilities last time that would not have even allowed stakeholders to run the base case as required by the policy. Stakeholders should not have to forgo their deposit due to a failure on the part of the utility. Not only should the policy be clear what the utilities must provide and by when, it should allow for a discovery like process. If you have issued a Letter of Intent, you should also be able to issue data requests that the utilities have to comply with in 10 days, just like in a rate case.
 
RECOMMENDATION 3: Honor Reciprocity as to Any Deadline Delays
 
Any delays by the utilities to meet their deadlines in the IRP process should correspond with an equal delay in the requirements for stakeholders to meet their subsequent deadlines. A delay on the part of a utility should not require a stakeholder to forfeit their deposit.
 
RECOMMENDATION 4: Allow Stakeholders to Jointly Complete the Framework Requirements
 
“Stakeholder” in this policy should not be singular. Stakeholders should be able to work collaboratively with one Letter of Intent and be able to share the data and responsibility for the requirements articulated in this policy, even if only one person is actually allowed to run the model (i.e., maintains the license). Stakeholders should be able to work together to fund one consultant. A consultant that does capacity expansion modeling likely exceeds $100,000. That number will go up if more modeling runs (like three) are required. Even with model license reimbursement, the Commission is making this process so onerous that most stakeholders, like AriSEIA, will not be able to participate absent working collaboratively with other stakeholders.
 
RECOMMENDATION 5: Reimbursement Must Occur within 60 days of October 30, 2026
 
Reimbursement should happen within 60 days of the stakeholder filing its analysis on October 30, 2026 and should not require a subsequent vote of the Commission and should, certainly, not have to wait until a vote of the Commission on the actual IRPs, which is typically one to two years after the IRPs are filed. A stakeholder being out >$30,000 for two to three years is not reasonable. The utilities will know what the requirements are and reimbursement should happen seamlessly after filing. If there is any kind of dispute, a stakeholder can notify Staff and that can be taken up by a vote of the Commission. But all stakeholders should not need a vote on something that a) you will have voted on already before the process commences and b) is not likely to be controversial. Note, should any of the deadlines be moved, the 60 days should run from the due date for filing the analysis.
 
RECOMMENDATION 6: Create a Scholarship Option
 
The Commission should consider a scholarship process for stakeholders that can demonstrate a financial hardship. The Commission should put parameters in place to make sure only qualified stakeholders qualify for the scholarship. If a stakeholder does qualify, they should be required to complete the requirements set out in this policy, but without paying for the license themselves. Suggested parameters may include: being a member of the RPAC, attending a certain percentage of RPAC meetings, demonstrated participation in the last IRP process, being a not for profit entity, and financial hardship either by 990 or other means. Penalty for obtaining a scholarship and not completing the requirements as set forth in this policy could be disqualification from any such similar program in the next IRP cycle.
 
RECOMMENDATION 7: Spread Out When the Fees are Due
 
Finally, entities should not have to upfront the entire cost of the license at the outset. Perhaps half is paid at the beginning and half is paid in Q1 2026 or some other date. Being out >$30,000 for multiple budget cycles could be very difficult for many nonprofit organizations.
 
Respectfully,
/s/ Autumn T. Johnson
Executive Director
AriSEIA 
(520) 240-4757
[email protected]

[1] AriSEIA Comments on the August 30, 2024 Utilities Division Memorandum and Amendments, Docket No. E-99999A-22-0046, filed October 4, 2024, available here https://docket.images.azcc.gov/E000039019.pdf?i=1749756384020.

[2] AriSEIA Response, Docket No. E-99999A-22-0046, filed August 27, 2024, available here https://docket.images.azcc.gov/E000037591.pdf?i=1749756384020.

[3] AriSEIA Comments on the APS and TEP 2023 IRPs, Docket No. E-99999A-22-0046, filed January 31, 2024, available here https://docket.images.azcc.gov/E000033415.pdf?i=1749756384020.

[4] Joint Comments of AriSEIA, Advanced Energy United, and Vote Solar on the 2023 IRPs, Docket No. E-99999A-22-0046, filed January 31, 2024, available at https://docket.images.azcc.gov/E000033451.pdf?i=1749756384020.

[5] Support for APS and TEP’s Request for an Extension of IRP Filing Deadline, Docket No. E-99999A-22-0046, filed May 2, 2023, available at https://docket.images.azcc.gov/E000026358.pdf?i=1749756384020.

[6] AriSEIA Letter on IRP Modeling Licenses, Docket No. E-99999A-22-0046, available at https://docket.images.azcc.gov/E000026311.pdf?i=1749756384020.

[7] Utilities Division Staff Proposed Framework for IRP License Reimbursement Memorandum, Docket No. E-99999A-25-0058, filed May 9, 2025, available here https://docket.images.azcc.gov/E000044023.pdf?i=1748461994048.