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The document also contains a requirement that officials of the new institute seek matching funds from other sources at least equal to the money coming from ratepayers.

Overseeing the institute, which was charged with working collaboratively with the state’s colleges and national laboratories, will be a board composed of government officials, university officials, lawmakers and representatives of utilities, environmental groups and certain industries, including agriculture. It will be co-chaired by the utility commission president and the president of the University of California. A physical headquarters for the institute is yet to be determined.

The California commission’s vote comes amid increasing calls for public financing of research and development to discover and implement new technologies to mitigate global warming (see Climate Law Update story here).

Still, there was clearly unease about charging the state’s ratepayers for the costs. The institute will be funded by a surcharge on electric and gas customers’ bills. Peevey noted that some have asked why utility ratepayers alone should be asked to pay for the institute. His response:

“The short answer, frankly, is that they shouldn’t. Ratepayer financing should serve as seed money to leverage other public and private sources of funds, and I think it will. Certainly broad-based taxpayer financing would be preferable, if it was available. But we cannot wait for the Legislature to allocate funds any more than the United States can defer decisive action on climate change until China and India take action.”

Despite voting for the proposal, Bohn expressed deep reservations:

“By this action we announce our intent to assess the private utility ratepayers of the state of California $600 million over a 10-year period in order to establish and operate a new organization devoted to seeking and implementing technology solutions to the global problem of climate change. We are, in short, telling the ratepayers that as a condition of receiving essential utility services delivered by monopoly enterprises under our jurisdiction they are required to pay for research and commercialization of technologies that may indeed never deliver the results that impact global warming or, at best, are unlikely to deliver those results in the near term.”

Bohn concluded that the commission's decision "pushes the boundaries of our duty and our jurisdiction almost to the breaking point."

The institute’s work is to be carried out under a strategic plan scheduled to be in place in about a year. The governing board was also charged with establishing panels to establish protocols for transferring technology and looking at potential workforce impacts in the energy sector.

In a separate move, the utility commission approved a $4.6 million request by Southern California Edison to participate in a study on reducing greenhouse emissions from coal-fired electricity generation. The technology under consideration, according to a statement from the utility commission (see text here) would convert coal through a gasification process into predominantly hydrogen and carbon monoxide gases. The hydrogen would fuel a power plant while the carbon monoxide would be sequestered underground.

Peevey said the company would participate in a project known as the Southwest Regional Partnership on Carbon Sequestration. Among other participants, the U.S. Department of Energy has put $65 million toward the effort, he said.

(Photo of California Public Utilities Commission building: Climate Law Update)

The Law

California has in place a long-standing moratorium on construction of new nuclear power plants. The moratorium can only be lifted when there is a demonstrated method for the “permanent and terminal disposition” of high-level nuclear waste. (Public Resources Code section 25524.2.) Since under the law the state will not even consider granting permits for the construction of new nuclear plants until there is a permanent waste storage solution, at present there is little incentive for anyone to put much money or energy into developing a proposal for a new nuclear plant in California.  

Presumably the moratorium could end if the proposed Yucca Mountain nuclear storage facility becomes functional, but the future of Yucca Mountain is also uncertain. The other possibility is repeal of the moratorium statute. All legislative attempts to repeal it have been unsuccessful, and last year backers of an initiative that would have repealed the moratorium pulled it off the ballot when poll numbers showed it unlikely to pass. In short, the legal climate for building a new nuclear plant in California is decidedly chilly.

Water and Earthquakes

Nuclear plants need tremendous amounts of water for cooling, and given the time needed to recover the plants’ high capital cost, the sources of water need to be reliable for quite a while. If there is a commodity in California that is scarcer and more politically fraught than electricity, it is water. Nevertheless, there is water in California, mostly in rivers and the ocean.

Rivers in California, however, are increasingly impractical and unavailable for nuclear power. In addition to environmental pressure to restore salmon runs and preserve rivers in their wild state, there is continued demand for fresh water from agriculture, industry, and residential development. In the southern US, recent droughts have resulted in nuclear reactors being shut down due to low water levels and high water temperatures in rivers and lakes. The bulk of California’s rivers are fed by Sierra snowmelt, which means that drought and global warming (combined with the other demands for water), tend to make river water an unreliable long-term source, particularly in the quantities needed by nuclear plants.

The Pacific Ocean provides the water for California’s two operating nuclear power plants, Diablo Canyon (on the Central Coast) and San Onofre (between Los Angeles and San Diego), and there is certainly plenty of it. One problem in siting new nuclear plants on the coast becomes apparent upon looking at seismic hazard maps – the coastal region of California is also largely an area of significant seismic risk. Even the staunchest advocates of nuclear plants should hesitate to locate a reactor in an earthquake-prone area.

In short, siting a nuclear plant in California presents a dilemma – if you site it where there is plenty of water, you are increasing your earthquake risk. The backers of the one nuclear plant that has been proposed for California are planning to site it in Fresno, an area with little seismic risk, and propose to use municipal waste water for cooling. This is a fairly elegant solution to this particular dilemma, but given the increasing pressure on California’s water supplies, it is not clear how long such water will continue to be considered otherwise unusable “trash” water.

Hybrid Electricity Market

California currently has a “hybrid” electricity market, with electric generation being provided by both utilities and independent power producers.

On one hand, it would seem like the large investor-owned utilities would be the most likely to build a nuclear plant; they can get rate recovery of costs, they don’t have to find a buyer for the energy, and they also currently own and operate successful nuclear plants. Nevertheless, California’s investor-owned utilities appear unlikely to seek to build new nuclear power plants. 

First, the California Public Utilities Commission (CPUC) is likely to require a reasonableness review of any nuclear power plant built by the utilities under its regulation. It would be difficult for the CPUC to abdicate such a post-hoc review, given the high costs involved and the rather embarrassing history of nuclear development in California, which includes the infamous “mirror-image error,” where the plans for Diablo Canyon got flipped, and the “hole in the head,” the abortive attempt to build a reactor on Bodega Head north of San Francisco (and directly on the San Andreas Fault).

By itself this type of regulatory oversight would not appear to be much of a barrier, as after-the-fact reasonableness reviews are a traditional utility regulatory tool. In recent years, however, California’s investor-owned utilities have been extremely reluctant to submit themselves to reasonableness reviews. In the wake of California’s 1996 industry restructuring, the utilities refused to sign long-term electric supply contracts unless the CPUC exempted those contracts from reasonableness reviews. When the CPUC maintained its right to after-the-fact reasonableness reviews, the utilities chose to purchase electricity only on the spot market, with now well-known consequences. Given the utilities’ reluctance to subject themselves to reasonableness reviews for relatively uncontroversial and inexpensive contracts, it seems unlikely they would want to take on the risk of a reasonableness review for a politically contentious and extremely expensive nuclear power plant.

If the investor-owned utilities will not build new nuclear plants, the other possibilities are the municipally-owned utilities and independent generators. The Sacramento Municipal Utility District, which shut down its Rancho Seco nuclear plant in 1989 due to high costs and chronically poor performance, is unlikely to want to go down that road again. 

The Los Angeles Department of Water and Power, which is probably the only other muni in California big enough to build a nuclear plant, might be thinking about it, as its heavily coal-based supply portfolio is looking problematic in a carbon-constrained future. Given its currently somewhat strained relationship with Los Angeles city government, including questions regarding maintenance of its infrastructure, building a new nuclear plant may be a bigger bite than LADWP wants to try to chew in the near term. 

While the moratorium only bars new nuclear plants within the state, AB 32 constrains carbon from both in-state and out-of-state plants whose power is consumed within the state. So if LADWP’s carbon costs associated with its out-of-state coal-burning sources become too high, perhaps it would seek to replace those sources with nuclear plants. But since LADWP could improve its compliance with AB 32 by purchasing electricity from out-of-state nuclear plants, it would more likely invest in an out-of-state plant than attempt to build one in California.

That leaves the independent developers. In fact, the facility proposed for Fresno is by a local group, not a utility. The risks, though, may be higher than investors may want. The cost of a new nuclear plant is high, and the construction process is lengthy and much less standardized and much more complicated than building a gas-fired plant. It will take a long time (and a lot of money) until the plant is up and running and generating electricity and revenue. Since nuclear plants are largely non-dispatchable, the developer will need to find a buyer (presumably under a long-term contract) for significant amounts of baseload power, although the possible return of direct access, currently under consideration by the CPUC, could make this easier. These factors, combined with tightening credit markets and California’s shifting regulatory framework, may make it difficult to find investors who want to put their money into a California nuclear plant. 

Better Alternatives

Compared to many other states, California is rich in potential for development of renewable generation. Wind in the Tehachapis, geothermal in the Imperial Valley, solar in the Mojave, tidal and wave power along the coast – all of these are relatively untapped resources. The California Independent System Operator (ISO) currently has interconnection requests for over 42,000 megawatts of renewable energy (albeit not all of it viable). In short, there are a lot of energy resources in California other than nuclear.

Context is everything – in the southern US, a region with few earthquakes, plenty of water, lots of coal plants and fewer renewable resources, a carbon-constrained future starts making nuclear plants look fairly attractive, especially when compared with a coal plant. But in California, we have other and better choices. Nuclear power plants are simply not the best option for California. And besides, it is the law.

(Photographs, L-R: Peter V. Allen, Richard M. Shapiro)

The report noted that meeting California’s ambitious goals for renewable power “will require a substantial amount of new transmission development, as most large-scale renewable resources are located in remote areas rather than near the state’s major load centers.” State law, although it has some flexibility, requires that 20 percent of electric energy come from renewable resources by 2010 and a 2005 executive order signed by Gov. Arnold Schwarzenegger anticipates that figure should hit 33 percent by 2020 as part of the state’s strategy for meeting the requirements of the greenhouse gas reduction law, AB 32.

The report incorporated a variety of assumptions, including renewable demand, and information about current generation and the transmission system. It also looked at resource operating and cost assumptions, as well as economic assumptions. A key criteria was the development of the “base case,” or group of resources the RETI process included as the starting point. For power generation, that incorporated renewable projects that are operating or currently under construction, or those that are in advanced planning stages with contracts and permits in place.

Whether or not to include a technology in the next phase, known as Phase 1B, of study depended on a number of factors, according to the report, including the likelihood the resource had enough potential to contribute to the state’s renewable portfolio standards, the ability to deliver power cost-effectively to the grid and the maturity of the technology. According to the report: 

“Based on these assessments, resources with limited potential to provide energy to California are eliminated from further review in Phase 1B. While there may be discrete resources in these regions that might provide energy to California, there are not sufficient resources in these areas to merit exploring potential new transmission to access these resources.”  

The report concluded that anaerobic digestion -- which generates power from such sources as municipal sewage treatment plants and livestock operations -- and landfill gas were, among other things, too small to include in the next phase. On the other hand, it concluded the potential for solar voltaic was "virtually unlimited" and that for biomass was “substantial.”

Interested parties can participate in a Webcast scheduled for March 26 and can submit comments until March 28. Overseeing the RETI project are the California Public Utilities Commission, the California Energy Commission and the California Independent System Operator, as well as several publicly owned utilities.

An recently prepared by Peter V. Allen and Paul C. Lacourciere of Thelen Reid Brown Raysman & Steiner contains further details and background about the RETI process. It is available here. 

(Wikipedia photograph of electrical transmission lines in Sweden)

Although some groups, including those concerned about pollutants affecting poor and minority populations, have opposed cap and trade markets, the idea has gained support among other environmentalists and business groups. Peevey strongly backed the approach in remarks before the commission voted Thursday:

“A cap and trade program is likely to produce additional emissions reductions beyond the mandatory programs, it can tackle a wider variety of sources, potentially at a lower cost. It also encourages investment in innovative technologies that lower greenhouse gas emissions.”

But Peevey acknowledged that officials have only just begun to take on what he called the “thorny issue of allocation,” referring to the critical question of how emissions credits or “allowances” will be distributed among those producing greenhouse gases. Under a cap and trade system, credits represent the right to emit a certain amount of greenhouse gases. The document approved by the two commissions recommends that some credits be auctioned, suggesting that the money be used to benefit ratepayers or support energy efficiency and renewable energy investments. But it does not resolve important questions such as what proportion of the credits should be auctioned and how many sold or given away for free:

"Based on the current record, we are not able to determine the proper
relative roles of auctions and administrative allocation of allowances in a
deliverer-based system. Several parties recommend that there be a gradual
transition over several years from relatively more administrative allocations
initially to relatively greater reliance on allowance distribution via auctions.
Distributing some amount of allocations administratively in the early years of
the program could reduce the immediate impact on entities that would bear the
costs of obtaining allowances, and would give them more time to develop
emission reduction strategies. Based on the current record, it may be reasonable
to provide a transition from small amounts of auctioning in the early years to
greater amounts in later years. However, we require more analysis before
making a determination on this issue."

Peevey, during his presentation, said it would not be the commissions’ intention to punish utilities based on their past investments or decisions made prior to the passage of AB 32. However, he cautioned that the state’s retail electricity providers “are starting off in very different positions” with respect to their emissions. He noted, for instance, that some large public utilities spew twice as much carbon dioxide per unit of energy produced than do the state’s private utilities and some other public entities.

The allocation recommendation is expected to be addressed in a subsequent document to be ready in August.

Although other commission members lauded the recommendation, Commissioner Timothy Alan Simon expressed some concerns about the potential impact on municipally owned utilities. He said he would “closely monitor” the next phase to make sure that those utilities, over which the commission has no regulatory authority, are “treated fairly.”

The feed-in tariff for renewable generation owned and operated by water and wastewater facilities was capped at 250 megawatts. The expansion of the program available to customers of Edison and PG&E adds another nearly 230 megawatts to the total, about 124 megawatts for Edison and nearly 104 megawatts for PG&E. 

According to the CPUC, the power that is sold to the utilities under the new tariffs will count toward the state's renewables portfolio standard, which requires the companies to reach a 20 percent renewable goal by 2010. The tariffs apply to multi-year contracts and are based on a so-called Market Price Referent, which is intended to reflect current market prices for long-term contracts.

The CPUC touted the pricing mechanism as a way of supporting the development of up to 480 megawatts of power from small facilities. The latest action also follows on a decision rendered by the panel in 2007 that broadened the program beyond water and wastewater for entities supplying Edison and PG&E. In the statement accompanying the latest action, CPUC President Michael R. Peevey (pictured) in lauded the impact of the new structure for smaller generators: 

"Up until now, only large renewable projects were able to effectively participate in the Renewables Portfolio Standard program. Now small facilities can easily contribute to this program and be compensated for their renewable generation by signing up for these tariffs."

Peevey said the tariff could prove particularly attractive to facilities that have access to significant amounts of biogas, such as livestock operations and water and wastewater treatment facilities.

Feed-in tariffs have been used in other countries, including Germany, to encourage quick growth in such renewable energy systems, according to a brief report on the California program prepared by the U.S. Department of Energy. The DOE report noted that the prices available under the contracts is adjustable by the time of day the power is generated. According to the DOE, the tariffs range from 8 to 31 cents per kilowatt-hour.  

The state's largest utilities, including PG&E, have until 2010 to meet the state's demands.  The Chronicle noted that the standard, which state policy makers are now working to boost to 33 percent, has been tough to meet:

Even PG&E's achievement comes with a caveat. The company now has enough power contracts to hit 20 percent, but some of those contracts won't kick in until after the state deadline passes, delivering power to PG&E customers in 2011. That isn't a legal problem. If a utility falls just short of 20 percent by the end of 2010, it can still comply with the law by overshooting the 20 percent goal the following year.

But that caveat underscores the difficulty utilities have had in meeting California's ambitious renewable-energy goals. Simply put, the state does not have enough geothermal generators, wind farms and solar power plants to produce as much clean energy as California's politicians and citizens want. More renewable-power projects have been proposed, but it's an open question how many will get built. 

Nevertheless, numerous projects are on the drawing boards and the state's ambitious goals would seem to provide significant incentives for at least some of them to go forward, and quickly, as California attempts to meet its self-imposed demands to reduce greenhouse gas emissions under legislation such as 2006's AB 32.

The document is in the form of a proposed decision to be presented for consideration by the full five-member CPUC. If adopted by the panel, the paper would  then constitute a recommendation to the California Air Resources Board, which is the key body in charge of implementing AB 32,  the law that mandates big reductions in California climate-change emissions by 2020 and which officials hope to have up and running by 2012.

Peevey wrote:

We favor inclusion of the electricity sector in a cap-and-trade program for
a number of policy reasons. While we fundamentally favor a certain minimum
level of mandatory reductions from existing programs as described above, a
cap-and-trade system in combination with these mandatory reductions should
be able to produce the GHG emissions reductions required by AB 32 at a lower
cost than reliance on additional mandatory reductions. This is because emissions
trading maximizes flexibility in achieving emissions targets by allowing
obligated entities to rely on the least-cost options across the entire economy.

Significantly, Peevey wrote that any cap-and-trade program must include a component to include electricity imported from other states. While California gets about 20 percent of its juice from neighboring states, those imports represent more than half of the greenhouse gas emissions from the sector, he noted.

It was partly along those lines that he recommended that electricity deliverers to the grid bear the burden of complying with AB 32. Other options would have placed the responsibility on retail providers; in-state generators, with no inclusion of imports in the cap-and-trade system; and in-state generators, with retail providers as the point of regulation for imports. All the choices were evaluated against a set of criteria including "environmental integrity," accuracy and ease of reporting, compatibility with ongoing reforms in energy markets and legal issues.

The so-called deliverer option worked best, Peevey wrote:

After evaluating the point of regulation options against these key criteria,
we find that the deliverer option best meets the criteria. Each of the other
options has serious shortcomings regarding one or more of our priorities. The
deliverer system provides for the environmental integrity of the system by
covering imported power as well as in-state generation. It also shares a number
of common characteristics with a pure generation-based point of regulation
making it likely to be compatible with the eventual design of a cap-and-trade
system that is broader in geographic scope (regional and/or national). The
deliverer point of regulation also improves the ability to report and track
emissions in the sector and minimizes the impact of AB 32 GHG regulations on
California’s wholesale electricity markets. Finally, the deliverer method can be supported on legal grounds.

Despite advocating the inclusion of a market-based approach in efforts to control climate-changing emissions from the electricity sector, Peevey shied away from backing an immediate move along those lines for natural gas. He cited "key differences between the electricity and natural gas sectors" for his recommendation to leave gas out of the equation for now. Those included, he wrote, "significantly fewer options" for reducing greenhouse emissions in the natural gas sector and the "very limited availability of low-carbon alternatives" to gas. However, he added that as California gains experience with a cap-and-trade system and other developments occur, "it may become appropriate" to add the natural gas sector to such a system.

Peevey cited support for a cap-and-trade approach from a wide range of interests, not all of whom usually see eye-to-eye, including environmental groups, utilities, power suppliers and others.

There isn't unanimity among all of the parties, however, as reflected in written comments filed with the CPUC.  Environmentalists, including The Natural Resources Defense Council, filed comments urging officials to "move forward in designing a [greenhouse gas] cap and trade program for electricity. Those same organizations also advocated that California go ahead with "a cap and trade system that includes natural gas, even if regional and federal programs have not yet emerged." Meanwhile, El Paso Corporation, a large natural gas supplier, submitted arguments urging a wait-and-see approach to imposing a gas cap and trade system. The Utility Reform Network, a vocal California ratepayer group, asked that any cap and trade system adopted for 2012 exclude electrical generation, arguing that the state would be better off "promoting existing policies that result in real GHG reductions" and taking other steps, such as developing a regional tracking system for the emissions.