California Public Utilities Commission

1. What are examples of current and proposed distributed generation services, including ancillary services? What current and proposed DG or DSM applications would provide each such service? What are the current and projected levels of cost-effectiveness and market penetration for each application of DG or DSM?

2. Are any distributed generation and ancillary services a natural monopoly? To what extent? Why? How is your answer similar to or different from the current scheme of unbundling that exists in the electricity services industry? Why?

3. Are there any distributed generation or ancillary services that cannot be unbundled? Why or why not? What are your assumptions about the structure of electricity markets that support your answer? How does your answer differ from the unbundling of generation, including its ancillary services, that exists at the transmission level? Why?

4. Refer to "impacts" in the Definition of Terms. Assume that potential "impacts" of distributed generation and DSM measures at the transmission or distribution levels are unbundled and therefore directly effect the users of the T&D grid such as customers, generators and ESPs. How are the potential "impacts" described? Are the potential "impacts" described differently if they are bundled and therefore directly effect the UDC? What analytical tools exist or are being developed to quantify these potential impacts? How do they compare to the impacts of central station generation at the transmission level? What are your assumptions about the structure of electricity markets, including DG markets, which support your answers?

5. Refer to "externalities" in the Definition of Terms. How can the externalities of distributed generation be internalized or otherwise expressed to DG providers? What are your assumptions about the structure of electricity markets which support your answer?

6. What changes are needed in rules, tariffs (including net metering tariffs), unbundling policies and interconnection practices to facilitate DG while promoting the Commission's restructuring goals?

7. What are the requirements for data management, metering standards, communications and interoperability that are associated with centralized dispatch of DG, (Scenarios 1, 2 and 3 in Question 12 below), and negotiate dispatch in response to congestion conditions (Scenario 4 below)? Which architecture is preferable? Why? What are your assumptions about DG technologies, the structure of electricity markets, and the nature of the distribution system that support your answer?

8. Do the incentives that UDCs face under existing regulation facilitate or conflict with the implementation of DG or DSM measures by others in a competitive retail marketplace? Why? What changes are needed?

9. What, if any, is the locational and vertical market power associated with UDC planning, ownership, leasing, or dispatch of DG for each of the DG three applications given above in the Definition of Terms (including DSM)? Does it differ from the locational and vertical market power associated with UDC planning, ownership and/or dispatch of central station generation and storage? If so, how?

10. Can the locational and vertical market power identified above regarding UDC planning, ownership, leasing or dispatch of DG be mitigated for each of the three applications defined above (including DSM)? If so, what are the alternatives available to mitigate? How do your mitigation alternatives vary with your assumptions about the structure of electricity markets?

11. Please comment on the following scenarios regarding DG applications on the system (supply) side of the grid. Which scenario is preferred? Why? Which market participants' potential applications of DG would be most supported in each scenario? Least supported? Why? What are the pros and cons of each scenario in terms of vertical and geographic market power implications and mitigation? What are your assumptions about the structure of electricity markets that support your answers? How do your assumptions support your answer?

Scenario 1 is a vertically integrated utility in which DG is planned, owned or leased, and dispatched as part of the distribution system. Some T&D decongestion benefits are shared by the UDC with those distributed resources that defer or avoid T&D expansion expenses. All other externalities and ancillary services are bundled in distribution rates.

Scenario 2 is a semi-integrated utility characterized by functional separation of some DG from T&D, and the unbundling or partial unbundling of some DG impacts and ancillary services at the distribution level. T&D decongestion benefits are unbundled in distribution rates. The UDC leases rather than owns some DG as part of the distribution system.

Scenario 3 uses one or more independent distribution (system) operators (IDOs) to address vertical market power. All ancillary services and impacts at the T&D level are unbundled. An IDO does not plan or site DG. Rather, an IDO evaluates congestion conditions for purposes of devising incentives or distribution congestion prices, or offering must-run agreements for ancillary services. Affiliates may own DG on UDC sits if regulators are assured that all providers have equal access to UDC siting. Affiliates may own DG elsewhere.

Scenario 4 uses the IDO(s) to make congestion conditions public so that DG can self-dispatch, possibly in real time. All DG impacts and ancillary services are unbundled. An IDO does not plan or site DG. Congestion conditions are published, rather than priced by an IDO. Users of the distribution system negotiate grid access (DG dispatch) by trading distribution access rights. Market pricing of tradable distribution access rights incents DG siting and distribution system stability. Affiliates may own DG on non-UDC sites only.

JXM/KTT/RC/MS/ERW/KD/jxm

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