Many Options For Solar Developers In California
By Laura Norin, Heather Mehta and David Howarth
Installed capacity of grid-connected solar projects in California has grown from 360 to 1,120 megawatts since 2002, and many more projects representing thousands of megawatts are waiting in the wings.
Solar market pricing information is for the first time starting to emerge, and competitive pressures are starting to bear.
The dynamic situation presents great opportunity for solar businesses of all types. However, many important policy and program elements are still being debated, and upcoming legislative and regulatory decisions could have significant effects both on the demand for solar power and the viability of some of the state’s solar markets.
Solar Power Expansion
The renewable energy industry in California is driven by requirements for utilities to supply a certain percentage of their electricity from renewable sources. California has had a renewable portfolio standard since 2002. The RPS currently requires utilities to supply 20% of retail sales from renewable energy in 2010. An executive order issued by Governor Schwarzenegger in November 2008 (S-14-08) extended the RPS goal to 33% by 2020 and expanded the jurisdiction to include municipal utilities that were exempted from the initial legislation. Legislation to codify the 33% by 2020 goal is pending in the state legislature.
California’s three largest investor-owned utilities – PG&E, SCE and SDG&E – served just over 15% of their combined load with renewable energy in 2009. The California Public Utilities Commission expects that the three utilities will reach 18% in 2010 and achieve the initial 20% RPS goal in 2011. Because the RPS has flexible compliance mechanisms, the utilities will not be penalized for not achieving the 20% RPS this year.
Prior to the establishment of the RPS in 2002, large-scale solar power in California consisted of nine solar thermal power projects with a total capacity of 360 megawatts and one large-scale solar PV array with a capacity of just over three megawatts. Solar power was not a focus of early RPS procurement efforts, given its price premium over other forms of renewable energy. As such, only a small number of utility-scale solar projects have become operational since 2002. However, the installed solar capacity in California has more than tripled during this period, primarily driven by homeowners and businesses that have installed 700 megawatts of small-to-medium size grid-connected rooftop PV systems.
Over the next 10 years, the utility-driven market for medium- and large-scale solar systems likely will predominate, even as the consumer market continues to expand. The size of the utility-driven market can be appreciated by looking at the project pipeline: in August 2010, the California Energy Commission was conducting environmental reviews on 4,800 megawatts of solar thermal projects. In all, more than 8,000 megawatts of solar thermal capacity and 9,000 megawatts of medium-to-large scale PV capacity are reportedly in various stages of permitting, planning and development. While it is unlikely that all of this capacity will ultimately be built, the addition of just one third of this capacity would represent more than a ten-fold increase in California solar generation.
Solar developers have a number of options for selling output in California, ranging from annual solicitations for long-term utility contracts to residential rooftop programs. The details of each utility program differ, as does the ease of participation. The programs can be roughly divided by generator size, though generators of certain sizes are eligible for multiple programs.
The three largest investor-owned utilities in California typically contract for long-term supplies of renewable energy through annual competitive requests for offers called “RFOs.” The CPUC established this program for utility procurement of renewable energy to ensure that the utilities meet their RPS obligations through a transparent process.
The main features of the program are annual RFOs, standardized terms and conditions for the power purchase agreement, an independent evaluator that oversees the RFO, a procurement review group that advises the utilities on procurement-related issues, explicit codes of conduct for any dealing between a utility and any of its affiliates, and a method for determining the reasonableness of contracts that result from competitive procurement.
Bids into the RFO are benchmarked to the market price referent or “MPR.” The MPR is intended to be a proxy for the long-term market price of electricity as established by the CPUC. By statute the MPR must reflect the long-term ownership, operating, and fixed-price fuel costs associated with a new gas-fired combined cycle turbine. For a 10-year contract with a 2010 start date, the MPR adopted in 2009 set the price at $84.48 per mWh.
The MPR is both a cost containment tool and a benchmark of reasonableness for RPS contracts. Any contract that has a levelized price that is below the MPR established by the CPUC after the close of bidding is deemed per se reasonable, while contracts for renewable power executed by the utilities with prices above the MPR must be approved by the CPUC.
Each utility has an overall limit on the amount of above-MPR costs that it can incur. Once the above-MPR funds have been fully allocated, the utility is no longer under an obligation to procure renewable energy at prices above the MPR. As of the end of 2009, each of the three major investor-owned utilities had allocated all of its above-market funds to RPS contracts signed at prices above the MPR. However, the utilities are still under regulatory pressure to procure renewable power, and they continue to procure renewable energy at a range of price points.
Prices in RFOs
The RFO market provides very little price revelation. All RFO bids are sealed. Losing bids are never unsealed, while winning bids are unsealed three years from the project start date.
Beginning in 2010, a small amount of bid information has become unsealed; however, this information is associated with contracts from the 2002-2006 period, some of which have already expired (see Table 1). In general, the data reflect the low prices attributable to the low-hanging fruit that was available in the early days of the RPS program: more than half of the contracts were for existing projects, and the eight new projects were biogas or wind facilities. Thus, these data probably do not reflect the current market price for renewable power.
One approach for estimating the current market price for renewable power is to use the MPR as a rough benchmark. When a utility seeks approval of a renewable power contract, it reveals whether the price is above or below the MPR. During the first five years of the RPS, all approved RPS contracts were priced below the MPR. However, a number of these contracts have since been renegotiated and reapproved at higher prices, and many more recent MPR bids have come in above the MPR.
In 2007 the CPUC began to approve contracts priced above the MPR, and the CPUC has since approved at least 21 above-the-MPR contracts. Given these approvals, the MPR clearly does not represent a price ceiling for RFO bids. On the contrary, contracts that provide specific benefits, such as being able to reliably come on line quickly, may be approved at prices well above the MPR. However, the MPR remains a powerful benchmark, and some developers continue to bid into utility RFOs at below-MPR prices.
New price data for renewable resources recently became available in Nevada, where the public utility commission required NV Energy to disclose pricing data for its current renewable procurement plans. The prices ranged from $81 per mWh for a landfill gas recovery plant to more than $130 per mWh for solar thermal and solar photovoltaic facilities. These prices are generally similar to the prices used in California policy planning discussions, except for solar prices, which appear to be higher in California.
Renewable power in some parts of the country is less expensive than the prices observed in California and Nevada. However, much of the low-cost power cannot be delivered to California given current transmission constraints.
A recent CPUC decision would allow the investor-owned utilities to use the renewable attribute of power that is not delivered to California (in the form of a tradable renewable energy credit or REC) to meet up to 25% of their annual RPS compliance obligations. Implementation of the decision has been stayed pending petitions for rehearing. As this article went to press, the CPUC issued a proposed decision that would lift the stay and increase the allowable use of tradable RECs to 40% of the annual compliance obligation.
If the tradable REC decision is implemented, this policy could lead to new opportunities for renewable energy developers located in the western United States, but lacking transmission access to a California delivery point, to sell RECs to the California market.
The market impact of the tradable REC decision is not yet clear. In addition to limiting the use of tradable RECs to only 25% of the annual RPS compliance, the CPUC determined that the 25% cap applies not only to transactions that are entered into in the future, but also to any transactions that emanate from existing contracts, if such transactions meet the CPUC definition of a tradable REC. According to an analysis by a ratepayer advocacy group, SDG&E’s existing contracts would easily exceed the 25% cap, meaning SDG&E could sign no new contracts for tradable RECs. The 25% cap is set to expire at the end of 2011, but this date could be pushed back to account for the delay in implementation.
The tradable REC decision imposed a cost cap of $50 per tradable REC (where one REC equals one mWh of renewable power) if the utility intends to use the tradable REC for RPS compliance. The cost cap should also sunset at the end of 2011 but may be pushed back. The $50 cap is equivalent to the existing penalty for noncompliance with RPS procurement obligations.
SCE Standard Contract
Southern California Edison offers a standardized contracting process for renewable resources with capacities of 20 megawatts or less located within the CAISO-controlled grid. SCE expanded an older contracting program that targeted only biomass projects to include all eligible renewable resources so long as the facilities meet certain other criteria, including capacity and location.
SCE first offered the expanded renewables standard contracts program in 2009, leading to 13 power purchase agreements with a combined capacity of 200 megawatts. (SCE had sought up to 250 megawatts.)
The price paid for energy under the standard contract was equal to the MPR multiplied by time-of-delivery factors. SCE offered two different contracts depending on the size of the generating facility: one contract for generators with capacities of up to five megawatts and one contract for generators with capacities of up to 20 megawatts. SCE signed agreements with biogas, solar PV and wind projects.
In 2010 SCE again is offering standard power purchase agreements with terms of 10, 15 or 20 years. However, SCE is not offering an energy price at the MPR, but instead will follow a competitive RFO process for awarding contracts.
Small- and Mid-Size Solar PV
The California RPS does not include a specific solar set-aside. However, the CPUC has effectively carved out a distributed solar PV set-aside by establishing separate PV procurement programs for each of the state’s large investor-owned utilities.
While the program details vary by utility, each of the programs is a 50-50 hybrid of utility ownership and power purchase agreements with independent power producers. The programs are designed to spur the development of small and mid-size PV within the utility service areas, even at a premium above the cost of large-scale renewable development.
These programs are in their earliest stages, with one underway and the other two nearing final stages of approval. As such, information on actual program costs is for the most part not yet available. However, in approving these programs, the CPUC set caps for the power purchase agreement prices and set caps on the capital costs of the utility-owned generation. These prices range from $235-$260 per mWh (AC) for power purchase agreements and $3.96-$4.32 per watt (DC) for the capital costs of the utility-owned
The CPUC has expressed hope that actual power purchase agreement costs will be lower than the caps on account of competitive pressure. The CPUC has also recognized the potential overlap between these programs and an expanded feed-in tariff (discussed below) and indicated that the PV solicitations could be incorporated into the feed-in tariff auction mechanism, if that mechanism is adopted.
Additional information about the programs is provided in Table 2.
Feed-in tariffs are standard contracts for power sales to a utility.
The California feed-in tariff program is designed to allow small renewable generators located within the service territory of an investor-owned utility to sell electricity to the utility without having to bid into an RFO.
Current regulations allow generators to sell up to 1.5 megawatts of renewable power to the utility for a price equal to the MPR for contract terms of 10, 15 or 20 years.
In turn, the customer is not eligible for net-metering or other ratepayer-funded incentives and must relinquish the RECs for energy sold to the utility. The utility must agree to the sale as long as the renewable facility meets eligibility requirements, the utility has not yet met its share of a 498.5-megawatt statewide cap and the interconnection does not pose safety or reliability concerns.
Through June 2010, the utilities had entered into feed-in tariff contracts for just 7% (34.5 megawatts) of the available capacity under the cap (see Table 3). Eighty-four percent of this capacity (28.9 megawatts) is in PG&E’s service area, and nearly 40% is from biogas plants. An additional 39% of capacity represents contracts from a single solar PV developer entered into during the second half of 2009.
Prior to this, PV developers had said that the MPR was too low to attract solar development.
Legislation that became effective January 2010 authorized an expansion of the program to projects up to three megawatts and an increase in the feed-in tariff price to include the value of environmental compliance costs paid by the generators and possibly the value of additional power attributes, such as the time of power delivery. It also authorized an increase in the statewide cap to 750 megawatts.
However, prior to implementation of this expansion, the Federal Energy Regulatory Commission ruled that states do not have the authority to set wholesale rates, even for small-scale projects, unless the projects are “qualifying facilities” under the Public Utilities Regulatory Policies Act and the price does not exceed the utility’s avoided cost.
The CPUC has not yet announced how it will revise the existing feed-in tariff program to comply with the FERC ruling.
Concurrently, the CPUC is also considering expanding the feed-in tariff program for the three large investor-owned utilities so that it applies to projects of up to 20 megawatts.
While this expansion is being considered under the rubric of a feed-in tariff, the CPUC staff recommendation is to price the power using an auction rather than a stated price. Under this proposal, contract terms and conditions and requirements for project viability, locational preferences and other parameters would be decided before the auction so that utilities would be able to rank projects on price alone. They would then sign all contracts that meet the pre-determined criteria up to a CPUC-authorized cap. The CPUC would publicly release the bid data (consolidated so that individual bids are masked), adding more transparency to the market.
Some parties to the proceeding oppose the auction proposal and have argued for a traditional feed-in tariff, at least for smaller systems. However, in the wake of the FERC ruling, the auction mechanism may be more viable since it does not require the CPUC to set the price of power.
The proceeding has been stalled since October 2009, but CPUC action on all of these feed-in tariff matters is expected during the third quarter of 2010. As the NewsWire went to press, the CPUC released a proposed decision that would establish a renewable auction mechanism for transactions up to 20 megawatts that use standardized contracts. (The commissioners will not take up this issue for a vote until the end of September at the earliest.)
Residential and Small Commercial Solar
In 2007, California embarked on a program to encourage Californians to install 3,000 megawatts of solar facilities on homes and businesses over a 10-year period.
The program has three components.
First, a “New Solar Homes Partnership” aims to add 360 megawatts of solar systems on new homes in PG&E, SCE and SDG&E service areas. The program provides financial incentives to builders and developers who install PV systems on highly efficient residential buildings.
Second, the “California Solar Initiative” is providing rebates to customers of PG&E, SCE, and SDG&E who install solar panels, with a program goal of adding 1,940 megawatts. Rebate levels are established based on the expected or actual performance of the panels, and incentive payments decline as more systems are installed. Current incentive payments are $0.65-$1.55 per watt for residential customers (depending on the utility) and $0.35-$0.65 per watt for commercial customers. Customers with operating solar systems are also eligible for a further incentive, called net energy metering. Net energy metering allows customers to sell their solar power to the grid at the full retail value of the electricity and then to buy back this same power at other times of the day or times of the year when their load exceeds their self-generation.
Finally, a third component aims to add 700 megawatts of solar systems in the service areas of municipal utilities. Incentives at municipal utilities vary widely, with some utilities providing extremely attractive incentives.
Through July 2010, 670 megawatts of PV have been installed under these programs at an average price of $9.21 per watt for systems smaller than 10 kilowatts and $7.66 per watt for larger systems. The California Energy Commission has certified more than 1,900 solar PV installers and retailers for this program, though fewer than 20 firms have more than half the market share of installations to-date. The largest players in terms of overall megawatts of installations are SunPower (10%), Chevron Energy Solutions (7%), SolarCity (6%), Team-Solar (5%) and REC Solar (5%).
These solar incentive programs provide commercial opportunities primarily for consumer-oriented companies rather than traditional project developers. Companies can compete by lowering upfront costs and risk for consumers, such as by leasing a solar system to a customer or owning a system on a customer’s rooftop and selling the power to the customer. Companies can also compete on cost by providing a standard product or they can offer PV as part of integrated energy management services. SunPower, the company with the most market share in these programs, combines a number of these strategies, offering several financing and leasing options, a 25-year partial warranty and several options for monitoring panel performance.
Given the number of programs in California to promote installation of solar facilities, in many cases developers have the opportunity to choose among several programs (see Table 4).
For example, PV facilities of 1.5 to three megawatts located in the SCE service territory are eligible for the SCE distributed PV program, the SCE standard contract and any of the investor-owned utilities’ annual RPS RFOs. They will also be eligible for the feed-in tariff once the program expansion is implemented.
Often the choice is straightforward: a developer of a two-megawatt PV facility in the SCE service territory would probably have lower transaction costs and a higher probability of success bidding into the SCE PV program than the SCE RPS RFO. However, in other cases the choice can be more complex and can depend on such factors as expectations of future prices, amount of on-site load, and the developer’s comfort with standard contract terms. Price revelation emerging from some of these programs can also help developers identify the programs in which they are likely to be most successful.
Market players would be wise to keep a close eye on the California legislature and regulatory bodies. Key decisions or legislative votes are expected in the coming months concerning the RPS requirement, the investor-owned utility PV programs, expansion of the feed-in-tariff and the status of tradable RECs.