CEC 2007 IEPR Excerpts

By Paul Gipe


Excerpts from 2007 Integrated Energy Policy Report

p 124

Chapter 4: Using Renewable Resources to Meet Energy Needs

The resulting market price referent, 93 however, fails to properly consider the risk of price volatility. In the 2006 IEPR Update, the Energy Commission discussed the weakness of relying on a particular natural gas forecast that represents a snapshot of potential future costs. Costs for most renewables generation (other than biomass) are independent of fuel price volatility and depend primarily on capital investment during project development. Thus, renewables generation has value as a hedge against fuel price volatility. However, in the current investor-owned utility solicitation process for long-term RPS contracts, SDG&E states that renewable energy developers tend to increase their bids if natural gas prices rise.94 SCE is concerned that the demand for renewable energy is outpacing the supply and anticipates that prices for renewable energy will be 25 percent higher as the state moves to 33 percent by 2020. To avoid these results, changes in the structure of the RPS program could be designed to de-link prices paid for renewable energy from natural gas and thereby avoid a shortage of renewable energy. One way of doing so is through feed-in tariffs, discussed later in this chapter.

p 134

“In Europe, feed-in tariffs typically offer a fixed, long-term price for renewable energy based on specific technologies.123 In a number of European countries, the tariff levels are set to cover the cost of each eligible renewable technology plus a profit. The tariff can be designed to favor early actors, with generators coming on line in later years receiving a lower price. The tariff also can be varied by technology. Germany’s tariffs are designed to favor both early actors and specific technologies.

This approach has benefits compared to California’s ad hoc contract-by-contract subsidy decisions. By reducing uncertainty in a project’s income stream, feed-in tariffs help developers obtain lower-cost financing and stimulate investment in a domestic renewable energy market.”

p 158

Status of RPS Compliance: California Not on Track to Meet 20 Percent by 2010.

p 184

33 Percent by 2020 Is Feasible with Changes in Program Structure

Using renewable resources to provide 33 percent of retail sales by 2020 is feasible technically and economically, but concerted and coordinated support is needed from government, industry, and the public to make it happen. Changes are needed at least in the following areas:

    • Planning and permitting processes need to be strengthened and streamlined through programmatic environmental impact report/environmental impact statements for renewable energy generation in coordination with state and federal transmission corridor planning.


  • The transmission grid and distribution system need to be expanded and upgraded to access and prepare for the resource mix needed to bring the electricity sector’s greenhouse gas emissions to 1990 levels.


  • The MPR mechanism should be redesigned to allow developers to obtain lower-cost financing and encourage expansion of equipment production for renewable energy.

The first two items are addressed in the 2007 Strategic Transmission Investment Plan. The third, related to use of supplemental energy payments now repealed by SB 1036, should be seen as a hallmark of the start-up phase of the RPS program. To scale the program toward reaching the 33 percent goal, California must move to a new system, such as the expanded use of feed-in tariffs.

Moving Forward with Feed-In Tariffs

Assembly Bill 1969 requires utilities to file tariff/standard contracts for renewable generation operated by a public water or wastewater facility. In July 2007, the CPUC adopted Decision 07-07-027 implementing this requirement. The decision requires that the standard contract use the appropriate MPR from the table of MPRs that are in effect on the date the contract is signed. However, in each solicitation year’s table, the MPRs vary by start year. The decision requires that the actual MPR tariff paid be equal to the MPR for the start year during which the facility becomes commercially operational. Since MPRs used for a particular year’s solicitation may trend up or down over the potential start years, either the utility or the generator, but not both, is at risk of the commercially operational date is delayed. Because for most solicitation years the MPR trends upward for later start years, the generator could have a small incentive to delay commercial operation.

Utilities are required to offer this tariff until they have purchased generation equal to a proportionate share of 250 megawatts, statewide. The CPUC expanded this program to require the same standard tariff for about 230 MW of additional renewable resources from customers other than water and wastewater.223

p 184

In May 2007, SCE started offering a set of standard contracts priced at the 2006 MPR for biogas and biomass generators as large as 20 MW. The 2006 MPR is equivalent to approximately 7.960 to 9.393 cents per kilowatt-hour, depending on contract length (10, 15, or 20 years) and start date. Actual prices paid will also be adjusted for time of delivery, with higher prices paid during peak demand periods.224 The contracts are available until December 31, 2007 up to a maximum of 250 MW.

This offer was prompted by the Governor’s executive order S-06-06, issued in April 2006, which encouraged IOUs to increase sustainable use of biomass and other renewable resources.225 There are three standard contracts, divided by project size and location as follows:

    • Less than 1 MW of generating capacity in SCE’s service territory.


  • 1 MW to 5 MW in the California ISO Control Area.


  • Greater than 5 MW to 20 MW under the operational control of the California ISO.226

SCE set the cut-off at 20 MW because it found that biogas and biomass renewable energy projects this size or smaller have been unable to participate in its competitive RPS solicitations.

The Energy Commission applauds SCE’s leadership in the use of standard RPS contracts set at the MPR, making participation in the RPS feasible for smaller generators that cannot easily participate in the standard RPS process. Following the example set by . . .

CPUC implementation of AB 1969, the contracts offered by SCE should be expanded to other RPS-eligible renewables. Based on SCE’s rationale, the size cut-off could be for systems as large as 20 MW, but SCE and the other investor-owned utilities should impose no cap on the total amount to be contracted and renew the offer each year.

Although the AB 1969 tariffs are not differentiated by technology type as are most feed-in tariffs, because they offer prices differentiated by time of delivery, they effectively result in different prices for different technologies due to differences in typical renewable generation profiles. For example, solar generation would be paid a higher average price per kilowatt-hour because deliveries generally coincide with peak times of delivery. SCE’s tariff pays 3.28 times the base MPR for deliveries during the summer peak time of delivery period. In contrast, unless wind generation was able to supply electricity during a significant part of peak and shoulder periods, with little energy delivered at night and on weekends, the average price paid for wind would be less than the base MPR.

In general, feed-in tariffs can increase transparency, reduce complexity, and provide full valuation of renewable energy, addressing key problems of the current RPS structure. Feed-in tariffs can set different cost-based prices for different technologies, providing flexibility to account for technology-specific market conditions. Rickerson and Grace227 report that “well-designed feed-in tariffs have been highly successful in driving a large percentage of the new renewable energy capacity installed around the world since the 1990s.

In many cases, feed-in tariffs in Europe and Canada are below California’s 2007 market price referents for selected technologies. Considering 19 European countries, Ontario, and pending feed-in tariff legislation in Michigan, feed-in tariffs for facilities with high quality wind resources range from $0.062 to $0.128 per kilowatt-hour, with an average tariff of $0.097 per kilowatt-hour. In contrast, the 2007 MPR ranges from $0.09572 for 20 year contracts with facilities that begin commercial operations in 2008, to a levelized value of $0.11954 per kilowatt-hour if operations start in 2020. Feed-in tariffs range from $0.045 to $0.251 for solid biomass, from 0.036 to $0.251 for biogas-fired generation. Six European countries have feed-in tariffs for geothermal generation below $0.09 per kilowatt hour.228 The German feed-in tariff system is one of the most successful. Germany had 6.3 percent renewable electricity in 2000. In 2007, Germany met its goal for 2010 renewable electricity (12.5 percent) and states that new goals of 27 percent by 2020 and 45 percent by 2030 should be adopted.229

German feed-in tariffs are not linked to the cost of generation of wholesale electricity; rather, they are based on the cost of generation for each technology. The tariffs decline over time so facilities that begin operation in a future year receive a lower payment than facilities beginning operation in the current year.

Cost-based, technology-specific feed-in tariffs in Germany and other European countries have provided a mechanism to contain costs, while also lowering uncertainty to the developer, and stimulating expanded supply of renewable energy.230

Feed-in tariffs allow individuals, communities, and for-profit developers to generate renewable energy at a publicly known price. Feed-in tariffs are long-term and widely available, allowing developers to obtain financing at a lower cost.231 In this supportive climate, equipment manufacturers can invest in expanded production.

. . . A competitive RFO does not protect the ratepayers against the risk of collusion by energy generators to ratchet up the price bid for RPS contracts in renewable resource zones with new infrastructure investment. Nor does it provide a transparent process for developers to easily know and anticipate what price they will receive for their energy. A technology-specific feed-in tariff can accomplish both of these goals and pay a price that reflects the value of the energy product provided by the renewable energy generator.

To fully examine the impacts of a renewable feed-in tariff in California, the Energy Commission, in collaboration with the CPUC, should develop a white paper investigating the use of feed-in tariffs to be completed in 2008.

p 190

. . . Although the Committee would like to see all of the signed contracts for renewable energy come to fruition, the historical record to date indicates this is unlikely to be the case. An expanded use of feed-in tariffs can stimulate the robust pace of renewable energy development needed to achieve 33 percent renewables by 2020.

p 192


Implement a feed-in tariff set, for the immediate future, at the MPR for all RPS-eligible renewables up to 20 MW in size, and begin a collaborative process with the CPUC to develop a white paper evaluating feed-in tariffs for larger projects to accelerate renewable development in the next decade. This process should recognize the value of a diverse mix of renewables considering differential costs of different renewable technologies and incorporate these values and the applicable features of the most successful European tariffs. Also, the joint Energy Commission-CPUC process should consider how to evenly allocate costs for renewable energy feed-in tariffs.