An Update on Competition in California’s Power Markets

Competition in markets can lead to many benefits for consumers. Conversely, monopolies are considered, almost by definition, to be bad for consumers. However, investor-owned utilities in California are monopolies, regulated by the California Public Utilities Commission (CPUC).

Utilities are considered “natural monopolies” because it makes little sense to have more than one set of wires or power plants to serve customers. In return for being granted a monopoly, each utility is regulated closely by the CPUC; this is known as the “regulatory compact.” The CPUC, with the help of intervenors like my organization, and the Division of Ratepayer Advocates, which is part of the CPUC, closely watches over almost every aspect of utility business.

California’s ill-fated attempt at deregulation, from 1998 to 2001, was actually a re-structuring rather than deregulation per se. Under AB 1890, the law passed in 1996 that authorized the re-structuring, the utilities were incentivized to sell off most of their power generation assets, while retaining their transmission and distribution lines. Independent power producers were supposed to step in to the gap and sell power to the utilities in open markets.

We know the rest of the story, but the quick summary is that tight power market conditions (due primarily to low hydroelectric output from the Pacific Northwest) allowed unscrupulous power traders to manipulate markets. Consumers lost billions and one major utility went bankrupt. The Legislature suspended this experiment in 2001.

Since 2001, California has been a hybrid market. In this hybrid market, many independent power providers still build power plants and sell to the utilities, but the utilities have also built a number of power plants of their own, with CPUC approval. Utilities were also authorized in 2007 by the CPUC to build and own renewable energy projects to satisfy the 20% by 2010 Renewable Portfolio Standard.

The CPUC has also signaled its intent to reinstate “direct access,” which was the key component of re-structuring. Direct access allows customers to choose where their power comes from. Direct access providers are independent power providers (IPPs) or middlemen known as electric service providers (ESPs). IPPs and ESPs use utility-owned transmission lines to “wheel” the power to customers. The utilities still bill direct-access customers, but show a different power generation charge on the bill. The CPUC is working on reinstating direct access, but it’s not clear when this will become a real option again as there are significant unresolved issues and there remains significant opposition to reinstatement. (My organization hasn’t taken a position on the merits of direct access reinstatement).

So what remains of competition today, particularly in renewable energy markets? There are a number of different ways for companies to sell renewable energy to the utilities. As mentioned, third parties can sell power to the utilities under the Renewable Portfolio Standard (RPS) system. The utilities issue requests for offers each year and any party can submit a proposal as long as their project is at least one megawatt (MW) in capacity. Contract negotiations can be lengthy, however, and costs consequently high, making it difficult for smaller projects (one to five megawatts, for example) to take advantage of this option.

AB 1969 is a new law that provides a limited feed-in tariff option, for projects up to 1.5 MW. The CPUC has implemented AB 1969 in such a way that any party can sell renewable energy to the utility, not just wastewater treatment plants, as described in the law itself. Up to 478 MW, state-wide, may be bought by the utilities under this authority. The utilities must pay the “market price” for electricity from these projects. The market price represents the cost of electricity from a new natural gas power plant, so if renewable energy projects up to 1.5 MW can provide power at or below this price, this tariff may be useful. Solar projects generally aren’t competitive enough for this tariff to work, but wind, biomass or geothermal energy projects may be. A major advantage of this option over the RPS option is that there is no contract negotiation – it’s take it or leave it. This means that transaction costs are significantly reduced.

Edison also has a biomass standard contract process for projects up to 20 MW. There is some flexibility in these contracts, so transaction costs may be higher than for AB 1969 projects.

Net metering, of course, is a long-standing option in California. Under the net metering law, customers can install a solar, wind or fuel cell project that produces up to 100 percent of the customer’s power. Customers will be credited for excess power on an annual basis. But no payments will ever be provided: the best a customer can do is to get to zero on his/her power bill. Net metered projects must be 1 MW or smaller.

The Public Utilities Regulatory Policy Act (PURPA) is still operative in California – despite its evisceration by the 2005 Energy Policy Act in most other states. The CPUC recently issued a decision reviving PURPA in California. This decision allows “qualifying facilities,” which are cogeneration or renewable energy facilities, generally 20 MW or smaller, to sell power to the utilities at the market price or below (known as the “avoided cost” in this context). A utility must buy this power unless it can show that it is over-subscribed. Contracts are up to ten years in duration. More on SCE’s QF can be found here.

Last, Prop 7, on the November ballot, will significantly improve competition in California if it passes. As I’ve written previously, Prop 7 contains a new feed-in tariff that applies to any size renewable energy projects, with contracts up to twenty years in duration. The utilities must buy power under this feed-in tariff if two conditions are met: 1) energy is offered at or below the market price (the market price calculation will also be modified by Prop 7, making renewable energy even more competitive), and 2) the utility is behind in its annual renewable energy purchase obligations. For more information on the Renewable Energy Act, click here.

Prop 7 also significantly changes the RPS process, very likely giving a substantial boost to renewable energy projects under the RPS system. With an improved RPS system, we can expect to see many more market opportunities for new and existing renewable energy companies.

Tam Hunt is Energy Program Director and Attorney for the Community Environmental Council in Santa Barbara. See for our regional energy blueprint. Hunt is also a Lecturer in renewable energy law and policy at the Bren School of Environmental Science & Management at UC Santa Barbara.

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