November 29, 2007

Pursuant to Elections Code Section 9005, we have reviewed the proposed initiative “The Solar and Clean Energy Act of 2008” version 1, Amendment #1-S (A.G. File No. 07‑0066).

Background

Provision of Electricity Service. Californians generally receive their electricity service from one of three types of providers: investor owned utilities (IOUs), local publicly owned (municipal) utilities, and electric service providers (ESPs).

The state’s three largest electricity IOUs—Pacific Gas and Electric, Southern California Edison, and San Diego Gas and Electric—each have a unique, defined geographic service area and are legally required to serve customers within their respective service areas. The California Public Utilities Commission (PUC) regulates IOUs’ rates and how their electricity service is to be provided to the customer. These conditions on electricity rates and provision are commonly referred to as “terms of service.”

A municipal electric utility is a local governmental entity that provides electricity service to residents and businesses in its local area. Municipal electric utilities set their own terms of service and are not regulated by PUC. Major municipal electric utilities include the Los Angeles Department of Water and Power and the Sacramento Municipal Utility District.

The ESPs provide retail electricity service to customers who have chosen not to receive service from the utility that serves their area, but instead have entered into “direct access” contracts with ESPs that deliver electricity through the local utility’s transmission and distribution system. In response to the energy crisis that arose in late 2000, state law since 2001 has suspended new direct access for IOU customers. This suspension will continue to about 2015. There are currently around 20 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 required to register with PUC for licensing purposes, but their rates and terms of service are not regulated by PUC. However, PUC has applied certain additional requirements on ESPs, including a requirement to demonstrate adequacy of electricity supply to meet anticipated demand.

While individual customers currently are barred from entering into new direct access contracts, existing law allows 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 through contracting with an electricity provider other than the local utility, such as an ESP. This variation on direct access is referred to as “community choice aggregation.” At present, no community choice aggregator (CCA) exists to provide electricity service in California, though proposals to create CCAs are under development.

Currently, the IOUs account for about 68 percent of retail electricity sales in the state, municipal utilities account for around 24 percent, and ESPs account for around 8 percent.

Electricity Infrastructure Siting. Four principal components comprise California’s system for generating and delivering electricity—electricity generating facilities; the interconnected, interstate electricity transmission grid; electricity transmission lines that tie generation facilities to the grid; and electricity distribution lines that connect the electricity grid to electricity consumers. Regulatory responsibility for siting (permitting) this infrastructure is held by one or more federal, state, and local agencies, depending on the particular infrastructure at issue.

Siting authority for an electricity generating facility is determined by the type and size of the facility to be operated. The Federal Energy Regulatory Commission (FERC) has permit authority for hydroelectric generating facilities, such as dams. The state’s Energy Resources Conservation and Development Commission (Energy Commission) issues permits for thermal electricity generating facilities capable of generating
50 megawatts or more of electricity. Most other electricity generating facilities—including many types of renewable energy generating facilities, such as wind turbines and nonthermal solar arrays—are permitted by local government.

Permitting authority over electricity transmission lines depends upon the function of the line to be built, as well as the type of electricity provider that will own the line. A line tying an electricity generating facility to the electricity grid generally is permitted by the entity that permits the generation facility. (For example, the Energy Commission would have permitting authority over a line that connects a 50 megawatt thermal power plant to the transmission grid.) Construction of a transmission line that is part of the electricity transmission grid is subject to FERC permitting, as well as the permitting authority of the entity that regulates the service provider proposing the line. (For example, in addition to federal permitting authority, a transmission line within the grid is also subject to permitting by the PUC if an IOU proposes the line.) Finally, distribution lines generally are permitted by local government.

Energy Commission’s Permit Processing Time Frames Specified in Statute. Existing statute defines the time frames within which the Energy Commission must issue a decision on an application to construct and operate a thermal electricity generating plant or an electricity transmission line under its siting jurisdiction. Those time frames are 18 months for most applications, or 12 months for applications meeting certain conditions.

Renewables Portfolio Standard. Current law requires that electricity providers that are retail sellers increase their share of electricity generated from renewable sources (such as solar or wind power) by at least 1 percent per year so that, by the close of 2010, 20 percent of each electricity provider’s retail sales are generated from renewable energy sources. This requirement is known as the renewables portfolio standard (RPS) and is enforceable by PUC. Statute defines “retail sellers” as IOUs, ESPs, and CCAs, while specifically excluding from that definition municipal utilities, the Department of Water Resources, or an operator of a cogeneration (combined heat and power) facility. Of retail sellers, only IOUs currently are required to submit to PUC a procurement plan that describes how the IOU will meet its RPS targets at the least possible cost. In addition, IOUs must offer procurement contracts for renewable resources of no less than ten years, with specified exceptions.

A retail seller that fails to meet its RPS target in a given year is required to compensate for that shortfall by procuring additional renewable energy in the following year. Should an IOU fail to meet its RPS target, the PUC may impose penalties. The PUC has capped the amount of these penalties administratively. Current law does not direct the use of these penalty monies, which generally are deposited in the state General Fund.

Current law does not require municipal utilities to meet the same RPS that retail sellers are required to meet. Rather, statute directs each municipal utility to implement and enforce its own renewable portfolio standard. However, no state agency enforces municipal utility compliance or imposes penalties on a municipal utility for failing to meet its renewable portfolio standard objectives. Nor is there a statutory requirement that a municipal utility increase annually its procurement of renewable resources, as is required of a retail seller. Finally, a municipal utility is not bound by a statutory definition of the energy sources that count towards attainment of the RPS objectives required of retail sellers.

The different classes of electricity providers vary in their progress towards achieving the state’s RPS goal of generating 20 percent of electricity from renewable resources by 2010. As of 2006 (the last year for which data are available), the IOUs as a group had 13 percent of their electricity generated from renewable resources, whereas ESPs had 2 percent generated from those same types of resources. Using their own, various definitions of “renewable resources,” the municipal utilities together had nearly 12 percent of their electricity generated from renewable resources. However, if the statutory definition of renewable resources (which does not include large hydroelectric electricity facilities) is applied, their renewable count falls to just over 7 percent.

Addressing the Potentially Higher Cost of Renewable Energy. Recently enacted legislation (Chapter 685, Statutes of 2007 [SB 1036, Perata]), effective January 1, 2008, ends a program, administered by the Energy Commission and funded by a surcharge on IOU electricity ratepayers, that made subsidy payments to renewable energy producers. The payments were referred to as “supplemental energy payments” or “SEPs,” and were made when the price of renewable energy exceeded the market price of electricity as determined by PUC. Under law prior to Chapter 685, IOUs were required to purchase renewable energy at above-market prices only to the extent that SEP funding was available to subsidize the above-market cost. In this regard, the availability of SEP funding acted as a cost limitation on the requirement that IOUs purchase additional renewable energy at above-market prices.

Under Chapter 685, IOUs are still required to purchase renewable energy at above-market cost. However, as part of the rate-setting process, PUC is required to establish for each IOU a limitation on total above-market costs for renewable energy, taking into account unspent monies collected to date for the SEP program, as well as monies that would have been collected in the future for SEPs. This limitation will determine the amount of renewable energy that each IOU is required to purchase at above-market costs.

Proposal

Overview of Measure. This measure makes a number of changes regarding RPS and permitting for electricity infrastructure. In particular, it raises RPS targets for electricity providers, applies these requirements to municipal utilities, and gives the Energy Commission authority to enforce municipal utility compliance with the RPS. In addition, the measure expands the scope of RPS enforcement to include ESPs and CCAs, and increases the minimum length of contracts for renewable energy. The measure expands penalties for failure to meet RPS requirements, removes current caps on these penalties, and directs the use of these penalty revenues. The measure also grants authority for the Energy Commission to purchase, sell, or lease property to further achievement of the RPS requirements. In addition, the measure transfers certain electricity infrastructure permitting responsibilities from PUC and from local government to the Energy Commission. Finally, the measure shifts responsibility for market price determination from PUC to the Energy Commission and revises the process for cost recovery of above-market prices of renewable energy. Each of these components is described below.

Establishes Additional, Higher RPS Targets. The measure adds two new, higher RPS targets—40 percent by 2020 and 50 percent by 2025. Each electricity provider would need to meet the targets by increasing its share of electricity generation from renewable energy by at least 2 percent a year, rather than the current 1 percent. The measure eliminates the requirement under current law that an electricity provider compensate for failure to meet an RPS target in any given year by procuring additional renewable energy in subsequent years.

Makes RPS Requirements Enforceable on Municipal Utilities. The measure requires municipal utilities generally to comply with the same RPS as required of retail electricity sellers and places the authority to enforce this requirement in the Energy Commission. The measure, however, specifies that the Energy Commission does not have the authority to approve or disapprove a municipal utility’s renewable resources energy contract, including its terms or conditions.

Expands Scope of RPS Enforcement Over Retail Sellers. The measure expands PUC’s current RPS-related enforcement mechanisms over IOUs to include ESPs and CCAs as well. The enforcement mechanisms include review and adoption of renewable resources procurement plans, related rate-setting authority, establishment of flexible rules for compliance, and penalty authority. The measure grants to the Energy Commission similar RPS-related enforcement authority over municipal utilities.

Revises RPS-Related Contracting Period and Obligations. The measure requires electricity providers (both retail sellers and municipal utilities) to offer renewable energy procurement contracts of no less than 20 years, with certain exceptions, and further requires an electricity provider to accept all offers for renewable energy that are at or below the market price of electricity established by the Energy Commission. The measure states that an electricity provider is not obligated to procure renewable energy when the price of that energy exceeds the established market price of electricity by more than 10 percent.

Prescribes Penalty Amounts and Directs Use of Penalty Monies. The measure prescribes by formula monetary penalties against an electricity provider that fails to procure sufficient amounts from renewable energy—one cent per kilowatt hour by which the provider falls short of the applicable RPS target. The measure specifies that neither PUC (in the case of IOUs, ESPs, and CCAs) nor the Energy Commission (in the case of municipal utilities) shall cap the amount of any penalty. In addition, the measure states that no electricity provider shall recover through rates the cost of any penalties. The measure also provides the conditions under which PUC or the Energy Commission, as applicable, may waive the statutorily prescribed penalty, such as when the electricity provider demonstrates a “good faith effort” to meet the RPS.

The measure creates the Solar and Clean Energy Transmission Account, and directs that any RPS-related penalties (along with other specified fee-based revenues) be deposited into the account. Monies in the account are to be used to facilitate, through property or right-of-way acquisition and construction of transmission facilities, development of transmission infrastructure necessary to achieve RPS. The measure specifies that the Energy Commission will hold title to any properties acquired with funds in the Solar and Clean Energy Transmission Account and gives the commission the authority to exercise its ownership rights over any such property.

Expands Energy Commission’s Permitting Authority. The measure expands the Energy Commission’s existing permitting authority in two major ways, not limited to the RPS. First, the measure newly grants the commission the authority to permit new nonthermal renewable energy power plants capable of producing 30 megawatts of electricity or more, as well as related infrastructure, such as electricity transmission lines that unite the plant with the transmission network grid. Currently, this permitting authority rests with local governments. Second, the measure gives the Energy Commission the authority to permit IOUs to construct new transmission lines within the network grid, currently a power solely of the PUC at the state level. It is unclear, however, whether the measure has divested the PUC of this authority in giving it to the Energy Commission.

The measure specifies that the Energy Commission is to issue a permit for a qualifying renewable energy plant or related facility within six months of the filing of an application. However, the commission is not required to issue the permit within the six-month time frame if there is evidence that the facility would cause significant harm to the environment or the electrical system or in some way does not comply with legal or other specified standards.

Shifts Responsibility for Market Price Determination. The market price for electricity serves as a reference point against which the cost of renewable energy is measured for cost recovery purposes. The measure shifts from PUC to the Energy Commission responsibility for determining the market price of electricity.

Changes Process for Cost Recovery of Above-Market Prices of Renewable Energy. The measure deletes the current law formula that limits the total amount of above-market costs for renewable energy incurred by IOUs and recoverable through rates. Rather, under the measure, an IOU is able to recover through rates the costs for a renewable energy contract that are no more than 10 percent above the Energy Commission-determined market price for electricity.

Declares Limited Impact of Measure on Ratepayer Electricity Bills. In its findings and declarations, the measure states that, in the “short term,” the measure will result in no more than a 3 percent increase in electricity rates. However, the measure includes no specific provisions to implement this declaration.

Fiscal Effects

State Administrative Costs to Implement Measure. The measure will increase the administrative costs of the Energy Commission by approximately $2.4 million. These increased administrative costs result from the new duties given to the commission by the measure—including enforcement of municipal utility compliance with the RPS, determination of the market price of electricity, and acquisition and management of property to facilitate transmission development. Administrative costs also reflect increased workload resulting from the measure’s expansion of the commission’s existing electricity facility permitting authority to include a broader universe of renewable power plants and IOU-constructed transmission lines within the electricity network.

While some of these new responsibilities for the Energy Commission currently are carried out by PUC—namely, the electricity market price determination and IOU-related transmission permitting—we do not expect that there would be significant offsetting reductions in PUC’s costs as a result. This conclusion is based on two reasons. First, to the extent that the measure is legally interpreted as requiring PUC to continue carrying out some of the duties that the measure assigns to the Energy Commission, there likely will not be offsetting savings to PUC. Second, in other cases, the transfer of responsibility from PUC to the Energy Commission may be reflected in reduced workload delays at PUC, not reduced personnel costs.

Under current law, additional costs imposed by the measure on the Energy Commission will be funded by fees paid by electricity customers. However, because these fees are set in statute, a statutory change to the current electricity surcharge may be required to accommodate the increased costs to the extent that reserves are not adequate to cover them.

In addition, the measure’s other requirements will increase administrative costs of the PUC by up to $1 million. These additional costs will result from greater workload related to the increased RPS targets, such as procurement plan review, validation of renewable resource potential to meet electricity demands, and other related analysis, and the addition of ESPs and CCAs to the universe of entities subject to specified RPS regulatory requirements and rate-setting administered by PUC. Under current law, these additional costs will be funded by fees paid by electricity customers.

Unknown Administrative Savings to Local Governments. By shifting permitting responsibility for certain renewable energy facilities from local government to the Energy Commission, the measure will result in administrative savings of an unknown, but not likely significant, amount to local governments.

Unknown Impact on State and Local Government Costs and Revenues. The primary fiscal effect of this measure on state and local governments would result from any effect it would have on electricity rates.

Changes in electricity rates would affect government costs since state and local governments are large consumers of electricity. The measure could result in higher electricity rates and in turn higher costs to government, particularly in the short term, to the extent that there is increased procurement of more expensive renewable energy (relative to conventional energy) that would not occur but for the measure’s mandates. However, the potential for higher electricity rates to the customer, including state and local governments, would be limited by the measure’s provision of a cost cap on mandated purchases of renewable energy at prices above the market price for electricity. In addition, any increase in costs due to increased electricity rates, particularly in the short run, could be offset to an unknown degree by longer-term cost savings, to the extent that the measure advances development of renewable energy resources so as to lower their cost from what they otherwise would be.

State and local revenues also 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 taxable sales—all of which in turn are affected by what individuals and businesses pay for electricity. However, as is the case with state and local government costs, the measure’s potential to lower state and local government revenues due to higher electricity rates would be limited by the measure’s cost cap provision and by any longer-term cost savings resulting from advances in the development of renewable energy resources.

Summary

In summary, the initiative would have the following fiscal effects:

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