Rate Order Incentivizes New Battery Storage, Distributed Generation Options

The Arizona Corporation Commission has accepted, as modified, a proposed rate settlement under which the electric utility applicant, Arizona Public Service Company (APS), was awarded a net base rate increase of $94.624 million out of a requested $165.9 million in rate relief. 

The commission found that in addition to the obvious benefit of a much lower increase than that sought by APS, the stipulation offered several other significant benefits as well, including the following: 

1. expanded rate options for residential customers, such as time-of-use (TOU) rates with additional nonpeak hours and days; 
2. a stay-out provision that precludes APS from seeking another base rate increase prior to June 1, 2019; 
3. a pilot program designed to encourage customers to adopt technologies for better managing and controlling demand and reducing system peak usage; 
4. further assistance for qualifying low-income customers; and 
5. continuation of a "buythrough" program for industrial customers. 

The commission stated that while many of the rate agreement's terms were reasonable overall, it wanted to see more innovation with respect to costsaving measures, environmental protections, and technological advances. It therefore directed that the settlement be amended so as to focus on creating incentives for more forwardlooking strategies. In particular, it set its sights on battery storage opportunities, including development of a new optional "storage-friendly" rate for businesses and large-volume users. 

The commission maintained that by eliminating the demand ratchet, off-peak demand charge, and declining block demand charge currently included in the company's TOU tariffs, the new optional rate would encourage growth in battery storage use. The commission contended that various safeguards and restrictions it had added to the optional storagefriendly rate should help avoid any negative unintended consequences and ensure smooth and meaningful implementation of the optional tariff. 

Providing more specifics on the utility's new optional TOU storage program for large general service customers, the commission said that the offering will be capped at a total peak demand of 35,000 kilowatts for installed systems and active interconnection applications, with the program being available on a first-come, first-served basis. The commission stated that once 70% of the initial program capacity has been subscribed, and if such threshold has been reached prior to the company's next general rate case filing, APS may evaluate whether the costs of the program are less than the system benefits therefrom. 

The commission remarked that eligibility for the optional tariff depends on a customer's installation of a chemical, mechanical, or thermal energy storage system that is capable of allowing the customer to offset a minimum of 20% of measured peak demand during the on-peak period. It added that in order to qualify for the program where a power-producing facility is installed, inverters must be capable of and configured to provide "volt ampere reactive" support, so that a near-unity power factor of at least 95% is maintained during operation. 

The commission deemed appropriate those parts of the proffered settlement that extend supportive measures to customers with distributed generation (DG) systems. The commission commented that DG customers now will become eligible for four different rate schedules, including all proposed TOU and demand rates. 

In addition, the commission observed, any DG customer that files a completed interconnection application before the rate-effective date in the case will be grandfathered in for a period of 20 years, with that 20- year time frame calculated from the date the system is interconnected with APS. 

The commission ruled that grandfathered DG customers may continue to take service and be netmetered under full retail rates. That is, they will be able to take service according to their current tariff schedule for the duration of the grandfathering period. As to cost of capital, the commission reported that the settling parties had adopted a capital structure comprised of 44.2% debt and 55.8% common equity. 

They further reached consensus on a return on common equity of 10.0% and an embedded cost of debt of 5.13%. The commission estimated that the billing impact on the average residential customer would be an increase of about 4.54%, which equates to a monthly increase of around $6.00. The utility operates in 11 of the state's 15 counties, making it the largest electric service provider in Arizona. 

It is the largest subsidiary of Pinnacle West Capital Corporation, serving more than 1.2 million customers. Re Arizona Public Service Co., Docket Nos. E-01345A- 16-0036, E-01345A-16-0123, Decision No. 76295, Aug. 18, 2017 (Ariz.C.C.).