0130 1 iiiiii 11 Control Number: 48023

MI Hifi Item Number: 36

Addendum StartPage: 0 PROJECT NO. 48023

RULEMAKING TO ADDRESS THE USE § zola NOY -2 PM 2: 37 OF NON-TRADITIONAL PUBLIC UTILITY FiLING CLERK TECHNOLOGIES IN ELECTRIC OF DELIVERY SERVICE

NRG ENERGY, INC. COMMENTS ON THE QUESTIONS REGARDING THE USE OF NON-TRADITIONAL TECHNOLOGIES IN ELECTRIC DELIVERY SERVICE

I. Introduction

NRG Texas Power LLC, NRG Power Marketing LLC, Reliant Energy Retail Services LLC, Green Mountain Energy Company, US Retailers LLC, and NRG Curtailment Solutions LLC — all wholly owned subsidiaries of NRG Energy, Inc. (collectively NRG) appreciate the opportunity to respond to the Public Utility Commission of Texas (Commission) Staff questions filed October 2, 2018 in PUC Project No. 48023, Rulemaking to Address the Use of Non- Traditional Technologies in Electric Delivery Service.

NRG supports reasonable Transmission and Distribution Utility (TDU) investment to maintain a secure and reliable grid. However, TDU investment in "non-traditional technologies" that undermine the structural separation underlying the ERCOT competitive wholesale and retail markets must be rejected. Competition in the wholesale and retail markets drives innovation and efficiency, empowers customers with choices, and shifts investment risk from customers to investors. Permitting TDU ownership of resources that provide competitive services erodes the structural bright line established in Senate Bill 7 and walks back 20 years of competitive market progress in Texas. Moreover, allowing TDUs to rate base these investments means that customers are held captive to the financial obligations of utility ownership even when a more efficient option may be available. Competitive providers are bringing to life the new energy technologies that customers are increasingly demanding. Allowing these technologies to be rate based funded will stunt and hinder further development, to the detriment of the customer and market as a whole. We know the competitive market model works because we have seen it work successfully in Texas. NRG markets and offers products to customers that include , small scale solar, , and energy storage through the competitive market. Since the opening of the competitive ERCOT market in 2002, Texas has seen more than 115 Retail Electric Providers (REPs)1 become certificated and more than 47,000 megawatts2 of new capacity development. This progress should not be undermined by TDU encroachment into competitive service offerings, including, but not limited to, energy storage.

II. Responses to Commission Questions

1. Apart from energy storage, what non-traditional technologies could provide a potential cost-effective solution to reliability issues on a utility's transmission or distribution system?

Generally, alternatives to traditional transmission and distribution solutions include distributed generation (including energy storage), energy efficiency, demand response, and controls to change load. These technologies may defer or replace specific equipment upgrades including transmission and distribution lines, substations, and transformers. The key to implementation of these resources as a cost-effective solution is designing successful markets that incentivize customers or investors to resolve reliability issues. Unfortunately ERCOT market participants do not currently receive a market signal to site resources at a specific location on the distribution system to resolve loading or reliability issues. If consistent market signals were provided, private investment in resources that could resolve reliability issues would be incentivized. Alternatively, a TDU could facilitate the development of targeted energy efficiency programs, using existing energy efficiency funding, to create incentives for investment in specific locations. TDUs could also publish reliability indices (SAIFI, SAIDI, CAIFI, CAIDI, MAIFI) by distribution circuit so non-utility companies can market to appropriate areas to resolve the reliability issue.

2. Can a transmission and distribution utility (TDU) legally own a non-traditional technology device, including energy storage equipment and facilities, to support reliability on its system, without a specific exemption in the Public Utility Regulatory Act? If so, under what legal authority could a TDU own such a device?

No, TDUs are prohibited from the ownership or operation of energy storage facilities. The legal issues pertaining to the limitations of TDU ownership of generation assets, including batteries, were thoroughly briefed in Docket No. 46368, Application of AEP Texas North

See Public Utility Commission of Texas, Numeric Directory of Retail Electric Providers: Active REPs, ctvailable at http://www.puc.texas.gov/industry/electric/directories/rep/numeric_rep.aspx (last visited Oct. 31, 2018). 2 May 2018 CDR- filtered on Installed capacity since 2002

2 Company for Regulatory Approvals Related to the Installation of Utility-Scale Battery Facilities, and are unfortunately likely to be re-litigated in this project. In Docket No. 46386 REPs, power generation companies (PGCs), large commercial and industrial customers, an electric cooperative, the Office of Public Utility Counsel (OPUC), and Commission Staff all agreed that as a matter of law TDUs are prohibited from ownership of batteries. First, ownership of energy storage constitutes the provision of a competitive energy service by a TDU in violation of 16 Texas Administrative Code (TAC) §§ 25.341(3) and 25.343(c). Second, ownership and operation of a battery storage facility violates the post-unbundling Public Utility Regulatory Act (PURA) § 39.105(a) prohibition against a TDU's sale of electricity or participation in the market for electricity. Third, PURA § 35.152(a) defines electric energy storage facilities as "generation assets. "

3. How should any energy necessary for TDU implementation of a non-traditional technology device be measured and accounted for within the ERCOT market, without using Unaccounted for Energy (UFE)?

The ERCOT market provides two mechanisms for accounting and settlement of energy usage: metering a specific point of delivery for its own usage or uplift of unmetered usage through UFE. In the case of metering, PURA § 39.105(a) states "a transmission and distribution utility may not sell electricity or otherwise participate in the market for electricity except for the purpose of buying electricity to serve its own needs."3 A TDU metering usage to charge and discharge energy from a non-traditional technology such as a battery constitutes participation in the market for electricity, contrary to PURA.

4. In which situations and scenarios would it be appropriate for a TDU to deploy a non- traditional technology device for the purpose of supporting reliability on its transmission or distribution system?

NRG supports exploring the situations and scenarios for deployment of non-traditional technologies especially in instances where deployment could result in savings to transmission and distribution costs. However, as a bright line, whatever a "non-traditional technology device" is, it should maintain the integrity of the current rule structure and in no way impact the competitive wholesale and retail markets. A TDU should not be permitted to own generation including batteries or serve as a retail electric provider.

3 Public Utility Regulatory Act § 39.105(a).

3 5. Should a Certificate of Convenience and Necessity (CCN) or other commission pre- approval process be required before the construction or procurement of utility owned devices that use non-traditional technologies to support reliability on the transmission or distribution system? If so, what criteria would be appropriate for pre-approval of such devices and why? Should such a pre-approval process only apply for a limited time?

Commission pre-approval of non-traditional technologies should be required as a precondition before procurement. This will protect consumers from unjust and imprudent costs appearing in rate base. Neither the Transmission Cost Recovery Factor (TCRF) nor Distribution Cost Recovery Factor (DCRF) process includes a thorough review of need or prudency prior to inclusion in rates. The DCRF rule defines "distributioe invested "capitar as the portion of the electric utility's invested capital categorized as distribution plant that is "properly recorded" in specific Federal Energy Regulatory Commission (FERC) accounts relating to distribution.4 Under the rule, distribution invested capital includes only costs "that comply with PURA," among other requirements, and does not include generation-related costs or transmission-related costs.5 Without a pre-approval process, non-traditional technologies that do not comport with PURA, like batteries, might enter rate base years before a prudency review.6 To ensure that the cost was properly recorded and complies with PURA, the Commission's prudence evaluation should happen in a CCN or similar process prior to procurement.

Basic criteria for Commission review and pre-approval of non-traditional technologies include: • Is the technology a legal technology for the TDU to own or operate? • Is the technology cost effective compared to a traditional asset? • What are the criteria to compare cost effectiveness when assets have different useful lives and depreciation schedules? • Are the impacts to the retail and wholesale market mitigated?

4 16 Tex. Admin. Code § 25.243. 5 Id 6 Id at § 25.243(e)(5) (TAC) ("Nhe issues of whether distribution invested capital included in an application for a DCRF or DCRF adjustment complies with PURA, including §36.053 and §36.058, and is prudent, reasonable, and necessary shall not be addressed in a DCRF proceeding unless the presiding officer finds that good cause exists to address these issues") (emphasis added). See also 16 TAC § 25.192(h)(2) (costs that are unreasonable or unnecessary but included in an interim TCOS update would not be reconciled until the TSPs next TCOS application).

4 NRG does not recommend a sunset date for pre-approval at this time, especially because the PUC may amend its rules if experience renders some forms of non-traditional technology to be uncontroversial after time.

6. Should the commission's rules permit or require a TDU to contract with a non-utility service provider for the provision of a non-traditional technology device to support reliability on the TDU's transmission or distribution system? If so, what parameters should the commission stipulate for this arrangement?

Contracting with a non-utility service provider for ownership and operation of a non- traditional technology device such as a battery is an end-run around utility ownership and would undermine the competitive market in Texas. The funding of the technology would still occur through captive ratepayers regardless of whether the utility owns it or purchases it from a third party. That equates to subsidized supply that other market participants must compete with. Additionally, this proposal would have the utility selecting "winners," rather than competitive market forces shaping the supply of these competitive services. If there are specific reliability services the TDU is attempting to achieve that can best be resolved using a non-traditional technology then the service attributes should be defined and a market for services should be created by ERCOT regardless of whether the service can be provided by a battery, some other form of generation, or another non-traditional technology. This concept is similar to how ERCOT has created an ancillary service market for reserve generation and fast frequency response as proposed in NPRR863. The benefit of creating a market is that it shifts risk to the entities participating in the market and incentivizes innovation whereas a long-term contract for "reliability services" shifts risk to rate-payers.

7. If the commission were to adopt a policy of permitting a TDU to procure a non- traditional technology device for the purposes of supporting reliability on the TDU's transmission or distribution system, what potential effects would such a policy have on ERCOT wholesale market outcomes, and especially price formation, in the ERCOT market? What potential effects might such a policy have on the competitive retail market, if any?

TDU procurement and dispatch of batteries undermines the competitive ERCOT wholesale market by distorting price signals and subsidizing investments in projects that impact supply and demand fundamentals. The ERCOT market relies on price signals to inform asset owners and developers whether new generation should be built and if existing generation should

5 continue to operate in the market. Rate based energy storage would undermine the effectiveness of those price signals and would compete directly with investor owned generation by subsidizing the entry of new resources. This would fundamentally disrupt the investment prospects for the ERCOT wholesale market. If the Commission allowed the subsidization of these resources, to mitigate the impacts on the wholesale market, price adjustments would need to occur to account for the charging and discharging of the batteries. NRG is unclear as to whether the capacity from battery charging and discharging could be measured accurately enough to be included in the price adjustment mechanism (i.e. reliability deployment adders). The net effect of these price corrections would be that customers would likely pay twice — first, for the storage assets included in rate base, and second for the distortion and subsequent price corrections in the wholesale market. This does not represent a sound outcome.

Similar to the impacts to the wholesale market, utility funded energy storage would stall investment and the progress REPs are making in offering energy storage solutions to customers through the retail market. Other potential effects on the retail market include: uncertainty and inability to hedge uplift related to UFE (if UFE is permitted as a settlement mechanism), likely increased transmission and distribution costs as utilities seek to "hardee their systems with massive investment in "storage for reliability," and reduction in the number of suppliers as generation owners with peaking assets may exit the market.

8. What market-based alternatives exist, if any, to address reliability issues on a TDU's transmission or distribution system?

NRG suggests the specific "reliability issues" be clearly defined before determining what market-based alternatives could resolve the issue. Customers pay for reliability services and back-up generation in the competitive market today. NRG encourages the Commission to evaluate whether the reliability standards that utilities must meet justify the economic value customers place on those services. If the customers do not demand such a level of reliability, then why are utilities forced to provide (and customers forced to pay for) a service that customers do not want? If the customer actually values the level of reliability, the customer will purchase the service from the competitive market, like they do today.

6 9. How could a vertically integrated investor-owned utility maximize the value of an energy storage device without adversely affecting wholesale market outcomes and price formation in its respective market?

Vertically integrated investor-owned utilities are monopoly utilities that own all aspects of electric delivery including: generation, transmission and distribution, and the customer billing functions. Given this ownership structure there is generally not a robust wholesale market where price formation is critical to support investment. In a vertically integrated market, regulation is substituted for competition. The vertically integrated model works to "maximize the value of an energy storage device" only because the monopoly utility is indifferent to whether the energy storage device is booked as a generation or transmission or distribution asset, so long as it is booked as invested capital through which it can earn a rate of return. Same for limited exceptions for NOIE's, the ERCOT market is not a vertically integrated model. In fact, much of the success of the ERCOT market is based on the unbundled market structure mandated by Senate Bill 7, which precludes a regulated monopoly from participating in the competitive electric markets in ERCOT.

10. What impediments exist to using non-traditional technology devices on utility transmission or distribution systems?

The main impediment to utility use of non-traditional technologies is the non- legality of utility ownership. Utility ownership of energy storage devices without a specific PURA waiver is prohibited. Economics is the only impediment to non-traditional technology being provided by the competitive market. Once prices dictate value or a customer seeks such technology, competitive providers will invest.

11. Could the commission specify conditions under which a TDU could employ non- traditional technologies to support reliability? If so, what conditions would be appropriate?

No, without a specific waiver in PURA, TDU ownership of batteries is prohibited.

12. If you are a utility, please provide a detailed overview of any batteries or other energy storage technologies on your transmission and distribution system in the state of Texas

7 that are either currently operational or planned to be operational. Please explain the purpose, use, metering, and deployment of these technologies.

NRG notes that end use customers and PGCs own and operate batteries on transmission and distribution systems. As of September 2018 there are at least 89 MWs7 of interconnected batteries and 1,889 MWs in the ERCOT generation interconnection process.8 Metering arrangements for these resources differ depending on whether the battery is transmission interconnected or distribution interconnected. Applications for the batteries also vary and include participation in ERCOT Ancillary Service Markets like regulation, load reduction during high priced or 4CP periods, and firming output from intermittent resources like solar.

13. Are there any other issues that the commission should consider addressing in this project? NRG does not have any additional issues for consideration at this time.

Respectfully submitted,

Bryan Sams (-it ...-( Director, Regulatory Affairs estiav.A.ATrt•cw.) NRG Energy, Inc. 1005 Congress, Suite 950 Austin, TX 78701 (512) 691-6126

7 ERCOT, Capacity Changes by Fuel Type Charts (Sept. 30, 2018), http://www.ercot.com/content/wcmilists/162615/Capacity_Changes_by_Fuel_Type_Charts_September_2018.xlsx. 8 ERCOT, GIS Report (Sept. 2018), http://www.ercot.com/content/wcm/lists/143978/GIS_Report September_2018.xlsx.

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