Written July, 2005
Provision of Electricity Service. Californians generally receive their electricity service from one of three types of providers: investor owned utilities (IOUs), local publicly owned electric utilities, and electric service providers (ESPs). Investor owned utilities have a defined geographic service area and are required by law to serve customers in that area. The three largest electricity IOUs in the state are Pacific Gas & Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company. The California Public Utilities Commission (PUC) regulates the IOUs’ rates and how electricity service is provided to their customers (commonly referred to as “terms of service”). (See the nearby text box for definitions of commonly used terms throughout this analysis.)
Commonly Used Terms—Proposition 80
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Publicly owned electric utilities are public entities that provide electric service to residents and businesses in their local area. Unlike IOUs, they are not regulated by the PUC. Major publicly owned electric utilities include the Los Angeles Department of Water and Power, the Sacramento Municipal Utility District, and the Imperial Irrigation District.
The ESPs provide retail electricity service to customers who have chosen not to receive electricity service from the utility that serves their area. Instead, these customers have entered into “direct access” contracts with ESPs for their electricity. This electricity is delivered to these ESP customers through the transmission and distribution system of their local utility. There are currently eighteen registered ESPs operating in the state, generally serving large industrial and commercial businesses. The ESPs also provide electricity to certain state and local government entities, such as the California State University system, several University of California campuses, some community college districts, and some local school districts.
Under current law, ESPs are only required to register with the PUC for licensing purposes; their rates and terms of service are not regulated by the PUC. However, the PUC has applied certain additional requirements to ESPs (discussed below).
Currently, the IOUs provide about 71 percent of the electricity in the state; publicly owned electric utilities provide 14 percent; ESPs provide 11 percent; and the state’s Department of Water Resources provides 4 percent (chiefly for the operation of the State Water Project).
Deregulation and Direct Access. California began the process of restructuring electricity service in the early 1990s by introducing competition into the generation of electricity, with the ultimate goal being lower prices for IOU customers. The plan ultimately adopted in 1996 included a “transition” period during which the IOUs were to sell off their fossil fuel power plants to independent generators, while retaining their hydroelectric and nuclear power plants. During this transition period, the PUC continued to regulate the IOUs’ rates. Eventually, however, electricity purchases and customer rates were to be determined in a competitive market. In such a market, customers could choose to have the IOUs purchase the electricity on their behalf, or they could purchase electric power directly from ESPs through “direct access.”
The deregulation process was put on hold in response to the energy crisis that arose in 2000 and early 2001. At that time, the combination of sharply rising electricity demand, lagging investment in new power plants, and other factors led to electricity shortages and sharply rising prices. At that point, two of the IOUs were still under the transition period and therefore remained under PUC rate regulation. These IOUs were not permitted to pass along the sharply rising wholesale costs to their customers and were pushed into near financial insolvency.
In response to the energy crisis, the state began purchasing electricity on behalf of the IOUs and halted several aspects of deregulation. Among these, the state prevented the IOUs from continuing to sell their power plants and suspended new direct access for IOU customers. Under existing law, this suspension will continue until long-term electricity contracts signed on behalf of the IOUs by the Department of Water Resources expire. The last of the contracts expires in 2015.
While individual customers are currently barred from entering into direct access service, current law does allow a city or county to aggregate all the electrical demand of the residents, businesses, and municipal users under its jurisdiction and to meet this demand from an electricity provider other than the local IOU, such as an ESP. This variation on direct access is referred to as “community choice aggregation.”
Long-Term Procurement Process and Resource Adequacy Requirements. As required by current law, the PUC is currently overseeing a process through which the IOUs secure long-term electricity supplies through a competitive bidding process. Under this competitive “procurement process,” the IOUs select a mix of electricity supplied by their own power plants and electricity provided under contract from other generators to meet their long-term electricity needs. The PUC approved the IOUs’ first long-term procurement plans in April 2004.
In addition, the PUC has adopted rules requiring both the IOUs and the ESPs to show that they will have enough electricity to meet projected demand, known as a resource adequacy requirement.
Renewables Portfolio Standard. Current law requires that electricity providers, including the IOUs, community choice aggregators, and ESPs, increase their share of electricity generated from renewable sources (such as solar or wind power) by 1 percent per year, up to 20 percent of their total electricity supply by 2017. This requirement is known as the renewables portfolio standard.
The PUC has adopted a policy of accelerating the 20 percent requirement to 2010, but this is not required by law. Current law does not require electricity providers to continue to increase the proportion of their electricity from renewable sources once they have reached the 20 percent requirement.
Time-Differentiated Electricity Rates. Generally, all but the largest electricity consumers pay electricity rates that do not change based on the time of day or season. The IOUs have submitted proposals to the PUC to implement a system of time-differentiated rates that would apply to more consumers. Under such a system, customers would be charged different prices for electricity based on the time of day in which it is used, given that the cost to the IOUs of providing electricity varies depending on the time of day. For example, during peak demand times, customers would pay higher rates, while they would pay lower rates during the lower demand times of the day. In theory, time-differentiated pricing would encourage consumers to reduce electricity consumption during periods of peak demand, typically hot summer afternoons when electricity supply is the tightest and therefore its cost is high. The PUC is currently considering IOU proposals to implement time-differentiated rates in a regulatory proceeding, and has not yet determined how such a system of rates would be applied to more consumers.
Overview of Measure. The measure addresses a number of aspects of the state’s electricity market: the regulation of the ESPs and direct access, the procurement process, resource adequacy requirements, the renewables portfolio standard, and the use of time-differentiated electricity rates. Each of these aspects is discussed below.
Regulation of ESPs. The measure places the ESPs under the “jurisdiction, control and regulation” of the PUC. The measure specifies that the scope of this regulation includes the enforcement of requirements related to energy procurement, contracting standards, resource adequacy, energy efficiency, demand response, and the renewables portfolio standard. While the measure broadens the authority of the PUC to regulate the ESPs, it does not, however, specify the extent to which it would regulate ESP rates and terms of service.
Direct Access. In general, the measure bars any customer currently receiving electricity service from an IOU from switching to an ESP. Customers currently being served by direct access contracts with ESPs could continue to receive electricity service from ESPs, effectively “grand fathering” in their direct access service. Direct access customers could also return to IOU electricity service under specified conditions. The measure does not restrict current or future community choice aggregation.
Procurement Process. The measure requires that the PUC implement a long-term procurement process, and directs the PUC to consider a series of factors in evaluating the IOUs’ long-term procurement plans. While the PUC generally now considers the factors listed in the measure, current law does not specify that all of these factors be considered.
The measure also requires that the first priority for IOUs in procuring new electricity is to be from “cost-effective” energy efficiency and conservation programs, followed by “cost-effective” renewable resources, and then from traditional sources such as fossil fuel burning power plants. This “loading order,” as it is known, has been adopted by the PUC, but is not currently required by law.
Resource Adequacy Requirement. The measure requires both the IOUs and ESPs to show that they are able to meet peak demand with adequate reserves to ensure system reliability. This puts into law current PUC practice.
Renewables Portfolio Standard. The measure accelerates to December 31, 2010, the deadline for the IOUs and ESPs to meet the 20 percent renewable resources requirement, consistent with a recent PUC decision. The measure also deletes a provision in existing law that explicitly provides that electricity providers are not required to increase their share of electricity from renewable sources once the 20 percent requirement has been reached.
Time-Differentiated Electricity Rates. Under the measure, residential and small commercial customers with electricity use under a specified amount and in a building built before January 2006 could not be required to pay time-differentiated electricity rates without their consent.
Amending the Measure. The measure states that the Legislature may amend the measure only to achieve its “purposes and intent” and would require a two-thirds vote of both legislative houses and signature of the Governor to do so. To the extent that the measure puts into law existing processes and policies of the PUC that are not currently required by law, the measure would make it more difficult for the state to modify these practices and policies when, for example, conditions in the electricity market change.
State Administrative Costs to Implement Measure. The measure could increase the PUC’s administrative costs, largely depending on the extent to which the commission exercises the broadened authority given to it under the measure to regulate the ESPs. The fiscal impact on the PUC could range from a negligible cost up to around $4 million annually. The upper end of the range would occur if the PUC regulates the rates and terms of service of the ESPs. The measure, however, would not increase the PUC’s costs in areas where the measure puts into law existing PUC practices related to procurement, resource adequacy, and the renewables portfolio standard. Under current law, the potential additional costs would be funded by fees paid by electricity customers.
Uncertain Impact on State and Local Costs and Revenues. The primary fiscal effect of this measure on state and local governments would depend on the impact it would have on electricity rates.
Changes in electricity rates would affect government costs since state and local governments are large consumers of electricity. To the extent that the measure limits state and local governments from entering into new direct access contracts, the measure takes away an opportunity for these government entities to potentially reduce their electricity costs.
State and local revenues would be affected by the measure’s impact on electricity rates, since tax revenues received by governments are affected by business profits, personal income, and sales—all of which in turn are affected by what persons and businesses pay for electricity.
It is not possible to determine the net effect of this measure on electricity rates (and hence state and local government costs and revenues), as the net impact would be influenced by several potentially offsetting factors. For example:
To the extent that the measure increases certainty about the structure of the electricity market, this may encourage additional investment in the market. Such investment, including the construction of new generation, could increase the supply of electricity and potentially lower electricity rates.
On the other hand, the measure’s ban on customers entering into new direct access contracts with ESPs could result in higher electricity rates over the long term by limiting competition in the retail electricity market.
The measure’s impact on retail electricity rates would be influenced by a number of factors, including the specific structure of the regulations adopted by the PUC to implement the proposition.