II. A New Comprehensive Framework - Distributed Energy Resources

Distributed generation encompasses many technologies and is subject to a seemingly equal number of definitions. We will offer our own below, subject to update as our understanding develops in this Rulemaking. Part of this confusion about definitions results from the existence of a range of technologies and resource options that share similar characteristics on or near the demand- or customer-side of the meter, such as the ability to serve or otherwise mitigate load without the sustained, direct involvement of the utility.

In addressing what we consider to be the three central issues in this rulemaking - cost-benefit analyses, incentives and IOU procurement guidance - we intend to develop a conceptual framework that will allow us to evaluate these similar resource options on an equal footing. With this Rulemaking we will begin to employ the name Distributed Energy Resources (DER) to encompass distributed generation, energy efficiency, demand response and electrical storage. These resource options share common characteristics in their ability to serve or otherwise manage onsite load, and in the potential benefits they can provide to the electrical network if employed with sufficient care and foresight.

We will not elide the important differences among these resource options, but in developing a formalized understanding of their similarities and differences we will enhance our ability to judge all options on an equal basis. A ratepayer dollar invested in one of these technologies will indicate that a careful balancing of options has taken place, and that the IOU has employed a Commission-approved methodology reflecting substantial party input. In the long run this approach will benefit ratepayers and the entities that serve them.

In future iterations of our proceedings addressing efficiency, demand response, and electrical storage (when and if storage technologies become a cost-effective resource option⁴), we will introduce the concept of DER and seek to develop and employ a uniform cost-benefit test in judging the suitability of these options for utility planning and procurement. This standard framework will in turn influence our consideration of incentives for utilities and their customers.

This standardized cost-benefit test ultimately involves the calculation of avoided costs over some time frame, typically the short run (SRAC) or the long run (LRAC). This exercise is currently underway in a number of forums before the Commission: in the energy efficiency proceeding, in the implementation of the Renewable Portfolio Standard, in the treatment of QF resources (as discussed in D.04-01-050), in our previous distributed generation proceeding, and now here.

These efforts are essentially technology-specific attempts to answer a common question: what is the value of deferring an IOU investment in traditional generation resources? The answer to this question is the foundation of the benefits side of the cost-benefit analysis, to which consideration of externality avoidance and other technology-specific attributes should be added.

The Commission intends to develop a common methodology for assessing avoided costs across the full range of supply- and demand-side technologies, to be employed as a fundamental component of integrated IOU planning for the short and long term. We intend to undertake this effort in 2005, which is an "off year" in the two-year planning cycle we have implemented for the IOUs.

While this integrated approach to avoided cost is our near-term goal, however, we see no reason to delay the development of avoided cost methodologies in the specific proceedings and program areas to which they can be immediately applied. These proceedings, including this one, should move forward in developing appropriate avoided cost methodologies, and establish robust records that will be of use to the Commission when the effort of integrating these methodologies into a common framework commences later this year.

To that end, this proceeding will focus on developing a cost-benefit methodology for DG, in accordance with our direction from the Legislature. For this DG rulemaking we propose to adopt a modified version of the CEC's definition of distributed generation.

Distributed Generation (DG) is a parallel or stand-alone electric generation unit generally located within the electric distribution system at or near the point of consumption.⁵

DG definitions also vary with respect to the maximum allowable size of the generating unit. The industry broadly characterizes units that are 20 MW or smaller (and otherwise consistent with the definition above) as DG, in part because 20 MW is the maximum capacity size that most utility distribution systems can accommodate. Using this definition, according to the CEC approximately 1980 MW of DG units were installed in the service territories of PG&E, SCE and SDG&E as of December 2003. We will need to develop a definition of what "at or near" means in this context. Further, we are aware that the above definition would potentially encompass larger generation units and Qualifying Facilities, and may therefore be too broad.

For now, however, we will not adopt the distinction of 20 MW or less, pending a demonstration of why this number and not some other is the critical threshold. DG technologies are changing quickly, and ongoing research may allow for deployment of larger capacity DG units in ways that benefit the grid or onsite power consumption. We will look for guidance in the pending record on the proper upper limit, if one exists, for classification as DG. Ultimately we must develop a standard definition of DG in order to harmonize the multiple objectives of ongoing DG programs and recent DG legislation.