XIV. Electronic Service Protocols

The Commission will permit and encourage electronic service in this proceeding to mitigate the expense of participation. Parties should use the electronic service protocols attached to this order for all pleadings if they have access to electronic mail.

Findings of Fact

1. The Commission has expressed its support for the development of distributed generation by utilities and customers.

2. State policy and utility rules will affect the development of distributed generation.

Conclusions of Law

1. The Commission should initiate a rulemaking to consider policies, rules and practices that would promote the development of cost-effective distributed generation in California.

2. Pub.Util.Code Section 353.9, enacted in SB28x of 2001 requires the Commission to develop a cost-benefit methodology for analyzing distributed generation investments.

3. Because all of the issues remaining in R.98-07-037 will be addressed in this rulemaking, the record in R.98-07-037 should be incorporated into this

docket and R.98-07-037 should be closed.

Therefore, IT IS ORDERED that:

1. A rulemaking is instituted on the Commission's own motion to establish policies, procedures and incentives regarding distributed generation and distributed energy resources, and to implement the provisions of Pub.Util.Code § 353.9.

2. PG&E, SCE and SDG&E shall file an update on their plans to incorporate DG into grid-side system planning, as required by Ordering Paragraph 2 of D.03-02-068. These updates shall be filed no later than two weeks from the date of this order.

3. Pacific Gas and Electric Company, Southern California Edison Company, and San Diego Gas and Electric Company are made respondents to this proceeding.

4. Proceeding R.98-07-037 is closed, and issues concerning the Self-Generation Incentive Program will be considered in this new docket. The record in R.98-07-037 is incorporated in this proceeding by reference.

5. The Executive Director shall cause this Order Instituting Rulemaking to be served on the respondents, the Executive Director of the California Energy Commission, the California Power Authority, the California Independent System Operator, the state Air Resources Board, the California Environmental Protection Agency, and on the parties to the following Commission proceedings: R.02-01-011, R.01-10-024, R.99-10-025, and R.98-07-037.

6. Within 20 days from the date of mailing of this order, any person or representative of an entity interested in monitoring or participating in this rulemaking should send a letter to the Commission's Process Office, 505 Van Ness Avenue, San Francisco, California 94102, or ALJ_Process@cpuc.ca.gov asking that his or her name be placed on the service list.

7. The category of this rulemaking is preliminarily determined to be "quasi-legislative" as that term is defined in Rule 5(d) of the Commission's Rules of Practice and Procedure.

8. The respondent utilities shall and interested parties may submit initial responses to the questions posed in Section IV no later than May 15, 2004. Reply comments shall be filed no later than June 6, 2004.

This order is effective today.

APPENDIX A

Potential Topics for Consideration in CPUC DG OIR

A Report Submitted on Behalf of Some Rule 21

Working Group Members

Scott Tomashefsky

California Energy Commission

June 5, 2003

DISCLAIMER:

The comments contained in this paper represent a collection of thoughts from many participants actively involved in the Rule 21 Working Group. This paper is not intended to represent a consensus opinion of the Rule 21 Working Group nor does it present the positions of all entities involved in the Rule 21 Working Group process. It is merely presented as a range of topic areas, some of which have been previously litigated, for consideration by policymakers. While some parties of the Rule 21 Working Group disagree with some of the recommendations, the paper reflects the experience of many individuals who work within the distributed generation community on a regular basis.

Introduction

This White Paper is offered for the California Public Utilities Commission (CPUC) to consider in its upcoming rulemaking on distributed generation.

As general background, the Rule 21 Working Group includes members representing all aspects of the distributed generation community, with utility representatives, DG manufacturers, project developers, and regulators all represented in some form. Approximately 35 members actively attend meetings which are held approximately once every 4-6 weeks. Another 200 members track developments via an e-mail distribution list. Updated materials related to the Working Group, including meeting minutes, Rule 21 equipment certification information, as well as technical documents are available on the Energy Commission website at www.energy.ca.gov/distgen.

The Working Group process is overseen by the California Energy Commission, with technical support funded under contract via the Energy Commission's Public Interest Energy Research (PIER) program. To date, approximately $830,000 of public funding has been used to support the Rule 21 effort.

While the initial focus of the group was to craft a model Rule for the interconnection of distributed generation facilities installed and operated by utility customers, which it did during calendar year 2000, the group now meets for the sole purpose of improving the interconnection process. Issues are debated and addressed in varying degrees. Resolution of issues is often reached. In some instances, however, additional policy direction from policy-makers is required to resolve the issue.

This paper offers several thoughts in consideration of the upcoming DG rulemaking expected to be issued by the CPUC in the next few months. It is our expectation that the CPUC will continue to work closely with the Energy Commission in crafting the OIR, continuing its productive working relationship on DG issues and consistent with the recently approved Energy Action Plan.

Interconnection Issues to Consider in OIR

Export Issues

Issue: Should Rule 21 guide and regulate the interconnection of all generating facilities subject to the jurisdiction of the CPUC?

Rule 21 does not currently restrict generating facilities from exporting energy to a utility's electric system. Rule 21 does, however, establish procedural and technical requirements for evaluating and controlling the impact of such energy exports and allocating the costs and responsibility for addressing such impacts.

The requirement in R.99-10-025 to establish standardized and streamlined interconnection requirements led the Rule 21 Working Group to initially focus on requirements and procedures for smaller customer generating facilities that did not (by design) or could not (due to relative size) export power to the utility's electric distribution system. Establishing the assumption that a generating facility would not feed significant power back into the utility's system allowed for the simplification of the review process regarding the impact the generation may have on the utility's system and the specification of simpler, lower-cost protection systems. This initial focus has led some to believe Rule 21 does not permit customer generation to feed power into a utilities distribution system under any circumstance. This was not intended to be the case.

The requirements for non-exporting customer generation installations are fairly well established. As such, some parties contend that the Rule should be expanded to specifically identify and establish requirements for customer generation that export energy (either intentionally or inadvertently) onto a utility's electric system, but under circumstances that are not subject to interconnection requirements established by the FERC. Such circumstances currently include net energy metering programs established under Section 2827 of the Public Utilities Code, power purchase requirements for Qualifying Facilities with a nameplate capacity of 100 kW or less as set forth in D.96-10-036, or the "inadvertent energy delivery" arrangements negotiated between a customer and the utility.

The Rule 21 Working Group technical subgroup is currently debating the issue and focusing on three primary areas:

Policy direction affirming the scope and applicability of Rule 21 is paramount to its continued success, especially in light of the expectation that the FERC will eventually issue its NOPR on small DG interconnection issues. Care must be taken to identify and coordinate the regulation of customer generation interconnection requirements between the CPUC, the California Independent System Operator (CAISO), and FERC. The utilities' administration of Rule 21 is currently based on the assumption that the interconnection of generation engaged in any transaction regulated by the FERC is subject to FERC interconnection requirements, and that by satisfying those requirements, any interconnection requirements established by the CPUC will also be satisfied.

Metering Issues


There has been much discussion over the language contained in Section F of Rule 21, which addresses Metering and Telemetry requirements. The arguments can be narrowed down to two primary issues: 1) whether utilities should require third-parties to purchase and/or use utility-grade meters; and 2) the extent of information required by the utilities from the DG facility to administer its tariff obligations.


The Rule 21 Working Group debated these issues with the intent of resolving them under the current rule structure. After several months of discussion ending in late 2002, the Working Group concluded that policy reconsideration is necessary to resolve the issue. In summary, the utilities are requiring utility-grade meters 100 percent of the time, which complies with the current language in Rule 21. Other parties believe this requirement is too stringent and should be revisited. Each of these issues is summarized briefly below.


Issue #1: Should each new customer be financially responsible for the installation, operation, and maintenance of utility-supplied billing-grade metering on all new customer generation units?

Most customer generation facilities are supplied with a meter or other measurement function to record the amount of power produced by the generating facility. Such measurement devices may or may not be of utility grade accuracy but is typically satisfactory for the needs of the customer. The data provided by such metering is produced in various formats. The utilities contend that, due to the uncertainties in accuracy and the incompatibility of data formats, installation of a utility meter is required to measure the output of the customer's generator for billing departing load charges and acquiring data needed for the operation and planning of their electric systems.

Parties are concerned about the generation output meter and the utilities' discretion to require a meter they control and choose to be used even if a third party provider or customer has installed a utility-grade meter that meets utilities specifications and allows access to tariff-approved billing data. For these customers, the cost of the meter imposes an additional $4,000 - $10,000 installed cost per project.

Some parties assert the ability to install metering that will meet both the utilities' needs as well as the needs of the customer generator. Given the correct controls for the accuracy and security of the information to be supplied by a customer or third-party metering provider, and the ability to integrate the data provided into the various utilities' billing systems, the utilities indicate an openness to consider third-party metering and have suggested that the third-party metering provisions of Rule 22 may be used as a basis for developing similar opportunities for customer generation metering requirements

Under Section F.2 of the current Rule 21 language, ownership, installation, operation, reading, and testing of metering shall be by the utility except to the extent that the CPUC determines that all these functions, or any of them, may be performed by others as authorized by the Commission. Many parties believe the new proceeding is the appropriate forum to revisit this issue globally.


Issue #2: What metering information should utilities have access to for tariff administration, planning, and operations?

The utilities interpret the language of Rule 21 allow them to require net generation metering on all generating units in their territory. For purposes of tariff administration, the utilities argue that the ability to precisely determine the amount of electric service supplied to a customer in order to administer various applicable electric service tariffs and charges supports mandatory installation of customer generation metering. PG&E identified, in working group meetings, four needs for such metering that are related to the tariff administration: 1) non-bypassable charges; 2) standby charges; 3) gas cogeneration rates; and 4) self-generation incentives. PG&E also identified four reasons that non-metering alternatives are now at issue: 1) gaps in information; 2) the need for manual input of data; 3) customer reluctance to provide proprietary data; and 4) data integration issues.

SCE cites the need to assess nuclear decommissioning charges and public purpose program charges as a basis for requiring revenue quality metering on customer generation. Specifically, SCE argues that there is no common format for the information provided as an alternative to generator metering, thus inhibiting its ability to re-integrate data easily. Moreover, SCE suggests that some customers are reluctant to have tariffs administered on estimated usage and thus raises the issue of an electric utility's obligation to accurately bill their customers.

SDG&E argues that past and current Rule 21 language allows it to require net generation metering of all customer generation. SDG&E's position is that it should continue to require such metering on all new customer generation. While it appears that SDG&E may not conform its practice to the reporting requirement in Section F paragraph 3, SDG&E confirms that it only installs metering on customer generation to administer its tariff provisions.

During deliberations, parties argue that the utilities should demonstrate an overwhelming need for net generation metering before metering is mandated. In any event, parties assert that utilities should only require net generation metering to administer a tariff "to the extent that less intrusive and/or more cost effective options for providing the necessary Generating Facility output data are not available."

The utilities agree that their metering requirements are implemented on a prospective basis and that customers already connected will not be subject to changed metering configurations. Parties argue that the planning and operation of the utilities' systems are impacted by: 1) the withdrawal or injection of power from or into their systems; or 2) the installed capacity of the customer generation. The electrical power withdrawal and injection is metered at the Point of Common Coupling and the installed capacity of the customer generation is reported as an element of interconnection with the utility. Accordingly, planning and operation concerns may not justify net generation metering.

Dispute Resolution Process


Issue: Is the current dispute resolution process contained in Section G of Rule 21 adequate to resolve differences between utilities, customers, or other parties planning and designing DG installations?

The resolution of disputes between stakeholders with regard to DG is outlined in Section G of Rule 21. The Rule offers a process similar to one used when customers have billing disputes with their local utilities. To date, there has been one formal complaint that has gone before the CPUC with many others addressed informally between parties. While the previous statement may suggest that the process is working well, parties have expressed high levels of frustration about how difficult it is to resolve issues short of filing a formal complaint. In some cases, parties have claimed that resolution of differences over protection and operation requirements cannot be reached and the projects are cancelled.

For example, the Rule 21 working group has struggled with the issue of anti-islanding and how much protection is required by utility protection engineers. The working group in its deliberations has concluded that the protection engineers have substantial discretion to determine the level of protection required. While consistent with Rule 21 language, parties seek alternative approaches to challenge the issue further. An enhanced dispute resolution process with some level of binding authority could help resolve this and similar issues, provided that the process should not be focused on finding ways to lessen utility discretion in maintaining the safety and reliability of the distribution system.

The Rule 21 working group is revisiting this issue to determine ways to improve the process. Presently, it is looking at a number of models, including a dispute resolution process proposed in Massachusetts as that state develops interconnection rules. There is no consensus among the working group as to the effectiveness of the current dispute resolution process.

Interconnection Fees/Costs

Issue: Should the interconnection fee schedule established in Rule 21 be revisited now that California has more than two years of experience with a combined $1400 application fee limit for initial and supplemental review?

During the development of Rule 21 in 2000, the working group deliberated extensively about what an appropriate fee might be assessed to customers looking to interconnect. During initial deliberations, discussions focused on the disparity between interconnection costs for small and large systems. At that time, the group determined that, rather than determine a per kW costs, an single hour/cost estimate was determined with the belief that the CPUC might establish a size or technology-based cost structure in the future.

Based on this discussion, the CPUC adopted the group's recommended guidelines of $800 for initial reviews (simplified interconnections) and an additional $600 for supplemental reviews. Subsequently, the working group reached two general conclusions: 1) the $1400 fee needed to be revisited at some point; and 2) the fee should not represent a barrier to DG deployment.

In a related matter, several parties believe there is a need to establish standard reporting and data requirements to track the cost of the interconnection reviews, studies, and related administrative costs. They suggest that the CPUC should review each transaction from the utility and the developer side of the ledger, subsequently establishing caps for each interconnection cost. Included in the evaluation would be administrative, ancillary, interconnection study costs, excluding only labor and capital equipment costs. These costs and current data of all DG interconnected under Rule 21 could be better coordinated with Energy Commission integrated resource planning as well as CPUC revenue, procurement and General Rate Case procedures. Agreement has not been reached as to who should be responsible for the costs of collecting and reporting this information.

Interconnection Rules for Network Systems

Issue: Can simplified interconnection rules be created for network systems?

Simplified interconnection rules for spot and grid secondary network systems do not exist in the context of Rule 21. As such, DG projects proposed in network system areas such as downtown San Francisco require costly interconnection studies and often require expensive equipment to complete the interconnection. Due to the complexity of the studies required and the lack of information related to impact of interconnecting generation into a networked system, these costs can exceed $50,000 per project. It is possible that cost allocation or recovery rules could be determined in the upcoming OIR and eventually implemented as part of the utilities general rate cases.

Non-Interconnection Issues to Consider Including in New DG OIR:

Determine a standard definition of DG. While the last proceeding established a definition of DG, it is appropriate to reconsider the definition in light of the many rules, regulations, and state policies that use a DG definition. In each forum, the definition is slightly different, a problem that is national. What is DG to one person is not to another. Some parties argue that there should be a standard definition of DG while others argue that due to various legislatively derived definitions, developing just one definition for DG is impractical and serves little purpose.

Determine if utility system performance would be enhanced or if ratepayers would realize economic benefits by incenting utilities to deploy DG. The previous rulemaking offered provisions for utility ownership of DG but did not offer any significant approaches for the effective deployment of DG on the utility side of the meter. With a present directive to consider DG in its planning activities, the CPUC could use this OIR to determine if integrating DG into its resource planning activities would benefit utility ratepayers. Close coordination should be made with R.03-03-015, which is currently investigating whether added rates of return should be afforded to DG.

Perform more extensive cost/benefit analyses. This issue was largely ignored in the first proceeding. A potential list of cost and benefit issue areas includes treatment for capacity value, unexpended energy, transmission line delay, avoided distribution investment, and avoided T&D losses. Beyond the traditional cost/benefit measures, system benefits issues such as locational and operational benefits related to waste heat utilization, demand reduction, avoided emissions, and thermal energy production could be evaluated. The Energy Commission's PIER program is currently undertaking several areas of DG research with results that can feed directly into the cost/benefit analysis that should be addressed in this proceeding. The OIR should identify these areas and then explain how the research will be used in the policy context. The DG OIR and its final determination of cost and benefits with order to findings of fact should be officially tied to final decisions of the utilities' future general rate cases and procurement proceedings.

Some parties believe that any examination of DG benefits should make a clear distinction between those that accrue to utility ratepayers in general and those which accrue to the DG operator alone. In addition, many of these parties agree that any cost/benefit analysis include all of the costs related to DG, including those costs shifted to others through incentive programs, exemptions, net metering tariffs, tax credits, etc.

Further evaluate terms of physical assurance. Some parties recommend that the CPUC further evaluate physical assurance with respect to standby tariff rate design. In the context of non-coincident peak demand in some cases, it may not be necessary to require physical assurance to avoid standby charges. The issue centers on whether a utility truly needs to add infrastructure to meet the noncoincident peak of all customers at all times. The debate is similar to the reserve capacity issue being debated for the California transmission grid.

Evaluate effectiveness of CPUC Self-generation Program. The CPUC's Self-generation Program, a $500 million, four-year program designed to provide incentives for the effective deployment of DG has been operating for nearly two years. Many stakeholders have concerns about the cost-effectiveness of the program. The OIR provides an opportunity to review its effectiveness which can then be used in determining whether to extend the program beyond 2004. Please note that the Legislature is currently considering extending the program for at least two years. It should also be noted that no cost recovery mechanism has been adopted for recovery of the program's costs. The following are suggestions for consideration in the OIR:

a. Public review of interconnected DG last 5 years.

b. Review of installation costs versus generation capacity - cost-effectiveness, reliability, geographic disbursement, etc.

c. Review and realignment of eligibility criteria -- (performance-based rather than technology-based and then a re-establishment of technology-eligibility process underway to ensure that process in rule is set to determine performance (emission, rated capacity, efficiency)

d. Payment should be based on capacity installed not eligible project cost, with incentive levels adjusted downward to reflect observed installed costs

e. Review and ensure equipment that converts a cogeneration system's waste-heat to useful thermal output should be eligible for payment. Establish ongoing compliance criteria and verification process.

f. Compare costs and benefits of capacity added to the grid system resulting from the program to other available sources of new capacity. This comparison would be performed to establish the rationale for extending the program and committing additional ratepayer funds.

g. Insurance requirements for the program are more strenuous than for interconnecting systems and should be evaluated.

h. Annual reports could be provided to Legislature.

In performing this analysis, close coordination with the CPUC's Energy Division analysis pursuant to CPUC Decision 01-03-073 is critical to ensure that duplication of effort does not occur.

Ensure that communications between utilities and customers regarding customer generation options are appropriately balanced. Some stakeholders claim utilities are using various tactics to convince customers to retain utility service and not select a DG option. The utilities strongly disagree with these claims and have indicated that, as the current provider of electricity, they have the right and obligation to provide factual economic and educational information to their customers and that doing so is in no way anti-competitive. The utilities have further said they have not and will not attempt to convince their customers to change their decisions to install DG once an agreement to procure DG equipment is reached. It is generally agreed upon that anti-competitive behavior by any of the parties should not be allowed.

(END OF APPENDIX A)

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