4. Preliminary Scoping Memo

The general scope of this proceeding is to consider further actions, if needed, to comply with the requirements of EISA and also to consider policy and performance guidelines to enable the electric utilities to develop and implement a smart grid system in California.

4.1. Issues to be Addressed

4.1.1. Obligation to Consider Smart Grid Investments and Information Access

4.1.1.1. PURPA § 111(d)(16), Consideration of Smart Grid Investment

As cited above, PURPA § 111(d)(16)(A) added by EISA § 1307(a) requires a state commission to consider whether to require an electric utility to make certain demonstrations prior to undertaking investments in nonadvanced grid technologies. In addition, PURPA § 111(d)(16)(B) requires that states consider authorizing utilities to recover smart grid investments and costs through rates, including a reasonable rate of return on capital expenditures for the deployment of a qualified smart grid system. Furthermore, PURPA § 111(d)(16)(C) requires that states consider authorizing utilities to recover the remaining book-value costs of equipment rendered obsolete by the deployment of a smart grid system.

We note that this Commission, through its AMI proceedings A.05-03-016 and A.05-06-028 (Pacific Gas and Electric Company); A.05-03-026, A.06-12-026, and A.07-07-026 (Southern California Edison Company); and A.05-03-015 (San Diego Gas & Electric Company)) has already addressed some aspects of these requirements.

EISA does not define what constitutes a "qualified smart grid system" for the purposes of State consideration of smart grid investments. However, as cited above, §§ 1301 and 1306(d) of EISA provide requirements that a smart grid must meet. We note further that EISA § 1306(b) (contained in Attachment A to this OIR) provides standards for smart grid investment costs to be eligible for federal matching funds, with EISA § 1306(c) specifying investments that would not qualify for federal matching funds. Thus, questions arise as to how the Commission should define "smart grid" and "qualified smart grid system" and whether the requirements listed in the statute are adequate for our purposes. In particular, we wish to consider whether any grid that has any or all of the characteristics cited in EISA § 1301 and performs any or all of the functions cited in EISA § 1306(d) is "smart" and whether the treatment suggested in PURPA § 111(d)(16) added by EISA § 1307(a) should be considered for investments that meet the standards in EISA § 1306(b), excluding investments specified in EISA § 1306(c).

4.1.1.2. PURPA § 111(d)(17), Smart Grid Information

EISA § 1307(a) added paragraph (17) to PURPA § 111(d), which contains a new federal standard for the information that smart grid providers must provide to electricity purchasers and other interested persons, and the types of access that must be provided to this information. The standard specifies a broad range of information that must be made available. In the questions below, we ask whether the Commission should implement this standard, and we explore the extent to which each California utility already is complying with the standard.

4.1.2. Policies, Standards, and Protocols for a
Smart Grid System

We believe that it is important to set policies to ensure functionality and interoperability with technologies such as distributed generation, plug-in hybrid and electric vehicles, and distributed storage. The vision of a smart grid should lead to interoperability of the entire electric grid, from the generation side to the customer's home area network devices and the exchange of integrated advanced intelligence that provides the information necessary to optimize electric services and empower customers to make informed energy decisions. For instance, a smart grid system should help facilitate the use of additional distributed generation and help encourage other non-traditional generation such as combined heat and power systems, and plug-in hybrid and electric vehicles.

To this end, we seek to achieve the following in this rulemaking:

    · Consider the principles and criteria that should guide the Commission's smart grid policies;

    · Address the specific provisions of EISA that relate to smart grid investments and information;

    · Determine the characteristics and requirements of a smart grid in California that would support existing policies;

    · Identify the IOUs' existing activities and investments related to a smart grid;

    · Consider whether standards and protocols are needed for the deployment of a smart grid in California and, if so, identify what the Commission's role should be in standards development, if any;

    · Determine how the Commission should assess the costs and benefits of smart grid-related expenditures that may be necessary to meet the state's future needs;

    · Develop an appropriate regulatory approach to support the development of a cost-effective smart grid in California;

    · Address other issues as needed to guide Commission policy in this area.

4.1.3. Questions

To address the issues delineated above, we pose the following questions for all interested parties to comment on.

1. Does the following list include the appropriate principles and criteria to guide the Commission's decisions in this proceeding regarding the possible development of a smart grid in California? Explain any modifications you propose.

· Interoperability of a smart grid system with non-traditional as well as traditional generation;

· Interoperability of a smart grid with current and future investments in infrastructure, including advanced metering protocols;

· Ability to enable distribution and transmission automation, e.g., be self-healing and adaptive;

· Ability to reduce overall usage (especially peak usage) because it will be interactive and price responsive, and

· Maintenance of system security and reliability.

2. Should the Commission require that, prior to undertaking investments in non-advanced grid technologies, an electric utility demonstrate to the Commission that the electric utility considered an investment in a qualified smart grid system, pursuant to PURPA § 111(d)(16)(A) added by EISA § 1307(a)?

3. Should the Commission authorize each electric utility to recover from ratepayers any capital, operating expenditure, or other costs of the electric utility relating to the deployment of a qualified smart grid system, including a reasonable rate of return on the capital expenditures of the electric utility for the deployment of a qualified smart grid system, pursuant to PURPA § 111(d)(16)(B) added by EISA § 1307(a)?

4. Should the Commission authorize any electric utility or other party deploying a qualified smart grid system to recover in a timely manner the remaining book-value costs of any equipment rendered obsolete by the deployment of a qualified smart grid system, based on the remaining depreciable life of the obsolete equipment, pursuant to PURPA § 111(d)(16)(C) added by EISA § 1307(a)?

5. For purposes of the preceding three questions, how should "qualified smart grid system" be defined? Should any grid that has some or all of the characteristics cited in EISA § 1301 and performs some or all of the functions cited in EISA § 1306(d) be classified as a "qualified smart grid system"?

6. How should investments and other costs of a qualified smart grid system be determined for purposes of considering recovery from ratepayers? In particular, should the investment standards in EISA § 1306(b), excluding investments specified in EISA § 1306(c), be used to determine investments in qualified smart grid systems that may warrant ratepayer recovery?

7. Should the Commission implement the standard regarding smart grid information contained in PURPA § 111(d)(17) added by EISA § 1307(a)?

8. Is each California utility complying with the standard for the information that electricity providers must provide to electricity purchasers and other interested persons pursuant to PURPA § 111(d)(17) added by EISA § 1307(a)? If not, which part(s) of the standard is each utility not complying with and what efforts are underway to comply with the standard? If a utility is complying, please provide further details on how the utility complies.

9. What should the characteristics or requirements be for a California smart grid? Should they be the same as those established for a "qualified smart grid system"? (See Question 5 above.)

10. How could a smart grid system in California affect the following areas of concern?

a. Increase energy conservation and energy efficiency;

11. What progress has each utility made toward establishing a smart grid? In answering this question, please provide details on progress related to each of the ten characteristics identified in EISA § 1301 and repeated below:

a. Increased use of digital information and controls technology to improve reliability, security, and efficiency of the electric grid.

b. Dynamic optimization of grid operations and resources, with full cyber-security.

c. Deployment and integration of distributed resources and generation, including renewable resources.

d. Development and incorporation of demand response, demand-side resources, and energy-efficiency resources.

e. Deployment of ``smart'' technologies (real-time, automated, interactive technologies that optimize the physical operation of appliances and consumer devices) for metering, communications concerning grid operations and status, and distribution automation.

f. Integration of ``smart'' appliances and consumer devices.

g. Deployment and integration of advanced electricity storage and peak-shaving technologies, including plug-in electric and hybrid electric vehicles, and thermal-storage air conditioning.

h. Provision to consumers of timely information and control options.

i. Development of standards for communication and interoperability of appliances and equipment connected to the electric grid, including the infrastructure serving the grid.

j. Identification and lowering of unreasonable or unnecessary barriers to adoption of smart grid technologies, practices, and services.

12. Are standards needed as part of a smart grid? If so, in what areas are standards needed to integrate components into the grid, e.g., interoperability standards for distributed generation, distributed storage, plug-in hybrid and electric vehicles, home area networks, in-home displays, energy management systems, etc.?

13. For each type of standard that is needed please answer the following:

a. Who should issue the standards, e.g., the National Institute of Standards and Technology, American National Standards Institute, Institute of Electrical and Electronics Engineers, and/or the Commission?

b. What standard-making processes are already underway?

c. What is or should be the role of the California utilities in the standards-making process?

14. What specific standards, if any, should the Commission adopt in this proceeding, and why? What type of standards should the Commission avoid because they risk obsolescence or might lead to unnecessary costs?

15. What types of standards should be common across California utility service territories? Do characteristics of each utility's transmission and distribution system (e.g., different mix of overhead versus underground wires) suggest that some types of standards are unnecessary?

16. What type of standards or protections, if any, are needed to allow secure access by approved market participants or third parties, such as Electric Service Providers or demand response aggregators? Would "guidance" work in lieu of standards?

17. Given the IOUs' existing transmission and distribution infrastructure and policy programs, to what extent will incremental investments be required in additional smart grid technologies?

18. How should the Commission assess the cost-effectiveness and reasonableness of smart grid-related expenditures?

19. What types of costs would be associated with deploying a smart grid?

20. How should any smart grid upgrades that are approved by the Commission be staged over a reasonable time horizon that mitigates rate impacts?

21. Should smart grid-related costs be borne by ratepayers, shareholders, or third parties?

22. What types of benefits would result from a smart grid? Which benefits can be easily quantified, and how? Which benefits are difficult to quantify, and how should they be addressed?

23. How should a competitive bidding process for IOU investments in smart grid technology be structured and monitored? Are existing competitive procurement processes sufficient?

24. How should a smart grid be deployed? What should a utility do in order to successfully deploy smart grid technology?

25. What type of regulatory approach should the Commission take to support the development of a cost-effective smart grid?

26. What, if any, regulatory barriers to the deployment of a smart grid should the Commission address?

27. If the Commission requires the utilities to develop smart grid deployment plans, what should those plans consist of?

28. What milestones should the Commission use to measure the utilities' progress toward the development of a smart grid?

Other Questions

29. How should a smart grid interact with the operation of the transmission system and wholesale market? What is the role of the CAISO relative to a smart grid?

30. Will deployment of a smart grid further the State's Assembly Bill 32 greenhouse gas reduction goals? If so, how?

31. How will deployment of a smart grid system impact the Commission's Planning Reserve Margins? Will a smart grid system impact the amount and type of generation necessary to meet peak demand? Off peak demand?

32. What other smart grid-related issues should the Commission address in this proceeding?

4.2. Schedule and Initial Comments

The schedule for this proceeding is stated below in Table 1:

Table 1

December 18, 2008

Issuance of Order Instituting Rulemaking.

February 9, 2009

Responses addressing scope, schedule, and other procedural issues and responding to the questions above to be filed with the Commission.

March 9, 2009

Replies to initial responses filed with the Commission.

In addition to comments responding to the questions above, workshops will be needed to establish a thorough record. For organizational reasons we propose that the workshops be divided into four distinct areas that make up a smart grid system:

Following the receipt of responses and replies, we anticipate holding a prehearing conference (PHC). At the PHC, we will address scope and scheduling issues including whether and, if so, how, this rulemaking should be divided into phases. For example, Phase I could deal with complying with federal legislation as well as establishing overarching policies for a smart grid system, while Phase II could establish specific standards and protocols to guide utilities toward building a cost effective and interoperable smart grid system. In addition to the questions identified above, parties may address any scope and scheduling concerns in their comments and reply comments. After the PHC, the assigned Commissioner will issue a ruling refining the scope and procedural schedule.

This proceeding will conform to the statutory case management deadline for quasi-legislative matters set forth in Pub. Util. Code § 1701.5. In particular, it is our intention to resolve all relevant issues within 24 months of the date of the assigned Commissioner's scoping memo for each phase. In using the authority granted in Section 1701.5(b) to set a time longer than 18 months, we consider the number and complexity of the issues and tasks, the need to coordinate with other proceedings, and the need to coordinate with the processes and role of the CAISO and the CEC as discussed below.

4.3. Proceeding Category and Need for Hearing

Rule 7.1(d) of the Commission's Rules of Practice and Procedure (Rules) specifies that an order instituting rulemaking will preliminarily determine the category of the proceeding and the need for hearing. Pursuant to Rule 7.1(e), we determine that this proceeding is quasi-legislative as defined in Rule 1.3(d). It appears that the issues may be resolved through comments and workshops without the need for evidentiary hearings. However, we will not make a final determination regarding the need for hearings until after the workshops have been completed in order to make sure that we have a complete record. The Assigned Commissioner may make this determination in the scoping memo or through a subsequent ruling.

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