III. Performance Based Incentives and Treatment of Federal Tax Incentives

The two existing solar incentive programs managed by the Commission and the CEC, namely the SGIP and ERP respectively, currently provide payments on the basis of solar project size. In other words, a project owner is paid the full incentive on the basis of the project's rated electrical capacity at the time of installation.

In D.06-01-024, the Commission stated its intent to further explore PBI to fund solar projects, concluding that a good incentive program is one that promotes efficient operation of solar facilities. The Commission reasoned that existing capacity-based incentives do not recognize power production or motivate good project management and maintenance once the project is installed. In contrast, performance-based incentives pay the project owner on the basis of energy production and, in theory, promote efficient operation of solar projects.

The decision also noted that the Federal Energy Policy Act of 2005 provides tax incentives for solar projects, and these federal tax credits could obviate the need for some or all state-sponsored solar incentives. The decision found the record unclear as to how federal tax credits may affect solar investment decisions and stated the Commission's intent to gather more information on this subject.

On March 16, 2006, the Commission sponsored a workshop on the subject of performance-based incentives and federal tax credits. Presentations were given at the workshop by Tom Hoff of Clean Power Research, a consultant to the National Renewable Energy Laboratory (NREL) and the CEC, and Ryan Wiser from the Lawrence Berkeley National Laboratory. In addition, panels of interested parties discussed various PBI alternatives and presented views on the tax consequences of various incentive structures.

In the sections below, we address the overall incentive level for CSI programs beginning in 2007, and two methods for bringing a performance dimension to the incentive structure, namely a structure incorporating PBI for solar projects 100 kW and larger, as well as up front performance-based payments, known as an EPBB, initially for projects less than 100 kW.

A. Incentive Levels and Interaction with
Federal Tax Incentives

In D.06-01-024, the Commission adopted a solar incentive level for 2006 of $2.80 per watt, along with a mechanism to reduce the CSI incentive level in each calendar year through 2016, or when specific MW levels of program participation had been reached. In D.06-05-025, the Commission implemented the first "trigger" reduction to $2.50 per watt to take effect as soon as 50 MW of solar applications had reached "conditional reservation" status.⁷

Following the March 2006 workshop on PBI, the Energy Division staff issued a proposal to differentiate incentive levels based on the tax credits available to different system owners. In effect, the Staff proposes to realign CSI incentives in 2007, the first year of the program, and every year thereafter through 2016. The Staff Proposal recommends reducing the 2007 CSI incentive level to $1.50 per watt for commercial customers and to $2.25 per watt for residential and tax-exempt customers, such as federal, state and local governments, schools, and non-profit organizations who cannot take advantage of federal tax incentives.

Staff reasoned that commercial customers can take advantage of the federal tax credit of 30% of solar installation costs, while residential customers' tax credit is capped at $2000.⁸ In an attempt to minimize these differences in the effective cost of solar facilities after tax credits, Staff proposed a lower incentive of $1.50 per watt for commercial customers, while allowing residential and tax exempt entities to receive $2.25 per watt.⁹ The Staff's incentive proposals were selected based on calculations that considered installed system costs, expected solar production, retail energy prices, tax credits, and a 10-year simple payback for a solar facility with a 25-year life. (Staff Proposal, pp. 11-12.) Staff analyzed the effective net cost per kWh for solar installations based on these assumptions, both for taxable and non-taxable entities. (Staff Proposal, pp. 17-18.) Staff further supported its proposed 75¢ per watt differential in the incentive rate by reasoning that residential system owners, unlike commercial system owners, are unable to take advantage of the tax benefits of depreciation. Residential systems, which are smaller in size, are typically more costly per installed watt than commercial systems.

In response to the Staff Proposal, the solar industry generally opposes the $1.50 per watt level proposed by Staff, arguing that this level is too significant a reduction from the current rebate level of $2.80 per watt. Specifically, the Joint Solar parties and ASPv contend the reduction in incentive levels in the Staff proposal is premature, risks disrupting the solar market, and does not account for the actual state of the solar market. The Joint Solar parties cite data from the SGIP program administrators, which suggests the rate of customer applications for rebates at $2.80 per watt has slowed considerably. They also claim that reducing the incentive level to $1.50 per watt would result in an even larger rebate reduction when combined with other elements of the Staff Proposal, particularly Staff's proposals to change how system capacity is measured, use a "design factor" in calculating EPBB payments, and ignore the time value of money in PBI payments. Therefore, the Joint Solar parties maintain the rebate should remain at $2.80 per watt until there is further market response.

Sun Light comments that the incentive levels proposed by Staff are inadequate and will prevent the Commission from meeting its goal of 2,600 MW of solar installations. Sun Light contends the CSI MW goal will only be met with a growing pool of solar suppliers and incentive levels that motivate buyers. To supports its view, Sun Light provides data from the CEC's current solar rebate program indicating a trend away from residential toward commercial installations, with residential growth rates flat since 2003. (Sun Light, 5/16/06, pp. 5 and 9.) According to Sun Light, this trend indicates that growth in the solar industry is slower than what is needed for the CSI to reach its MW targets. It contends high solar material costs are driving systems costs up, not down, and the incentive levels proposed by staff will not motivate residential or commercial customers to invest in solar.

Sun Light also provides a survey performed by Cal SEIA indicating the payback periods required by various customer segments. Sun Light maintains that residential customers are satisfied with longer paybacks ranging from 10 to 15 years, while commercial customers often find a six to eight-year payback more reasonable. Sun Light contends that government and non-profit customers are not always price conscious, their decisions are often politically motivated, and therefore, they may be less concerned with payback term. Sun Light uses this insight on payback terms and other critical assumptions regarding costs for PV systems, labor, and electricity costs to perform a detailed analysis of rebate levels and the internal rates of return they generate. Based on this analysis, Sun Light concludes the $1.50 per watt level proposed by Staff will result in an unacceptably long payback term for commercial customers that would lead to massive reductions in commercial PV sales. Sun Light suggests 2006 residential rebate levels be retained at $2.80 per watt to provide a reasonable payback for residential solar investors and steady growth in the residential market sector. For 2007, Sun Light recommends that both residential and commercial rebates be $2.70 per watt, declining in later years by $0.25 per watt each year.

Regarding the federal tax credit, ASPv claims it is premature to differentiate rebates between the private and public sectors on the basis of the federal tax credit. ASPv provides specific recommendations for an incentive level of $.492/kwh (corresponding to $4.31/watt), which it later revised to $.39/kwh (or $3.42/watt),¹⁰ based on its own analysis of the PV market and the returns it assumes investors require. Golden Sierra expresses concern that Staff's proposed incentive levels are based on incorrect assumptions regarding capacity factors and payback periods for solar facilities. Golden Sierra contends the higher incentive rate for non-taxable entities fails to account for their willingness to accept a longer payback period and other financial benefits these entities might receive, such as CEC low-interest loans. Golden Sierra recommends a starting incentive rate of $.36 to $.40/kwh (equating to $3.15 to $3.50 per watt).

Comments on the Staff Proposal from other interested parties present additional concerns. SDG&E/SoCalGas supports Staff's proposed incentive rates, but they express concern that it will be administratively difficult to prevent government and non-profit applicants from gaming the system to receive the higher non-taxable incentive rate. PG&E and SCE oppose incentives proposed by solar industry commentors, which are higher than those adopted in D.06-01-024. SCE argues these incentive levels are inflated and will result in fewer total installations within the CSI budget. CARE proposes that residential and non-profit organizations should receive an incentive closer to $4.00/watt to bring solar costs for residential and non-profit customers in line with costs for taxable entities.

The starting incentive level for the 2007 CSI program is a critical threshold decision. The debate on this topic has been informed by analyses performed both by Staff and the parties, all with competing assumptions about discount rates, payback periods, and the effect of tax incentives on financial decision-making. In reviewing the various proposals, we find that certain assumptions are more reasonable than others and inform our decision-making.

We will modify the single incentive rate adopted in D.06-01-024 in favor of two separate incentive rates, one for the commercial and residential sectors, and a separate rate for tax-exempt entities. These new incentive rates will take effect on January 1, 2007 as follows:

Table 4: 2007 Initial Solar Incentive Rates

Residential Customers	$2.50/watt
Commercial Customers	$2.50/watt
Government/Non-Profit Customers11	$3.25/watt

1. One Incentive Rate for Residential and Commercial Segments

First, we adopt a single incentive rate of $2.50 per watt for both the commercial and residential customer classes despite the Staff proposal to pay commercial $1.50 per watt and residential $2.25 per watt. We are persuaded by the comments of solar industry participants that a reduction to $1.50 per watt at this time for the commercial segment would prove disruptive to the solar market, particularly coupled with the introduction of performance-based incentives through PBI and EPBB. We prefer to keep the incentive level at a steady rate for now and avoid introducing numerous changes at once into the CSI program. Pursuant to D.06-01-024, the $2.80/watt rate for 2006 will drop to $2.50/watt when 50 MW of conditional reservations are reached. We now find that the rate should remain at $2.50 per watt, until program administrators receive applications and reserve incentives for an additional 70 MW of solar installations. In Section VI below, we discuss future adjustments to the incentive rate throughout the duration of CSI.

Moreover, the commentors persuade us that Staff may have relied on inaccurate assumptions in its analysis supporting the $1.50/watt incentive level. For example, Staff assumed a 10-year payback level for all customer classes and a 20% capacity factor. In contrast, solar participants claim that commercial customers require a shorter payback, in the realm of six to eight years, and capacity factors of 16% to 18% are more reasonable. Sun Light claims an incentive level of $2.50/watt provides a reasonable payback for commercial customers and a reduction to $1.50/watt ignores high solar module costs. We find these comments on payback periods, capacity factors, and module costs provide sufficient justification to leave incentives at $2.50/watt at this time.

We will adopt a residential incentive rate of $2.50/watt, the same as the commercial rebate. Although staff had proposed that residential customers should receive a higher rebate level than commercial customers because their federal tax credits are capped at $2,000, we are persuaded by the comments of solar participants that residential customers are generally willing to accept a longer payback period for their solar investment. Thus, even though residential customers receive less federal tax benefit, the Staff assumption of a 10-year payback for residential customers may have been too short. We see no reason to pay residential customers a higher rebate when comments suggest they may accept a payback period of up to 15 years.

We will not lower the residential incentive rate to $2.25/watt, as Staff had proposed, because Sun Light convincingly points to data indicating slower growth in the residential solar sector in the last few years. Again, we do not think it advisable to lower the current incentive level when data indicates slower adoption of solar technology in this market segment. We prefer to keep incentives at their current level while we await further experience with the introduction of a performance dimension to incentive payments through an EPBB mechanism for residential customers, as discussed further in Section III.C below.

Solar parties alleged they need higher incentive levels than those proposed by Staff, arguing solar panels are a large portion of installed system costs and costs have risen in the last year due to a world shortage of silicon. Parties estimate the worldwide silicon shortage will lessen by 2009. Despite these comments, we will not increase incentives over their current levels for those customers taking advantage of federal tax credits. As Staff noted in its proposal, the CSI budget cannot support higher incentives in 2007 and still maintain reasonable levels throughout the duration of the CSI program.

2. Higher Rebate Level for Tax Exempt Entities

We will adopt a higher incentive rate of $3.25/watt for tax-exempt entities such as government and non-profit institutions. As Staff pointed out, these entities are not eligible for the substantial federal tax credits available to commercial enterprises to offset the costs of system installation unless they can somehow take advantage of sophisticated third-party financing techniques.¹² Under a third-party ownership arrangement, a for-profit entity owns the solar facility installed on a tax-exempt entity's property and sells or leases the energy from that system, through a power purchase agreement, to the tax-exempt entity at a discounted rate that reflects some part of the various tax benefits available to the taxable owner. This strategy may not be feasible for all tax-exempt entities. Complex power purchase agreements may not be readily embraced by local government and public agency elected boards, or non-profit boards. We run the risk of discouraging non-profit entities from making solar investments if we pay them the same incentive as commercial entities, thereby forcing them to use third-party ownership arrangements to get a tax benefit and bring installation costs in line with those entities that receive a federal tax credit.

Parties did not dispute Staff's analysis that the net effective cost per kWh of solar is higher for those entities that cannot reap federal tax advantages. Nevertheless, the comments generally do not support a higher incentive for tax-exempt entities, citing difficulty administering two incentive levels and the risk of gaming. Solar industry participants suggest this segment is less price-sensitive, willing to accept a lengthy payback period, and has access to other incentives such as low cost loans.

We are hesitant to ignore Staff's proposal despite its lack of support from parties. The Staff analysis shows a significantly higher net cost per kWh for a tax-exempt entity making a solar investment.¹³ We note there was no participation from the government or non-profit sector in comments on this topic. Lack of support from parties does not mean the idea is not worthy. Further, Staff research on SGIP program participation indicates that government and non-profit institutions have been a vital component of SGIP program participation and we do not want to risk losing penetration in that sector as we transition to CSI.¹⁴

For these reasons, we conclude the $0.75 per watt differential proposed by Staff is reasonable because it will mitigate the higher net solar costs for tax-exempt entities and will allow government and non-profit entities to consider solar investments without third-party financing and ownership arrangements. Of course, tax-exempt entities may still find it to their advantage to use third-party financing, and if they do so, they will be paid at the lower incentive level of $2.50/watt. Tax-exempt entities who apply for the higher incentive level must include with their incentive application a certification under penalty of perjury from their Chief Financial Officer or equivalent that they are a government or non-profit entity and they are not receiving federal tax benefits through financing arrangements. We conclude it is reasonable to adopt this rate, at least for the first few years of the CSI. We will reassess the necessity for the higher tax exempt rate after a few years of data and experience.

3. Conclusion

In summary, we modify the single CSI incentive of $2.80/watt adopted in D.06-01-024 in favor of rates tailored to consider the tax effects seen by residential, commercial and tax-exempt customers. Residential and commercial customers will be paid the same incentive rate, even though they experience different tax effects, because they have different payback periods for their solar investments. Tax-exempt entities will receive a higher rate, unless they choose to engage in third-party financing arrangements. We shall revisit the necessity for this higher incentive rate for tax-exempt entities after a few years of experience with CSI. In addition, we will reconsider incentive levels for all customer classes if the federal tax credit is not extended past December 31, 2007.

B. Performance-Based Incentives for Large Solar Projects

We now turn to the issue of whether a PBI structure is a prudent and effective way to encourage installation of well-performing solar systems, given the Commission's earlier statements in D.06-01-024 that a good incentive program is one that promotes efficient operation solar projects.

The basic rationale for a PBI structure is to ensure that ratepayer subsidies for solar are paid based on effective system design, installation, and ultimately on performance, and not simply the rated capacity of the physical components. In the past, incentives were paid up front to help reduce the net investment cost of a solar system. These incentives may have been paid either as a percentage of the capital cost up to a cap or as a fixed contribution based on the rated wattage capacity of the solar system. Neither approach necessarily motivates the system designer to deliver a well-designed and installed system, nor ensures the system owner will attend to ongoing maintenance and performance of the system.

Thus, the Commission has been motivated to move in the direction of paying incentives based on solar system performance. The Staff Proposal recommended a PBI incentive structure for large solar installations with the following basic parameters:

· Base the PBI incentive on the dollar-per-watt incentive level for 2007, then convert it to a cents-per- kWh payment.

· Apply a system capacity factor of 20% to estimate kWh production per watt.

· Apply PBI to systems greater than 100 kW in size, but allow smaller systems to opt-in to the PBI structure.

· Offer fixed and flat PBI payments over five years, with no discount rate incorporated into the payment.

· Cap PBI payments at 10% over estimated output to preserve the CSI budget in the event there are very high performance technologies.

· Pay building-integrated PV systems using the PBI structure, regardless of size.

· Do not apply PBI to new construction applications.

· Consider phasing in the PBI structure over a period of three years, with:

o 50% of the incentive paid up front, and 50% via PBI in 2007,

o 25% of the incentive up front, and 75% via PBI in 2008, and

o 100% PBI in 2009.

Parties' comments on the Staff Proposal were generally supportive of moving towards a PBI structure. No party argued against PBI, though one party did recommend offering consumers a choice of a PBI or an up-front, capacity-based payment, pointing out there is not yet an example of a successful PBI program in place in the country.

We remain convinced that the reasons for moving forward with PBI are compelling. A PBI incentive structure accounts for five distinct factors that affect system performance:

· Actual system rating may differ from the reported rating due to incorrect equipment ratings and/or poor workmanship during installation;

· System design may not be optimal due to orientation (compass direction and tilt) and shading issues;

· Geographical location may reduce output because some areas of California have a better solar resource than others;

· System performance may be less than ideal due to poor system maintenance, e.g., dirty modules or equipment failures that are not repaired in a timely manner; and

· Weather variability may be different than the estimated typical year, thus resulting in a lower or higher amount of energy production than was expected.

Overall, under a PBI structure, consumers will be motivated to focus on the proper installation, maintenance, and performance of their systems. For all of the reasons stated above, we elect to move to a PBI structure now. Thus, for the remainder of this section, we will focus on the details of how to design the appropriate PBI structure.

1. Size Threshold for PBI

The first issue we encounter in PBI design is whether to apply PBI to all systems or only those systems over a certain size threshold. As noted above, the Staff Proposal would apply PBI only to those systems over 100 kW in size.

All parties representing the solar industry agree with the Staff Proposal to apply PBI initially only to projects over 100 kW in size. In addition, ASPv would make PBI mandatory for newer, innovative solar technologies such as building integrated PV and bifacial modules, since system ratings are not yet capable of estimating output from these technologies. As noted earlier, Sun Light, while supporting PBI in general, suggests offering each customer installing a system over 100 kW a choice between PBI and a capacity-based incentive payment.

Several parties, including PG&E and TURN, suggest starting PBI with systems over 100 kW but then transitioning PBI's application to smaller systems over time as the industry gains more experience with PBI payments. SCE would apply PBI to all systems over 30 kW immediately and transition down to systems as small as 10 kW over time. A number of other parties, including DRA, SDG&E/SoCalGas, SDREO, and CFC, would apply PBI immediately to all non-residential systems, regardless of size. Only CFC recommends applying PBI to residential systems immediately, though SDG&E and SoCalGas also recommend that the Commission consider this in 2007. CFC reasons that the only exception to the PBI requirement should be low-income households and businesses that are credit-worthy but unable to obtain "reasonable" financing. Several parties provided statistics showing that the number of projects in the size category over 100 kW is very small, while the solar system capacity associated with those projects is comparatively large.

Overall, we find parties provided little justification for the size threshold recommendations in their comments. Based on the lack of compelling evidence or reasoning offered by the parties in their comments, we prefer to adopt the Staff recommendation to require initially a PBI structure for systems 100 kW and larger. The main reason offered by Staff for this initial recommendation was the ability of customers investing in larger systems to finance additional system costs up front.

Lowering the size threshold at this time would potentially limit investments in solar systems by smaller commercial customers, i.e., those who are likely to invest in solar systems in the 30 kW to 100 kW size range. We are concerned that suddenly expecting these customers to pay for or finance an extra 30% to 40% of a solar facility cost, absent an up-front incentive, could jeopardize their investments in solar. Moreover, the EPBB approach to incentives for systems under 100 kW (discussed below in Section III.C) takes different but equally important steps to align incentives with realistic and site-specific expectations of performance for smaller systems. We prefer to start PBI with the larger systems and then transition to smaller systems over time, in order to allow sales and financing arrangements to evolve in the direction of PBI. We conclude that after an initial transition period and more experience with the PBI structure, we will be able to apply this structure to smaller systems. We envision a two or three year transition period before applying PBI to smaller systems in the 30 to 100 kW range. Therefore, we anticipate applying PBI to all systems over 30 kW beginning in 2010.

In the meantime, we will allow any system, regardless of size, to "opt-in" to a PBI payment structure beginning in 2007. There are some high-performing systems and system designs that may benefit from a PBI structure because of their performance characteristics, if the customer is willing to forego an up front payment in favor of a presumably-larger PBI payment over time. Certain other newer solar technologies, such as concentrating solar PV and tracking systems, also may opt in to the PBI to the extent their system size characteristic does not already require it. In addition, we will require that all building-integrated PV systems be paid on a PBI basis, because no accurate system rating yet exists to evaluate the likely performance characteristics of these systems. Finally, we will exempt all new construction applications from a PBI requirement, regardless of size, in order to allow the net up front cost of a solar system to be integrated into the financing of the new building as a whole. Solar installations on new construction projects will be paid under the EPBB approach outlined in Section III.C.

2. Time-Differentiated Payments

Although the Staff Proposal did not address time-differentiated payments, several parties commented on whether PBI payments should vary based on the time of day that the solar system produces energy. In particular, Thomas Beach recommended time-differentiated PBI payments. The rationale for this recommendation is that while south-facing systems will provide a larger total kWh output annually, west-facing systems offer greater value in kWh produced during the peak period (but lower annual kWh).

SCE, in its reply comments, rejects the concept of time-differentiated PBI payments as too complex. SCE maintains that the on-peak benefits of solar do not necessarily translate into transmission and distribution system benefits. The utility also points out that net energy metering already rewards on-peak performance of systems through time differentiated net energy credits for customers on time-of-use (TOU) rates.

At this time, we will not require time-differentiated PBI payments because of the added complexity in calculating and communicating the value of solar incentives. Moreover, many customers are already on TOU rate schedules that vary energy prices throughout the day, so that solar production reduces utility bills at values mirroring the TOU rates. In addition, most customers with solar facilities already participate in the net energy metering program which is inherently time-differentiated for those on TOU rates.

Though we will not make PBI payments time-differentiated at this time, we remain interested in structuring the payment of solar incentives to further reward on-peak delivery of kWh to the system. The ultimate goal of the CSI is to produce valuable energy during peak times. In general, we are attracted to the German feed-in tariff system, which combines our two-part approach (i.e., PBI and net energy metering) into one payment for system performance that can be time-differentiated. We believe it is preferable to embed time-differentiated signals into a tariff structure rather than an incentive structure such as PBI. Therefore, we will not require a time-differentiated PBI structure at this time, but will ask our staff to continue investigating and evaluating alternative incentive structures for later phases of the program.

3. Payment Period

We now address over what period of time to make PBI payments. The Staff Proposal recommended payments over a five-year period.

Most parties generally agreed with the Staff Proposal to offer PBI payments over a five-year period. SDG&E/SoCalGas would prefer to make PBI payments over the life of a system (20 to 30 years), but stated that they can accept the Staff Proposal. CCSF commented that public entities might prefer a 10-year payment stream to match the payment stream of project financing, but CCSF would not object to a five-year structure.

We see a tradeoff between the preferred payment period for ratepayers and solar investors. A shorter payment period is more attractive to solar buyers and has lower administrative costs. A longer period guarantees pay-for-performance for ratepayers, but incurs higher administrative costs and risks stalling the solar market since most homeowners and businesses are less likely to invest in solar if they have to wait 20 to 30 years to recoup their investment. We see no reason to depart from the Staff recommendation of a five-year performance payment period for PBI because it will have lower administrative costs and less market risk than a longer payment period. This is a reasonable balance between the current up-front payment structure and longer-term payments over the life of the system.

4. Capacity Factor

In order to provide continuity to the market from the current capacity-based incentive structure, Staff proposed to convert the per-watt up front incentive payment to a PBI payment (in cents per kWh) using a capacity factor to calculate expected system output. Staff initially proposed using a 20% capacity factor, based on CEC-alternating current (AC) ratings.¹⁵

Many parties provided data in support of their recommendations in this area. PG&E states that Itron data from the SGIP program shows an average capacity factor of 16% for systems installed through 2004. They recommend using this capacity factor initially, and then adjusting the capacity factor in subsequent years based on further data. CFC cites U.S. Department of Energy (DOE) and CEC data on capacity factors, showing that in 2004, the average commercial system capacity factor was 14%, and in 2005, the average residential system capacity factor was 16%. According to CFC, these sources project that average capacity factors will reach the 18%-20% range by 2010.

The Joint Solar Parties suggest 18% using CEC-AC wattage, or a higher 20% factor if a different rating method known as "system AC" is used. SDG&E/SoCalGas, and SCE all suggest using 20%. Sun Light suggests starting at 18.5% and then increasing the capacity factor by 10% over the 10 years of the program. TURN suggests incorporating an assumption of a 1% per year degradation factor. Golden Sierra Power suggests a lower capacity factor, because of lower solar production when panels are not matched to the inverter, but it does not propose a specific capacity factor.

We are persuaded that the 20% capacity factor proposed by Staff may have been too optimistic. The data cited by PG&E and CFC indicates as much. The comments of many parties suggest the same, preferring a lower capacity factor based on historic system performance. We accept the recommendation of the Joint Solar Parties, who propose an 18% capacity factor as a reasonable mid-point for the beginning of the program in 2007, based on CEC-AC wattage ratings.¹⁶

At the same time, we are convinced by some commentors that a higher capacity factor can act as a performance target. CFC presents DOE data that capacity factors should reach the 18%-20% range in a few years. We prefer to send a strong signal to encourage increases in system performance over time. Therefore, we will start with an 18% capacity factor for 2007, but we will increase the assumption automatically to 20% beginning with Step 4 of the Incentive Adjustment Mechanism, as discussed in Section VI of this decision. We anticipate that the Step 4 incentive level will not be reached for a few years, which should correspond to the higher capacity factors DOE projects. This will reward those technologies and installations with the best performance. We choose the Step 4 incentive level for this adjustment now in order to calculate and publish the specific incentive levels per kWh that will be paid in upcoming years.

We may consider subsequent changes to the capacity factor assumptions in later program years based on future evaluation findings regarding market trends in system output.

5. Performance Cap

The issue here is whether to put an upper limit on incentive payments to high performing systems as a way to manage the CSI budget. The Staff Proposal suggested capping payments for system performance at 10% above the output produced by the assumed capacity factor.

The utilities generally favor the imposition of some sort of performance cap in order to track and manage budgets, although PG&E suggests a cap should not discourage innovation. SCE, on the other hand, reasons that innovation needs to come from within the solar industry, rather than through the program offering rewards with unlimited upward incentives.

In contrast, the solar industry is unanimous in its opposition to the performance cap provision of the Staff Proposal. The Joint Solar Parties feel that such a performance cap undermines the entire purpose of having PBI. ASPv agrees that a performance cap discourages maximum system output. The solar industry parties suggest the budget can be managed by estimating each system's expected output at the reservation stage and then reserving the appropriate funding for the project at that time.

We agree with the solar industry that the imposition of a performance cap is inconsistent with our overall goal of rewarding systems for higher performance. We wish to send a clear and strong signal that high-performing designs and installations are desirable in this program. We also agree that the CSI budget can be managed if program administrators make a reasonable forecast of incentive payments at the time of system installation based on the design characteristics of each project. In addition, TURN points out that most systems experience a modest degradation of performance over time, which will tend to work in favor of preserving budget funding. Therefore, we do not adopt the performance cap suggested by staff. A solar facility receiving PBI payments will be paid for actual output over the five-year payment period. Nevertheless, the program administrators must operate within their total budgeted CSI funds, as set forth in D.06-01-024. Although we will not put a limit on the incentives paid to any one project through PBI, beyond the 5 MW limit adopted by the Commission in January, the program administrators may not exceed their individual budgets and the total CSI program budget will not be exceeded.

6. Funding Security

The Staff Proposal recommended that the program administrators set aside reserved PBI incentive funds for completed systems in an interest-bearing escrow account. No party commented on this provision in the Staff Proposal.

We agree with Staff that it is important to send a clear signal to the solar industry and the financial community that the money for PBI payments will be available for the full five-year PBI period. Therefore, we will require the each program administrator to deposit the expected PBI payments for all completed solar projects into a single interest-bearing escrow account for each administrator so it is available for the five-year incentive payment period.

7. Discount Rate

In the Staff Proposal, Staff did not include a discount rate when calculating the five year PBI incentive payments. Instead, Staff recommended offering a flat incentive payment for the sake of simplicity.

Parties representing the solar industry, as well as PG&E, disagreed with the Staff Proposal to ignore the discount rate. Neither ASPv nor the Joint Solar Parties propose a specific discount rate, though the Joint Solar Parties embed a 10% rate in some of their calculations. PG&E does not recommend a specific rate either, although it contends PBI should be made equally attractive with an up-front EPBB payment in order to entice smaller systems to opt in to the PBI structure. Sun Light recommends using an 8% discount rate.

We elect to apply a discount rate of 8%. Applying a discount rate is appropriate for several reasons. First, we find it reasonable to offer a comparable net present value for PBI as compared to the current up-front payment structure and not penalize those systems that must wait five years to receive their full PBI payments. Second, as PG&E points out, offering this additional incentive may cause some smaller systems to opt-in to the PBI structure, which furthers the overall program goal of increasing system performance. Finally, the budgetary cash flow consequences of a discount rate will be partially offset by the requirement that program administrators place incentive funds for PBI projects in an interest-bearing escrow account over the five years of the PBI period. In addition to interest growth, the escrow account may grow to the extent systems under-perform based on the average capacity factor used to set incentive levels and budgets.

We choose an 8% discount rate because we find it a reasonable assumption for the range of interest rates different solar buyers might receive on deferred payment streams. ASPv and the Joint Solar Parties suggest a 10% rate, but we prefer the more conservative 8% rate used by Sun Light for its analyses.

Although we will apply a discount rate of 8%, we still wish to keep the incentive payment structure simple. Therefore, in our incentive calculations offered at the end of this section in Table 5, we express the PBI incentive structure in levelized cents per kWh over five years. The incentive level will not change for each individual solar system over the five-year performance period. Instead, the level of the incentive payments has been adjusted to account for the 8% discount rate on a net present value basis.

8. Frequency of PBI Payments

We now address how frequently a solar system owner should receive PBI payments over the five-year period, and whether these payments should be incorporated with utility bills. The Staff Proposal recommended monthly payments, on utility bills, if possible, with quarterly payments if monthly payments prove too administratively costly or burdensome.

The Joint Solar Parties agree with monthly PBI payments to best match cash flow for installment payments on solar systems, and suggested this be paid in an off-bill mechanism to make the incentive most visible to the system owner. SDG&E/SocalGas indicated they plan to support monthly on-bill payment of PBI incentives within a short transition period following this decision, and to add on-bill system performance data on a later schedule. PG&E indicated that while it already reports net energy metering credits monthly on-bill, it could not immediately make incentive payments in the same way. PG&E suggests it could arrange a monthly payment through its off-bill Alternate Billing System. SCE prefers to pay incentives quarterly by a separate check and performance statement. SCE contends an on-bill payment by January 2007 would be "very challenging" based on the time and cost of billing system modifications.

We are pleased to see that most utilities can accommodate some form of monthly PBI payments, whether on or off-bill, and that this comports with the preference of one set of solar parties. We will require PBI payments at this time on a monthly basis, consistent with our desire for frequent customer feedback on system performance. We allow utilities discretion whether to make the payment with the utility bill or separately at this time. Those utilities that can offer monthly payments on or parallel to utility bills are applauded for their abilities to do so at their earliest opportunity. SDREO should make arrangements with SDG&E for monthly on-bill PBI payments, which may be separate from a solar system performance reporting mechanism.

9. Phase In of PBI Structure

The Staff Proposal suggested the option of phasing in the PBI incentive structure over a three-year period, to allow the solar industry time to prepare the market for higher up-front investments under PBI. Specifically, Staff suggested that half of the total incentive could be given up front in 2007, with the remaining half paid based on performance. In 2008, 25% of the total incentive could be given up front, with 75% paid out in PBI. By 2009, all incentives would be through the PBI structure for applicable system sizes.

The Joint Solar Parties favor an even more gradual phase in of PBI than recommended in the Staff Proposal. Under their phase-in proposal, PBI payments would reach a maximum of 50% of the incentive as of 2010, with smaller percentages paid through a PBI mechanism in earlier years, starting at 20% in 2007. The rationale is that such a system would avoid forcing system owners to rely on third-party ownership structures due to their own lack of capital for solar investment. In addition, the Joint Solar Parties argue that larger systems already have an inherent incentive to police the performance of their systems because of the large capital investments associated with their system installations. They also contend PBI will make solar installations more expensive for customers due to the increased costs of financing.

SDREO agrees with the Staff Proposal for a three-year phase in, in order to avoid market disruption. TURN favors a four-year phase in period. Pacific Power Management would phase in PBI in six-month increments over two years, because financing for the larger up front costs is a significant hurdle for commercial customers.

The utilities, CCSF, and ASPv, on the other hand, prefer an immediate switch to a PBI incentive structure. They argue that phasing in a PBI structure will be a confusing, administrative hassle. In addition, they feel that instituting PBI immediately will send a strong signal to the market that the Commission values performance. Further, they argue that PBI is easier to administer, easier to verify, and generally clearer than a phased in approach.

We choose to institute PBI immediately as of January 1, 2007. We note that the solar industry parties differ in their opinions on this topic. Both SCE and SDG&E/SoCalGas indicate that systems over 100 kW to which PBI will be applied only account for about 1% of the total project applications each year. These systems account for about one-third of the installed capacity, however. They are also typically installed by sophisticated building owners, who generally have access to a greater array of financing options than smaller system owners. We are not persuaded that an immediate transition to PBI will cause market disruption. We understand that most systems over 100 kW are already financed at the 60%-70% level. Thus, the transition to 100% financing should not be as significant a hurdle for these types of installations.

Finally, we are persuaded that phasing in the PBI structure will be more confusing to administer and to explain, thereby diluting the clear signal we wish to send to the solar market that we are interested in rewarding high-performance systems and installations. Therefore, we will move to the PBI structure as described herein, for systems 100 kW and larger, starting January 1, 2007. We anticipate moving to PBI for systems larger than 30 kW in 2010.

10. Conclusion

As noted above, the Commission will apply a PBI structure to all systems 100 kW and larger beginning on January 1, 2007. Any other size system may also opt in to the PBI structure. The Commission will require building integrated systems to receive incentives through a PBI structure, but will not require new construction solar installations to be paid through PBI. Beginning in January 2009, we will require systems over 30 kW to be on a PBI incentive structure.

The PBI payments will be made over a five-year period following system installation. Payments should be made on a monthly basis, but payments do not need to be on utility bills at this time. Payments will not be time-differentiated.

Payment levels identified in this decision take into account an 8% discount rate to provide comparability of PBI payments with EPBB payments addressed in the next section of this decision. PBI payments for completed projects will be deposited in an interest bearing escrow account to ensure their security over the period of the expected PBI payments.

PBI incentive levels also incorporate an assumed capacity factor of 18%, calculated on CEC-AC wattage ratings, beginning January 1, 2007. Once Step 4 of the Incentive Adjustment Mechanism is reached, the PBI payment is based on a capacity factor of 20% of CEC-AC wattage. Finally, PBI payments will not be subject to a performance cap for budget purposes.

The adopted PBI incentive rates over the duration of CSI are shown in the table below. ¹⁷ Appendix A provides the calculations supporting the levelized payments in this table.

Table 5

Levelized PBI Monthly Payment Amounts at 8% Discount Rate

		PBI payments (per kWh)
MW Step	MW in step	Residential18	Commercial	Government Non-Profit
119	50	n/a	n/a	n/a
2	70	$0.39	$0.39	$0.50
3	100	$0.34	$0.34	$0.46
420	130	$0.26	$0.26	$0.37
5	170	$0.22	$0.22	$0.32
6	230	$0.15	$0.15	$0.26
7	300	$0.09	$0.09	$0.19
8	400	$0.05	$0.05	$0.15
9	500	$0.03	$0.03	$0.12
10	650	$0.03	$0.03	$0.10

C. Expected Performance Based Buydown (EPBB) Incentives for Smaller Solar Projects

Given our preference to move toward performance-based incentives, we must address the issue of how to develop an incentive structure for systems less than 100 KW that combines many of the optimal performance benefits of PBI with the administrative simplicity of a one-time incentive paid up front at the time of system installation.

The Staff Proposal recommended an incentive methodology, the EPBB, which pays an up-front incentive based on a system's estimated future performance. The methodology considers factors such as solar system capacity ratings and system design (i.e., location, orientation, and shading). Staff proposed EPBB incentives would be paid based on the following formula:

EPBB Incentive = Incentive Rate x System Rating x Design Factor

This EPBB incentive formula would apply initially to systems under 100 kW, and to all new construction, regardless of size. In the case of new construction, staff believes an up-front payment best motivates the builder or developer to include solar in a new building design because these entities may not be the long-term owners or occupants of the property.

Most parties' comments were supportive of EPBB as an incentive structure. Many parties proposed refinements to a number of technical issues, which we address below.

1. System Rating

A system rating attempts to quantify, in wattage, how well the components of a solar generator will perform when combined into a single system. The two primary components are the solar modules and the inverter.²¹ Manufacturers and independent testing facilities assign ratings to panels and to inverters to estimate their expected individual performance. A total system rating can be estimated by factoring in additional system losses due to installation variables and operational losses. In estimating total system performance, the primary differences among the calculations are the system loss input factors. The CEC developed a methodology known as "CEC-AC," which rates system components based on PVUSA test conditions. The PVUSA test facility rating accounts for additional losses, such as those due to system wiring mismatch.

Staff proposes that EPBB calculations use a "System AC" rating, which uses a flat 10% loss factor as a proxy for overall system losses that are likely, yet unaccounted for in other methodologies. The System AC rating is the product of three multipliers: a Photovoltaic Test Condition rating (PTC) developed by the PV testing lab PVUSA, the inverter efficiency rating, and an assumed overall loss of 10%. The CEC-AC rating does not include a 10% loss factor.

Most parties, including Joint Solar Parties, ASPv, Michael Kyes, and PG&E, generally support moving from the current CEC-AC towards a "true system AC" rating system, which corresponds more closely to actual system performance. ASPv cautions, however, against adopting a methodology which assumes a specific loss rate, as loss rates may vary. ASPv argues that it makes more sense to wait until actual system output can be routinely verified before moving to "true system AC" as the basis for incentive payments. ASPv, along with SDG&E/SoCalGas, recommend retaining the CEC-AC rating for now. Joint Solar Parties and PG&E support a system rating similar to the Staff Proposal. SCE recommends a workshop to determine whether a better method exists to determine a solar facility's true peak AC capacity rating, perhaps one which begins with the Standard Test Conditions (STC) Power maximum peak rating. The STC rating is a peer-reviewed international standard to which equipment is tested, and is stamped on all solar panels. Otherwise, SCE supports a verified rating, which can only be determined through system output metering. All parties agree it is essential to maintain consistency, whichever method is adopted.

For now, we will retain the current CEC-AC rating system as the basis for calculating EPBB incentive payments because we are persuaded by the arguments of ASPv that System AC ratings are not verifiable at this time. While System AC ratings may be more accurate, they cannot be verified until systems are installed. This could introduce delay in introduction of the EPBB incentive method. We believe CEC-AC ratings serve as a reasonable proxy until a true system rating or verification method is developed. Additionally CEC-AC ratings for EPBB are consistent with the capacity factor we use to calculate PBI incentives for larger systems. While we agree with parties that the CSI should move towards developing a true system rating, we doubt that it can be developed in time for CSI implementation in 2007.

2. Design Factor

The other major factor in the EPBB incentive formula is the "design factor," which is a ratio comparing a given solar facility's expected to optimal output. The Staff Proposal calls for the EPBB design factor to include measurements for compass orientation, tilt, and shading, calculated at the time the project's incentive application is submitted. The design factor is measured relative to a reference, or "optimally designed," solar system. The factor equals the ratio of simulated solar output for a customer's specific system divided by the simulated output for an identical system designed for maximum energy output.

Design Factor = Simulated solar output of customer's proposed system

Simulated solar output for optimal reference system

In the Staff Proposal, an optimally designed system is assumed to be oriented south, tilted 30º, and without any shading. Staff requested comments on how the EPBB should account for systems with solar tracking mechanisms, which produce more output than a simple fixed panel installation. Additionally, the staff supports utilizing an estimation tool, to be available online and in other forms, to calculate the EPBB design factor, noting that a number of these tools already exist.

The Staff proposed that the design calculation should not consider geographic location. While the Staff Proposal acknowledges that geographical location affects expected system performance due to variations in annual insolation, or sun exposure, around the state, Staff believes that since all ratepayers contribute to the CSI funding, the EPBB structure should neither punish nor reward solar customers based on their location in the state.

There were no parties who agreed with the Staff Proposal to disregard geographic location. Most parties, namely CFC, Golden Sierra, PG&E, SCE, SDG&E/SoCalGas, and TURN, agreed that including geographic location would result in the highest level of overall system production at the lowest cost, even if it means lower incentives for the north coast compared to southern inland zones.

Several parties including Thomas Beach, CFC, Michael Kyes, SCE, and TURN argue that a system oriented to the west reaches peak production during a time more closely aligned to the utilities' system peak demand, and yields energy of higher value, compared to a south-facing system that may reach maximum output at noon or in the early afternoon. Therefore, they argue, the EPBB design factor should be adjusted to properly reward west-facing systems. ASPv believes this approach would result in less overall energy production, as total solar output is maximized when solar panels or collectors face south. SCE suggests that PV systems be given maximum incentives when positioned in either a south or southwestern direction. TURN and PG&E propose that west-facing systems oriented between 180º and 270º receive equivalent design factor ratings. Some argue that an ideal tilt could be determined for each compass direction. In addition, parties recommend determining a system's optimal tilt at location-specific latitudes rather than a standard 30º, citing the wide variance in latitudes from north to south in California.

Only three parties commented on whether to consider tracking capability as a specific design factor. SCE argued against the inclusion, pointing out that a higher performing system will be compensated by higher bill savings. SDG&E/SoCalGas contend that since minimal historical data exists on tracker performance, the Commission should revisit this issue when sufficient data is available.

Parties supported the use of various performance estimation tools, citing the Clean Power Estimator, Solar Pathfinder, and PV Watts. These estimation tools are available in down-loadable software versions. Michael Kyes suggests that a portable table-based reference system is likely to be more reliable than a software-based system, particularly in the early stages of implementation.

Based on the comments, we must consider which elements to include in the EPBB system design factor. First, we must take into account whether the ultimate EPBB goal is to promote peak solar production, or maximum total solar output. We believe it is important to incorporate both approaches to fully achieve the benefits that diversity and flexibility can provide within the total portfolio of CSI projects. We will allow equivalent "optimal" design factors for south, southwest, and west orientations (i.e., for systems oriented with a compass direction anywhere in the range of 180º to 270º). In other words, the optimal reference system in the denominator of the design factor ratio does not have to face south, but can face south, southwest, or west. This will necessitate determining an optimal reference tilt for different compass directions (e.g., a 30º tilt when facing south, but perhaps a higher degree of tilt when facing west ).

Second, there were no parties who proposed a design factor for trackers, and we will not adopt one at this time. As discussed in the PBI section of this decision, systems of any size which utilize trackers will be allowed to opt in to PBI whenever the solar owner believes the PBI payment better rewards the enhanced performance of trackers. We may revisit this issue in the future as historical tracker data becomes available.

Third, parties provided compelling reasons why EPBB should take geographical location into account in the incentive payment calculation. Variability in California's geographic and climate factors affects the levels of solar energy production possible around the state. If we include a geography component in the design factor, this ensures the ratepayer investment results in the highest possible solar energy production per dollar of ratepayer support. With geography included in the design factor, EPBB does a more precise job of estimating likely system performance. This achieves our overall objective of pay-for-performance solar incentives, while still using an up-front incentive payment for smaller solar installations, and parallels the similar outcome obtained from the metered performance structure of PBI for larger systems.

Now that we have determined the elements to incorporate in the design factor, we must address how to turn these design elements into a user-friendly estimation tool that can be incorporated into the CSI Program Handbook and used by program participants. Solar companies, program administrators and EPBB incentive applicants would use this estimation tool, either as software or a set of reference tables, to calculate their incentive payments. In short, we direct the program administrators to ensure a set of technical protocols and a corresponding user-friendly estimation tool (either software or a set of reference tables) are developed to calculate the design factor. The technical protocols and estimation tool should include the following characteristics:

o All systems oriented between 180º and 270º, facing south, southwest, and west, will be treated equally.


o An "optimal orientation tilt" that corresponds to the different acceptable compass directions from 180º to 270º.


o Location-specific criteria which account for varying degrees of solar insolation, based on local climate and geography.


o An "optimal latitude tilt" that relates to local latitude.

To accomplish this, we direct the program administrators collectively to issue a single solicitation for a technical expert or experts(s) to provide a single design factor protocol and an initial estimation tool.²² We state "initial estimation tool" because we do not wish to preclude the development of a variety of estimation tools based on identical design factor criteria, but we want to ensure that at least one is available to calculate EPBB incentives as of January 2007. The program administrators should ensure this protocol and initial estimation tool are incorporated in the initial CSI Program Handbook. We intend to circulate a draft of the initial handbook, according to the schedule in Section IV.B.4.

3. EPBB Verification

The Staff Proposal calls for projects sized between 30 kW and 100 kW to receive a post-construction inspection to verify the accuracy of system data submitted in the original CSI incentive application. The proposal also recommends a verification protocol whereby actual system output would be measured for one month following installation. The program administrator would compare actual output with the expected output. For systems under 30 kW, the proposal recommends random verification. As added protection for performance, the Staff Proposal invited comments on whether there should be warranty requirements beyond those now used in SGIP.

Most parties agree with the need to verify the accuracy of system characteristics described in incentive applications. There was little support, however, to require the administrators to collect actual system performance data. SDG&E/SoCalGas believe on-site inspection that verifies easily observable system characteristics (i.e., number of modules, orientation, and tilt) should be required for all systems. PG&E points out that it already visits each site to inspect system interconnections. The CCSF and SCE recommended requiring warranties on equipment to protect both consumers and ratepayers.

We see two primary issues associated with system verification. The first is administrative feasibility. Verification will add time and cost to program overhead, whether it is performed by third-party verification services or by utility interconnection personnel. If we require the utilities to perform system output verification for all system sizes as part of an interconnection inspection, this will require additional personnel training and time, and has the potential to delay the interconnection process for solar or other distributed generation facilities. We must weigh the potential for higher administrative costs and delays in interconnection practices against the benefits of verifying the accuracy of solar incentive applications. We find it reasonable to require program administrators to verify system characteristics for all systems between 30 kW and 100 kW, as these larger systems will receive significant ratepayer investment through the EPBB incentive. We will adopt the Staff recommendation to require administrators to perform a statistically reasonable random sample of systems under 30 kW to verify their design characteristics. We will not require the administrators to collect one month of system data at this time, but we may revisit this issue in the future, if warranted.

As suggested in the Staff Proposal, project installers who fail three random inspections must be excluded from program participation. Program administrators should incorporate this into the CSI Handbook. In addition, we direct the staff and program administrators to ensure that measurement and evaluation (M&E) plans include an assessment of system output for a sample of solar installations.²³ This may occur through analysis of system output metered data or through alternative, site-specific data collection methods.

The second issue is the availability of trained personnel to perform the verification procedures. All system verification visits must be performed by trained personnel, whether the verification is performed by utility interconnection inspectors, other utility personnel, or contractors. We will require program administrators to develop a training plan for EPBB site inspectors that is consistent among the participating utilities.

As a final protection, we will continue to require equipment providers to provide the five-year equipment warranty already required under the SGIP program rules. We direct program administrators to ensure that all installers continue to report expected annual output performance on program application forms.

4. Conclusion

We adopt EPBB incentive payments for solar projects under 100 kW and all new construction regardless of size, to begin no sooner than January 1, 2007, as set forth in the Table below.

Table 6

EPPB Monthly Payment Amounts

		EPBB payments (per watt)
MW Step	MW per step	Residential	Commercial	Government/ Non-Profit
124	50	n/a	n/a	n/a
2	70	$2.50	$2.50	$3.25
3	100	$2.20	$2.20	$2.95
4	130	$1.90	$1.90	$2.65
5	170	$1.55	$1.55	$2.30
6	230	$1.10	$1.10	$1.85
7	300	$0.65	$0.65	$1.40
8	400	$0.35	$0.35	$1.10
9	500	$0.25	$0.25	$0.90
10	650	$0.20	$0.20	$0.70

We anticipate that in 2010, EPBB will apply only to projects less than 30 kW.

⁷ "Conditional reservation" is defined as the initial application screening and payment of the application fee. As of July 18, 2006, the SGIP program administrators website indicates conditional reservations have reached a level of 46 MW, so it is expected the incentive level will automatically drop to $2.50 per watt before the end of 2006.

⁸ The federal tax credit reverts to 10% on January 1, 2008, unless currently pending legislation extends it.

⁹ The Staff proposed that in order to qualify for a higher incentive, tax exempt entities must certify they will not enter into any third party financing arrangements that qualify participants for federal solar tax credits. (Staff Proposal, p. 13.) Otherwise, tax-exempt entities will receive the commercial rate.

¹⁰ These per watt figures assume a 20% capacity factor and no discount rate.

¹¹ Government/Non-Profit customers must certify they will not enter into any third party financing arrangements that qualify participants for federal solar tax credits. Otherwise, they will be paid at the lower commercial rate.

¹² In addition, tax-exempt entities are not able to take advantage of other tax benefits such as depreciation and interest deductions.

¹³ Staff estimates customer net cost per kWh of 13¢/kWh for tax-exempt entities versus 9.4¢/kWh for a commercial customer. (Staff Proposal, p. 18.)

¹⁴ An Energy Division data request on June 16, 2006 to SGIP Program Administrators indicates SGIP applications from government and non-profit customers have amounted to 45% of the total PV capacity installed through SGIP since the program began in July 2001.

¹⁵ CEC-AC ratings are one means of estimating system output. They are defined and discussed in detail in Section III.C.1 regarding EPBB incentive payments.

¹⁶ We will maintain the CEC-AC rating system, as we discuss in more depth in Section III.C.1.

¹⁷ This table is based on the EPBB per watt rates shown in Table 6, Section III.C.

¹⁸ Residential PBI payments are shown in this table for those cases where a residential solar owner opts in to PBI, presumably because they believe they have a high-performing system.

¹⁹ Incentives for the first 50 MW are disbursed under the 2006 SGIP program and PBI payments do not apply.

²⁰ The PBI payments in Steps 2 and 3 are based on a capacity factor of 18%. Steps 4 through 10 are based on a 20% capacity factor.

²¹ An inverter converts the direct-current (DC) electricity from solar panels into alternating current (AC) electricity.

²² We note the CEC is developing an EPBB solar output estimation tool for use in their New Solar Homes Partnership program, which pays solar incentives to residential new construction. This tool is expected to be available by fall 2006. Once the CEC's tool is completed and operational, the program administrators should consider whether it or some other calculation approach is most appropriate to calculate EPBB payments.

²³ This issue will be addressed more specifically in Phase 2 of this proceeding.

²⁴ The first 50 MW incentives are disbursed at a statewide rate of $2.80 per watt through the 2006 SGIP program.