5. Distribution System Operations and Planning

In D.99-10-065, the Commission confirmed the utilities' responsibility to plan, operate and maintain their respective distribution systems. We recognized that significant deployment of both grid-side and customer-side distributed generation would likely affect distribution system planning, operations and maintenance, and indicated that R.99-10-025 should study the impacts on these functions.

The Commission directed the Energy Division to hold a workshop to consider these specific distribution system planning and operations issues:

· How distributed generation impacts distribution system operations;

· What changes in operating practices may be needed;

· How the utilities can identify the level of future deployment of distributed generation; and

· How this forecast of deployment can be incorporated into the distribution system planning process.

A Workshop Report was filed by the Energy Division on April 17, 2000, followed by a round of comments and reply comments. Parties were also asked to provide written testimony on potential revisions to existing ratemaking mechanisms to facilitate cost effective distribution system planning. Some parties discussed these and other issues related to distribution system planning and operational issues in both phases of their testimony.

5.1. System Operations

The utilities operate the distribution system to ensure employee and public safety and system reliability. Although operations vary among the utilities, certain basic operating principles and distribution system characteristics apply to all utilities. Several factors could influence how distributed generation impacts the utilities' operation of the distribution system. These factors include customer load, the size, technology, location and operational mode of the distributed generation, the number of distributed generation units on a circuit, the controlling entity, and the applicable tariff structure.

Parties identified how distributed generation impacts distribution system operations, and made recommendations as to the operational changes likely needed to accommodate distributed generation. Most operations system impacts, such as voltage levels, flicker, coordination of protection schemes, unintentional islanding, and remote monitoring were identified through the Interconnection Workshop process, and appropriate technical requirements were specified within the interconnection standards approved in D.00-11-001 and D.00-12-037. The utilities express concern over unintentional exporting of power during a system outage. As established in the interconnection standards approved in D.00-11-001 and D.00-12-037, this problem can be prevented with protection device coordination, conductor upgrades, and other automatic means.

From an operations standpoint, distributed generation raises few operational issues that are not covered by well thought out interconnection standards. Distributed generation that exports energy to the grid has a system planning impact because of the potential need for system upgrades to accommodate exported power. Distributed generation that provides grid support also raises system planning issues.

5.2. System Planning

NRDC agrees that the utility should compare the relative costs and benefits of potential distributed generation⁵ solutions and wires alternatives, and select the most cost effective solution, but expresses concern that current planning models do not thoroughly consider the "public good" nature of certain environmental, customer acceptance, system stability and power quality differences. NRDC does not propose any specific valuation methodologies, but identifies the need to analyze distributed generation options and apply them to the utility planning process.

The utilities indicate that if the utility is responsible for the safety, reliability and operation of the distribution system, it must have control over the planning and operation of the system. We reaffirm this today. Parties also agree that the utilities should continue their current responsibility of managing and planning the distribution system, but urge the Commission to clarify how distributed generation can be incorporated into the utilities' planning process.

5.2.1 Physical vs. Contractual Assurance

In considering how to incorporate distributed generation into the utility distribution system planning process, we must determine whether a non-utility distributed generation could provide sufficient reliability to substitute for a distribution system upgrade.⁶ New Energy, Inc. (New Energy) observes that the utility does not need to own all or any grid side distributed generation to fulfill its obligation to provide a safe and reliable distribution system, but the utility would need to have a certain level of control over grid side distributed generation. New Energy further states that sufficient control can be achieved through contractual relationships, coupled with severe economic penalties for failure to perform.

SDG&E believes there are no economic penalties strong enough to ensure distributed generation operates when needed. According to SDG&E, only physical assurance can ensure system safety and reliability, and is necessary if distributed generation is to be incorporated into the planning process as an alternative to distribution upgrades. SCE concurs, adding that its negative experience with RMR contracts reinforces its view that contracts for grid services are not an adequate substitute for grid ownership, and would interfere with SCE's ability to fulfill its obligation to provide safe and reliable distribution service. If the Commission orders the utilities to contract with third parties for distributed generation capacity, control and dispatch must be retained by the utility.

If we allow third-party owned distributed generation to contract for distribution capacity deferrals, or other services, it must operate when needed, and that load must be automatically curtailed if contracted distributed generation fails to operate. Physical assurance accomplishes these objectives, and addresses the utilities' concerns about the need for sequential restoration. The Interconnection Standards requirements approved in D.00-12-037 pre-certify, standardize and track the performance of distributed generation, which, paired with increasing distributed generation reliability, may make distributed generation an increasingly attractive option to enhance reliability of the distribution system. The option to provide distribution support (for a fee) may factor into a customer's decision to purchase distributed generation. Requiring physical assurance will increase confidence in contracting for distributed generation, thus enhancing opportunities for distributed generation in lieu of distribution capacity upgrades.

We agree with parties who make the distinction between ownership and control of distributed generation. As New Energy observes, "the key to ensuring safe and reliable distribution services is not ownership, but the ability to control the distributed generation unit. There are tools available to ensure that a third party owned distributed generation grid side unit performs its intended function - distribution system reliability." (New Energy Phase 1 Reply Brief, p. 9.) Utility ownership of grid-side distributed generation units is not necessary to ensure the safe operation and reliability of the utility operated grid.

5.2.2 Incorporating Distributed Generation into System Planning

NRDC, Enron North America Corp. and Enron Energy Services, Inc. (Enron), and New Energy recommend use of appropriate incentives to minimize the total cost of delivering electricity services, and to encourage development and use of new technologies. NRDC emphasizes the importance of coordinating grid planning with existing or planned non-utility distributed generation, pointing out that without coordination, the utilities may build distribution capability to serve loads that could disappear from the grid within a few years due to use of onsite distributed generation.

Very few parties provide specific recommendations on how the utilities might design a process to procure distributed generation used to defer capacity upgrades. PG&E and SDG&E indicate a willingness to consider distributed generation as an alternative to traditional wires solutions, and each provides similar broad selection criteria using existing procurement methods to obtain distributed generation. The Workshop Report observes that "[u]sing a solicitation process that provides functional or performance specifications (e.g., amount, time, duration, etc.) rather than a prescriptive solicitation could allow a wider range of possible solutions and a better chance that an innovative solution will surface" (pp. 42-43.)

TURN submits a more detailed approach similar to the alternative principles proposed by Capstone Turbine Corporation (Capstone) in the Workshop Report. TURN's model requires the utilities to develop a transparent planning process subject to Commission review and approval. TURN believes its model creates a fair and transparent process that balances flexibility with accountability.

SCE does not favor solicitation of third party distributed generation used as an alternative to wires upgrades, citing its position that only the utilities should be allowed to own distributed generation used to provide distribution support. SCE urges the Commission to use caution in creating policy regarding this type of distributed generation, citing the QF experience of relying on untested third-party contracts to promote development of new technologies. SCE further notes that utility-owned distributed generation would not require contract administration, an extensive mandatory bid process, or other coordination costs. Lastly, SCE indicates that distributed generation is not currently a cost-effective alternative to distribution investments.

Although PG&E agrees with SCE that distributed generation does not appear to be a cost effective alternative, PG&E offers a proposal to value distributed generation used for distribution support. PG&E's suggested criteria includes four requirements: the distributed generation unit must be identified by PG&E as an alternative to a distribution capacity upgrade; the distributed generation capacity must defer or alleviate an actual investment; compensation to the distributed generation must be cost-effective relative to the utility's alternative wires solution; and the distributed generation unit must provide the required distribution capacity. Although New Energy supports these criteria, it observes that industry participants must be provided more specific information in order to meet the "cost effective" criteria. SDG&E asserts that a formal solicitation process would hinder its planning efforts, and recommends adoption of approach described in its testimony as the most efficient method of implementing a cost effective capacity solution.

Proposals made by a number of parties for procedures to solicit grid side distributed generation, and how to utilize third party owned distributed generation deployed as a substitute for distribution system upgrades, are similar to previous regulatory schemes, and the utilities are wary of them. Some parties regard the process of soliciting for third party distributed generation as similar to the Biennial Resource Plan Update (BRPU) process.

The key utility responsibility is system planning. System planning must consider distributed generation alternatives (both on the grid side and customer side of the meter) to wires upgrades as part of the normal planning process. Non-utility solutions should be actively solicited through the planning process. The level of utility control/physical assurance should be weighed in evaluating/selecting options.

We do not wish to re-create a BRPU-type process for determining whether wires or distributed generation should be used to satisfy demand for electricity in distribution constrained areas. As part of each utility's planning process, each utility shall determine when a distribution system upgrade is necessary to ensure reliability and safe operation of the system. As a part of this determination, the utilities shall determine if a grid-side distributed generation unit could be a reasonable means of providing the electricity demanded in the identified constrained area.

SDG&E outlines the criteria distributed generation must meet to allow the utility to defer capacity additions and avoid future cost. The distributed generation must be located where the utility's planning studies identify substations and feeder circuits where capacity needs will not be met by existing facilities, given the forecasted load growth. The unit must be installed and operational in time for the utility to avoid or delay expansion or modification. Distributed generation must provide sufficient capacity to accommodate SDG&E's planning needs. Finally, distributed generation must provide appropriate physical assurance to ensure a real load reduction on the facilities where expansion is deferred. There is potential that distributed generation installed to serve an onsite use will also provide some distribution system benefit, however, unless it meets the four planning criteria describe by SDG&E, such benefits will be incidental in nature.

We adopt the approach to distributed generation procurement proposed by SDG&E in its Phase 1 testimony and developed in subsequent briefs and Phase 2 testimony. SDG&E describes a method that enables the utility to retain control of its distribution system planning process, maintain reliability at a reasonable cost, yet provides the flexibility required to evaluate various distributed generation options and technologies as an alternative to a wires solution. To accommodate distributed generation in the planning process, SDG&E suggests the utility be allowed to establish performance criteria for determining when a distributed generation solution is a viable distribution alternative. The distributed generation community would be made aware of these criteria and would be contacted in advance regarding specific locations where the utility is considering procuring a distributed generation option. When the utility determines that distributed generation is a potential alternative for the distribution system requirements, the utility would procure the distributed generation solution.

In comments on the proposed decision, TURN proposes that we require the utilities to file advice letters for approval of their implementation process. SDG&E suggests in reply comments that the utilities be required to file a compliance filing describing the methodology used for evaluating distributed generation as a distribution alternative. Both approaches are designed to ensure an understanding of the distribution planning process and distributed generation's role in it. The specific language proposed by SDG&E meets these needs with sufficient flexibility and has been incorporated into an ordering paragraph.

The compensation paid to the distributed generation solution would be no greater than that calculated for the deferral of a planned capital addition. Compensation for this deferral would be paid in the form of a bill credit or direct payment, to the distributed generation provider and should not exceed the cost of the planned addition multiplied by the short-term carrying cost of capital and the number of years of deferral.⁷ This process is consistent with the Operations and Planning Workshop Report, which states that the utilities should be responsible for determining the threshold at which distributed generation is considered as an option for distribution services. Because the distributed generation provider would only be compensated when its costs are less than distribution upgrade costs, and because the utility will control whether a credit is offered, the costs of any credits are absorbable within the existing distribution budgets. Credits shall be treated as distribution expenses.

The selection criteria established by the utility shall include a balanced consideration of reliability and cost. The utility is charged with selecting the proposal that would provide the adequate level of reliability and safety to the affected circuit at a reasonable cost to consumers. All decisions made by the utility must be documented and defensible should any third party challenge the utility's selection.

Payment to the distributed generator providing distribution support services to the utility should be governed by a contract mutually acceptable to the parties. We encourage the utilities to develop sample contracts that can be used as a starting point for negotiations between the parties, like the Form Contracts proposed by SDG&E in Exhibit 72, but we will not mandate or adopt specific terms.