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AriSEIA filed direct testimony today in the Trico rate case, making the following recommendations:
0 Comments
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:
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. FOR IMMEDIATE RELEASE
Contact: Autumn Johnson (520) 240-4757 [email protected] Phoenix, AZ - Today, the Arizona Corporation Commission (ACC) voted 4-1 to approve Arizona Public Service's (APS) Virtual Power Plant (VPP) pilot program. AriSEIA proposed that APS adopt a VPP in its 2022 rate case. The ACC voted on February 22, 2024 to proceed with a VPP as a pilot program and ordered APS to file a plan of administration to implement that program. That implementation plan was voted on today and passed 4-1 with only Vice Chairman Myers voting no. A virtual power plant allows a utility to aggregate customer owned devices, like batteries, to provide capacity back to the grid. APS' proposal is a pay-for-performance model in which customers are paid only when they provide capacity to the grid and they are paid a rate less than that of comparable wholesale purchases, saving all rate payers money. "Virtual power plants are a win win for customers and the grid. These batteries are paid for with private capital and are already interconnected and ready for use today. This program will help APS meet the growing demand for electricity in Arizona," said Autumn Johnson, Executive Director of AriSEIA. "Trico already has a VPP and Salt River Project (SRP) just voted to implement one this year. Tucson Electric Power (TEP) plans to propose one in its next rate case. Arizona is moving in the right direction." VPPs are deployed all over the country. There are more than 500 in the US and their capacity is expected to top 60 GW by 2030. According to the US Department of Energy, “VPPs are among the critical solutions to meet the pressing challenges the grid faces today and in the near term to keep electricity rates affordable while maintaining grid reliability and resilience.”[1] According to Brattle, VPPs could save US utilities $15-35 billion in capacity investment over ten years.[2] The full docket can be found here. About AriSEIA AriSEIA is the leading voice of the solar industry in Arizona, dedicated to advancing solar energy through advocacy, education, and collaboration. With a commitment to promoting sustainable energy solutions, AriSEIA serves as a catalyst for the growth and development of Arizona's solar industry. [1] US DOE, Pathways to Commercial Liftoff: Virtual Power Plants 2025 Update, January 2025, available here https://liftoff.energy.gov/wp-content/uploads/2025/01/LIFTOFF_DOE_VirtualPowerPlants2025Update.pdf. [2] Brattle, Real Reliability: The Value of Virtual Power, May 2023, available here https://www.brattle.com/wp-content/uploads/2023/04/Real-Reliability-The-Value-of-Virtual-Power_5.3.2023.pdf. Arizona Corporation Commission
1200 W. Washington Street Phoenix, AZ 85007 RE: Please approve the APS Virtual Power Plant (BYOD) Pilot Program, Docket No. E-01345A-22-0144; Exceptions Dear Chairman and Commissioners, This issue was thoroughly litigated in the last Arizona Public Service (APS) rate case. APS conducted a robust stakeholder process as ordered by the Commission. AriSEIA recommends adoption of the Plan of Administration (POA) as filed. The Grid Needs More Capacity APS is predicting unprecedented load growth over the next decade. To meet this rising need, the utility must aggressively add capacity which, if not done thoughtfully, will put dramatic upward pressure on rates. One way to mitigate that upward rate pressure is to avoid direct utility investments where possible and to leverage customer owned assets to provide services that would otherwise require utility investment and risk increasing ratepayer costs. To this end, the Commission ordered APS to implement the money-saving Bring Your Own Device (BYOD) program (also known as a virtual power plant (VPP)) which uses customer owned batteries to meet peak demand. The evidence in the rate case found that such a program could give APS access to batteries at a cost well below the cost of utility owned storage or market purchases. The Company has projected more than 4,000 MW of new capacity need over the following decade, and its integrated resource plan (IRP) shows that it will be procuring copious amounts of centralized generation and battery storage. APS’ 2024 all source request for proposals (ASRFP) sought at least an additional 2,000 MW of resources by 2030.[1] Residential Batteries Can Provide Capacity The Commission has been discussing this concept since at least 2020. In Decision No. 77855, the Commission ordered APS to “permit the aggregation of distributed demand-side resources [DDSR]… and provide compensation for the value each distributed demand-side resource provides, including, but not limited to, compensation for capacity, demand reduction, load shifting, locational value, voltage support, ancillary and grid services…”[2] In Decision No. 78165, the Commission ordered APS to file a DDSR tariff by May 1, 2022.[3] More than a dozen stakeholder meetings were held just in preparation to the filing of the DDSR tariff.[4] Once the tariff was filed, an entirely new docket was opened; workshops were held; national labs were engaged. That docket resulted in an additional year of work that resulted in the Commission finding APS did not go far enough and directing APS to issue a new RFP for the DDSR aggregation tariff.[5] Also in 2020, Commission Staff recommended approval of APS’ original battery pilot program, which had an upfront incentive for installing batteries. Staff said, “a tariff that compensates customers for the specific benefit their systems bring to the grid can also be beneficial and in the public interest.”[6] Staff characterized such a program as a “forward-looking policy that can benefit all APS ratepayers.”[7] When APS first proposed this pilot, it stated this original pilot would “inform a future potential ‘pay-for-performance’ shared storage program and system planning to ensure continued reliability for APS customers.”[8] APS sought to expand the original battery pilot, which was fully subscribed by January of 2023.[9] APS proposed expanding the battery pilot program in its amended 2023 Demand Side Management (DSM) plan. APS stated, “reallocating DSM budget to support expansion of the Residential Battery Pilot-an already-successful program that APS believes represents the best path forward to achieve the Commission's DDSR goals.”[10] The Commission has not voted on the APS 2023 DSM plan or its 2024 plan in which it also requested expanding the program.[11] APS subsequently closed its battery pilot program because the Commission voted to pursue this VPP program instead in Decision No. 79293. At the February 22, 2024 open meeting in which the 2022 rate case was voted on, Vice Chairman Myers specifically asked Staff and the administrative law judge about their opinions on moving forward with the VPP program. Commission Staff said they have “no concerns moving forward” with the VPP program as was directed in the Recommended Opinion and Order.[12] Judge Harpring said the VPP “would present an opportunity that APS currently lacks that could be a lot more meaningful than APS’ battery pilot” and “I think this is an opportunity. APS needs a lot of dischargeable resources. This would provide a new dischargeable resource and I see that as a positive.”[13] Denying the POA would eliminate all battery pilot programs at APS and would set Arizona back more than five years. That is not an efficient use of taxpayer dollars as the Commission has been pursuing this since 2020 or ratepayer dollars since APS has been working to aggregate demand side resources also since 2020. Another rate case would result in an unnecessary delay of at least two more years. There are more than 500 VPP programs in the US.[14] By 2030, VPPs could reduce peak demand in the US by 60 GW. By 2050, VPPs could grow to more than 200 GW nationwide.[15] According to Brattle, VPPs could save US utilities $15-35 billion in capacity investment over ten years.[16] According to the US Department of Energy, “VPPs are among the critical solutions to meet the pressing challenges the grid faces today and in the near term to keep electricity rates affordable while maintaining grid reliability and resilience.”[17] Salt River Project (SRP) just committed to develop a VPP program by the end of 2025.[18] Residential Batteries Add Capacity For Less Than Market Purchases APS provided the quantity and price of its wholesale market purchases from 2018-2022 in the rate case.[19] An analysis of this data shows that the Company routinely paid in excess of $200/MWh for market purchases, with occasional purchases in excess of $1,000/MWh. AriSEIA/SEIA’s analysis showed that the average weekday market purchase cost between 2019 and 2022 was over $100/MWh between 5 PM and 9 PM, the exact hours the VPP program would target.[20] But if one looks at the actual highest-cost purchases, the avoided energy potential is much higher. AriSEIA/SEIA determined the 500 highest cost hourly purchases throughout the year and then analyzed the purchases that fell in the core summer months of June to September from 2018 through 2022.[21] Even in 2019, which was an outlier in terms of the low quantity of high-cost market energy purchases, the average purchase during the high-cost hours was nearly $400/MWh. In 2021 and 2022 (and likely 2023), the price and quantity of high-cost purchases surged, with the average high-cost hour moving north of $800/MWh. Additionally, at $110/kW per year, the VPP program is less expensive that the cost of utility scale battery storage. The evidence in the hearing showed that the revenue requirement for APS-owned utility-scale batteries costs ratepayers $208/kW per year.[22] AriSEIA originally proposed $150/kW. The valuation in the POA is the result of a compromise derived out of the Commission ordered stakeholder process in Decision No. 79293. Please Adopt the APS POA In Staff’s Memorandum, they correctly assert the numerous benefits that this program can provide to the grid and they correctly state that all of these numerous benefits were discussed at length during the six month stakeholder process, which led to the creation of the POA. It is incongruent to argue that APS does not consider enough of the benefits which would “lower the net cost of the BYOD Program” and “increase the availability of customer incentives” while also stating that the program presents a possible cost shift.[23] Making the program a pilot capped at 5,000 customers was a compromise that the Commission already voted on in Decision No. 79293. Changes to the size of the program are not part of the Commission order to APS or Staff and are outside the scope of the POA. Additionally, the costs of the program are already factored into the per-kW valuation. The payments to participating customers are already reduced to cover the costs of the program. Further, while Staff expresses concerns of a cost shift, they also argue that APS should rate base the VPP program, which would allow APS to collect a return on the VPP program, which would increase costs for everyone. As mentioned above, APS’ first battery pilot was fully subscribed. As of January 31, 2025, APS had more than 4,195 customers with batteries and another 1,250 were in the interconnection pipeline. Given the increase in electricity rates and the decrease in the RCP, most installations will soon be solar plus storage. Further, it is the installers who obtain customer enrollment, not APS or EnergyHub. The installers already have direct relationships with qualifying customers and have a natural incentive to educate customers as to the program. APS’ Cool Rewards program currently has 95,000 enrolled customers, capable of conserving 160 MW of energy.[24] The potential for a battery program is significant. As was directed in Decision No. 79293, APS thoroughly considered the kW versus kWh issue, which was resolved in favor of a program design with a $/kW payment structure. We have no recollection of Staff ever raising this issue in the stakeholder process. As a capacity resource, which is the point of the program, kW are the appropriate metric. This was also discussed at length in the rate case testimony. Staff states that, “given the increasing demand for electricity in Arizona, Staff recognizes the importance of leveraging existing capacity resources and supports the advancement of technologies.”[25] We agree. According to APS, “APS resource planners expect peak customer demand to grow to more than 13,000 MW by 2038. For perspective, it took APS 140 years to reach 8,200 MW of peak demand, and customer needs will increase by 60% in only 14 years.”[26] The Commission has been discussing this concept for five years and this exact program for two years. Additional delay is unwarranted and needlessly limits capacity resources that are already available today at a time when we are experiencing significant load growth at a price less expensive than the alternative. As Staff correctly points out “APS was ordered to meet with other interested parties to collaboratively reach an agreement on the language of the BYOD POA.”[27] And against all odds, APS has done just that. Please approve the POA as drafted. AriSEIA has attached AriSEIA Proposed Amendment 1 to modify Staff’s draft order to approve the POA. Respectfully, Autumn T. Johnson Executive Director AriSEIA (520) 240-4757 [email protected] [1] APS 2024 ASRFP, available here https://www.aps.com/en/About/Our-Company/Doing-Business-with-Us/Resource-Planning/Request-for-Proposals. [2] ACC Decision No. 77855, Docket No. E-01345A-19-0148, available here https://docket.images.azcc.gov/0000202797.pdf?i=1741200024102. [3] ACC Decision No. 78165, Docket No. E-01345A-19-0148, available here https://docket.images.azcc.gov/0000204280.pdf?i=1741200631832. [4] APS DDSR Tariff, June 1, 2022, Docket No. E-01345A-22-0143, available here https://docket.images.azcc.gov/E000019505.pdf?i=1741200030297. [5] ACC Decision No. 78878, March 16, 2023, Docket No. E-01345A-22-0143, available here https://docket.images.azcc.gov/0000208710.pdf?i=1741200030297. [6] ACC Decision No. 77762, Docket No. E-01345A-19-0148, available here https://docket.images.azcc.gov/0000202207.pdf?i=1741200977874. [7] Id. [8] APS Supplemental to the 2020 RES Plan, August 26, 2020, Docket No. E-01345A-19-0148, available here https://docket.images.azcc.gov/E000008576.pdf?i=1741203415780. [9] APS 2023 Demand Side Management Annual Progress Report, March 1, 2024, Docket No. E-00000U-18-0055, available here https://docket.images.azcc.gov/E000034300.pdf?i=1741300652460. [10] APS Amended 2023 DSM Implementation Plan, May 31, 2023, Docket No. E-01345A-22-0066, available here https://docket.images.azcc.gov/E000027360.pdf?i=1741300107475. [11] APS 2024 DSM Plan, November 30, 2023, Docket No. E-01345A-23-0088, available here https://docket.images.azcc.gov/E000032472.pdf?i=1741374160495. [12] February 22, 2024 Open Meeting at 7:21:00. [13] Id. [14] Utility Dive, US VPPs Can Meet Summer Demand Peaks Faster, Cheaper Than New Generation and Transmission, July 10, 2024, available here https://www.utilitydive.com/news/us-vpps-can-meet-summer-demand-peaks-faster-cheaper-than-new-generation-an/721024/. [15] RMI, Virtual Power Plants, Real Benefits, January 2023, available here https://rmi.org/insight/virtual-power-plants-real-benefits/. Attachment A [16] Brattle, Real Reliability: The Value of Virtual Power, May 2023, available here https://www.brattle.com/wp-content/uploads/2023/04/Real-Reliability-The-Value-of-Virtual-Power_5.3.2023.pdf. Attachment B [17] US DOE, Pathways to Commercial Liftoff: Virtual Power Plants 2025 Update, January 2025, available here https://liftoff.energy.gov/wp-content/uploads/2025/01/LIFTOFF_DOE_VirtualPowerPlants2025Update.pdf. Attachment C [18] SRP, Board of Directors Approves Pricing Proposal, February 27, 2025, available here https://media.srpnet.com/srp-board-of-directors-approves-pricing-proposal/. [19] AriSEIA 4.03_ExcelAPS22RC03362_Hourly Market Purchases 2018-2022 [20] Lucas Direct at 59. [21] This is twice as many as are allowed in the BYOD program, which authorizes 60 event days with events up to 4 hours. [22] See Kevin Lucas in hearing test. Sept. 1, 2023 at 00:04:31. [23] Utilities Division Memorandum, February 26, 2025, Docket No. E-01345A-22-0144, available here https://docket.images.azcc.gov/E000041768.pdf. [24] APS Customers Served with Reliable Power During Record-Breaking Heat, October 7, 2024, available here https://www.aps.com/en/About/Our-Company/Newsroom/Articles/APS_Customers_Served_With_Reliable_Power_During_Record-Breaking_Heat#:~:text=APS%20Cool%20Rewards%20acts%20like,small%20power%20plant%20would%20produce. [25] Utilities Division Memorandum, February 26, 2025, Docket No. E-01345A-22-0144, available here https://docket.images.azcc.gov/E000041768.pdf. [26] APS Secures its Largest-Ever Energy Supply to Reliably Serve Customers, November 20, 2024, available here https://www.aps.com/en/About/Our-Company/Newsroom/Articles/APS_Secures_its_Largest-Ever_Energy_Supply_to_Reliably_Serve_Customers#:~:text=APS%20resource%20planners%20expect%20peak,is%20conducting%20a%202024%20ASRFP. [27] Utilities Division Memorandum, February 26, 2025, Docket No. E-01345A-22-0144, available here https://docket.images.azcc.gov/E000041768.pdf. Both Trico and SSVEC have proposed numerous anti-solar positions in their pending rate cases, including ending net metering for commercial solar customers, introducing new fees for solar customers, and ongoing export rate problems. AriSEIA has intervened to advocate on behalf of solar customers and installers.
APS has been charging a punitive and discriminatory fee against residential rooftop solar customers for almost a year and AriSEIA has been fighting it every step of the way. Today we joined with the Solar Energy Industries Association and two individual ratepayers in filing for an appeal with the Arizona Court of Appeals.
AriSEIA filed for reconsideration/rehearing today on the APS grid access charge and "legacy adjustment." These are two charges that uniquely punish solar customers for using less power from APS. The fee is currently ~$2.50 a month per customer, but APS has said it should be $88 a month per customer and the ACC has ordered them to increase it in their next rate case, which they plan to file this year. Applying for rehearing is a necessary step towards appealing to the Arizona Court of Appeals, which we plan to do on January 30th.
Arizona Corporation Commission Upholds APS’ Punitive and Discriminatory Fee on Rooftop Solar12/17/2024 FOR IMMEDIATE RELEASE
Contact: Autumn Johnson 520-240-4757 [email protected] Phoenix, AZ: Today, the Arizona Corporation Commission (ACC) voted to uphold a fee on all Arizona Public Service (APS) solar customers. APS has nearly 200,000 solar customers, all of whom are paying 15% more than the rate increase approved for all residential customers this year. The ACC upheld the fees after granting a rehearing on this issue at the request of AriSEIA, Vote Solar, and the Arizona Attorney General’s Office. The ACC refused to consider key evidence in the record. In January, the ACC surprised stakeholders by inserting a “grid access charge” into APS’ nearly completed rate case. AriSEIA argued the fee should be removed from the rate case decision, which was unheeded by the ACC. Therefore, AriSEIA and others immediately filed for reconsideration/rehearing, which was granted. After nearly a year of litigation, the ACC upheld the original decision after a number of abnormalities in the execution of the case, such as constraining the evidence to be considered, moving the hearing earlier after APS requested more time for adequate customer notice, an abbreviated briefing scheduled, and then scheduling the vote before the recommendation was even written. AriSEIA demonstrated at the hearing that based on a quantitative analysis of several national expert witnesses, APS had miscalculated the cost of service to solar customers. That miscalculation reflected that solar customers were not paying their fair share, when in fact, the inverse is true. Solar customers pay more than they should and actually subsidize non-solar customers. APS testified that if the ACC eliminated the solar fees, the difference would be $.25 to residential customers. Despite the evidence, the ACC will penalize solar customers several dollars per month and approved an amendment to increase it in APS’ next rate case, which is anticipated to be filed in 2025. “The evidentiary record makes it clear that solar customers are subsidizing non-solar customers and yet APS and the ACC continue to penalize solar customers with unfounded and discriminatory fees,” said Autumn Johnson, executive director of AriSEIA. An appeal to the Arizona Court of Appeals is likely in 2025. |
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The Arizona Solar Energy Industries Association (AriSEIA) is a 501(c)(6) non-profit trade association representing the solar, storage, and electrification industry, solar-friendly businesses, and others interested in advancing complementary technologies in Arizona. The group's focus is on education, professionalism and promotion of public policies that support deployment of solar, storage, and electrification technologies and renewable energy job growth and creation. |
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