Payment period options

There is no consensus among parties regarding the correct number of payment years, although most parties advocated a payment period ranging from three to five years. CalSEIA and PV Now argue that due to high customer discount rates, a short payment period is desirable. CalSEIA recommended a payment period of one to three years. PV Now stated a payment period that was too short would have a higher weather risk and instead recommended a payment period from three to five years. TURN advocated a three-year payment period to help offset the cost of financing a PV system and lessen the barrier to entry into the program.

Both SDG&E / SoCalGas Co., and the joint comments of the SGIP program administrators supported a hybrid approach with 50% of the incentive being paid upfront (CBB or EPBB) and the remainder through a PBI over a five to seven year period. Parties that advocated a longer payment period believed it was necessary for ensuring long-term system maintenance, including replacement of broken inverters.

Rationale for EPBB Incentive (not PBI) for Solar on New Commercial Construction

Staff accepts the argument made by DRA that commercial property developers do not benefit directly from energy cost savings offered by PV installations included in new building construction. New construction also lends itself to newer, more innovative technologies known as "building integrated PV" (BIPV).

Incentive Level. Recent research by LBNL suggests that PV installation costs for new construction tend to be lower than for PV retrofits. For example, solar system installation can be integrated into the work schedules of tradespeople already working on site, such as roofers, electricians, and others. However, there is not an adequate database to affirm exactly how much lower the costs of such solar installations are. For this reason we do not propose any downward adjustment of the incentive level to be paid for solar on new construction.

Incentive Structure. The Division of Ratepayer Advocates proposed that incentives for solar on new construction be paid up-front in order to better address solar economics when buildings are either developed for speculative sale, or are built with the expectation of having commercial tenants, and not owner-occupancy. In such cases, the PBI payments and lower utility bills benefits from a solar system would flow through to the tenants, but not to the developer or building owner. The developer/owner would qualify for up-front incentives such as an EPBB incentive as well as a federal solar tax credit. For these reasons, we propose an EPBB mechanism for new commercial buildings.

· For new commercial developer financed solar installations greater than 100 kW, and using conventional solar technologies, the CSI incentive will be paid in the form of an up-front incentive based on the expected performance of the system (EPBB).

· For BIPV applications, it becomes difficult to ascertain the expected performance of the BIPV components when they replace traditional walls or roof materials. Thus for solar BIPV systems on new construction, incentives will be paid on a 100% PBI basis.

Questions and Unresolved Issues:

· Alternative PBI approach: Instead of a hybrid approach, do parties believe we should start immediately with 100% PBI for large systems (100 kW or more), paying the PBI over 5 years?

· Should new construction projects receive a LOWER incentive than retrofits to reflect the likely lower costs of installing solar as part of a new building ?

2.4 Expected Performance Buy Down Incentive -- Small Solar PV Systems < 100 KW

Recommendation:

Rationale:

At the PBI workshop on March 16, 2006, a number of parties expressed support for adopting an expected performance based buy down (EPBB).⁷ Some parties indicated that an EPBB approach strikes an appropriate balance between encouraging system performance and allowing for administrative expediency.

An EPBB system provides upfront payments based upon the expected performance of a given system, taking into account issues such as orientation and shading. An EPBB incentive adjustment mechanism can encourage CSI participants to design systems to maximize expected output. Systems with close-to-optimal design parameters will receive higher incentive payments than systems with lower expected output.

To inform the development of an EPBB incentive structure, LBNL recently conducted a survey of the structural components of the major state and utility customer-sited PV incentive programs in the U.S.⁸ These programs often use one or more of the following design, installation, and location factors either to determine the level of incentive that a system receives or as threshold criteria for whether a system will receive any incentive:

· Panel orientation (i.e. azimuth and slope)

· Panel shading

· Geographical location (i.e. latitude, average cloud/fog cover)

· Installation workmanship (i.e. quality of installation)

Of the 18 programs that were reviewed that use up-front incentives for solar systems, 14 use panel orientation and/or panel shading as minimum design thresholds (i.e., if systems do not meet certain orientation or shading standards, they are simply ineligible for receiving incentive payments). Seven of the 18 programs that were reviewed go one step further and use orientation and/or shading to determine capacity-based incentive levels (i.e., incentives are tied to the expected performance of the systems based on orientation and shading, relative to an optimally oriented system with no shading at the site). Of these 7 programs, one goes ever farther, and ties incentive levels to not only expected performance relative to optimal performance at the site, but also to the geographic location of the site and therefore expected solar insolation. Another of the 7 programs takes an instantaneous measurement of system output to test for installation workmanship, and adjusts the incentive levels accordingly.

Based on this survey, it is clear that many programs either explicitly or implicitly address panel orientation and/or panel shading; only one of the programs addresses specific geographical location within a state. Issues of installation workmanship are most often addressed through post installation inspections.

CSI EPBB Incentive System

The CSI EPBB system will proportionally reduce the CSI incentive paid according to the ratio of expected to optimal output at that site according to the following formula:

CSI Incentive Paid = Incentive Rate x System Rating x Design Factor

System Rating

The System Rating is the AC rating of the entire installed system as defined under PVUSA Test Conditions (PTC). The Rating is calculated as follows:

Estimated Rating = Number and Capacity of PV Modules

x PV PTC Module Rating

x Inverter Efficiency

x Other Losses (Assumed to be 90%)

Design Factor

The Design Factor will be calculated at the time of the application submission. The Design Factor will equal the ratio of simulated output for the system that is specified divided by the simulated output for a system with an identical rating that is oriented south and tilted 30 degrees with no shading:

Design Factor = Minimum Simulated Output for Designed System / Simulated Output for Fixed 30º South-Facing System Without Shading

The model used to calculate the Design Factor will account for orientation, tilt, and shading and will be capable of performing the calculation for a system with multiple orientations/tilts. The Design Factor will not incorporate geographical location. Like panel orientation and shading, geographical location clearly affects the expected performance of a PV system. However, the use of geographical location to calculate incentive levels would discriminate against customers located in areas with less solar insolation. Since the CSI will be funded by all ratepayers of the state's investor owned utilities without regard to geography, we believe that the EPBB incentive structure should be designed so as not to reward or punish customers according to their location. In the alternative, paying a higher incentive for those systems located in areas with greater solar insolation could have the effect of "over-subsidizing" those systems that are already providing the greatest benefit in terms of offsetting retail rates. If we were to apply a geographic factor for the "availability of solar hours, this could amount to an incentive payment range of plus or minus 20 percent around an average California solar location.

Example EPBB Calculations

All of the following examples assume a solar system has an installed cost of $6.50 per Watt (DC). We show the recommended California Solar Incentive payment and the applicable Federal tax credit.

The following examples are based on taxable commercial installations receiving a CSI payment rate of $1.50 per watt (system AC) and varying design factor reduction taking into account panel orientation:

	Example 1	Example 2	Example 3
	Good Rating	OK Rating	Poor Rating
	30º Tilted, South, No Obstructions	Horizontal, No Obstructions	Horizontal, No Obstructions
System Size (kWDC)	50.0	50.0	50.0
Total system cost	$325,000	$325,000	$325,000
(1) CSI Rate ($/kW-AC)	$1,500	$1,500	$1,500
(2) System Rating (kWAC)	38.5	36.5	30.0
(3) Design Factor	100%	89%	89%
EPBB Incentive = (1) x (2) x (3)	$57,750	$48,727	$40,050
Federal Tax Incentive	$97,500	$97,500	$97,500
TOTAL INCENTIVE PAYMENTS	$155,250	$146,227	$137,550

The following example is based on a non-taxable installation receiving a CSI payment rate of $2.25 per watt and no design factor reductions (because of optimal installation).

	Good Rating
	30º Tilted, South, No Obstructions
System Size (kWDC)	50.0
Total system cost	$325,000
(1) EPBB Rate ($/kW-AC)	$2,250
(2) System Rating (kWAC)	38.5
(3) Design Factor	100%
EPBB Incentive = (1) x (2) x (3)	$86,625

The system described above would NOT be eligible for a federal tax credit.

The following example is based on residential installation receiving a CSI payment rate of $2.25 per watt and no design factor reductions (because of optimal installation).

	Good Rating
	30º Tilted, South, No Obstructions
System Size (kWDC)	2.0
Total system cost	$13,000
(1) EPBB Rate ($/kW-AC)	$2,250
(2) Verified System Rating (kWAC)	1.5
(3) Design Factor	100%
EPBB Incentive = (1) x (2) x (3)	$3,465
Federal Tax Credit	$2,000
TOTAL INCENTIVES	$5.465

Estimation Tools

Several software calculation tool options exist for estimating expected and optimal system output that will be used for EPBB incentive calculations. Options include the following:

· web-based tools such as PVWATTS developed by the National Renewable Energy Laboratory,

· shading analysis tools,

· proprietary software programs such as the Clean Power Estimator, and/or

· other generally -acceptable formulae used in other U.S. solar incentive programs.

Verification of Design Information in Applications and/or Performance

All projects 30-100kW must have a post-construction inspection. This will be required to verify the accuracy of installer data submitted in the original application. The EPBB incentive payment will be based on the verified information.

While reservations will be made based on the Estimated Rating, the incentive will not be paid until the system rating is verified.

The Design Factor will not change upon installation if the orientation and shading specifications of the system that is installed match the orientation and shading specifications of the incentive that is applied for. The purpose of the post-construction inspection is to verify the accuracy of installer data submitted in the incentive application. This requirement is consistent with historical practices in California, which have required post-installation inspections for participating systems at least 30 kW in size.

The Verified Rating is determined after the system is installed but before the incentive is paid. Comments are invited on the following approach:

System output will be measured for a one month period to determine what system output should have been based on measured insolation data collected for the same time and location (using satellite or some other location-specific data source) combined with the system's design (orientation, shading) and a simulation model.

· A Verified Rating that is between 95 and 100 percent of the Estimated Rating will be paid the incentive based on the Estimated Rating; this allows for some modeling inaccuracies in favor of the system owner.

· A Verified Rating that exceeds 100 percent of the Estimated Rating will be used in the incentive calculation; this will reward systems that have performance that is higher than expected.

· For a Verified Rating that is less than 95 percent of the Estimated Rating, the incentive will be calculated based on the Verified Rating; this will penalize systems with poor ratings due to faulty equipment or poor installation.

Systems smaller than 30 kW will be subject to random sampling verification. To the extent feasible, one inspection will be conducted for every solar integrator or contractor participating in the program. If any adjustments are necessary, the installer and system owner will be notified of the reasons why. Installers for whom a downward adjustment has to be made based on verified performance will go into a pool that may be subject to a higher percentage of random sampling in the future. Installation contractors and system integrators that repeatedly fail inspections may be excluded from future participation in the CSI.

Customer Class Distinction for Determining EPBB Eligibility

The customer classification on a customer's energy bill will be used to determine if a customer is a residential or commercial for the purpose of determining eligibility for the EPBB incentive (provided that the proposed customer system is less than 100kW).  

· If the customer is classified as a residential customer on their energy bill they will only be eligible to receive the EPBB incentive. 

· If a customer is classified as a commercial or industrial customer on their energy bill and they are placing a system sized less than 100 KW, they will have the option to choose whether to receive an upfront EPBB incentive payment or participate in the PBI payment structure

Questions and Unresolved Issues:

· What performance estimation tools would be most appropriate for EPBB calculations?

· Would that be unduly restrictive for BIPV systems?

· Is the verification protocol described above administratively feasible?

· Must the verification be done on-site, or is it possible to arrange for remote data collection to determine system performance, adjusted for weather factors?

· Can the cost of on-site verification be accommodated within the 10% limit for program administration and evaluation?

· Should verification for small systems be available on an opt-in basis if an applicant believes their technology performs better than average?

· Are there additional actions that should be taken to address installer requirements?

· Are there additional actions that should be taken to address equipment and warranty requirements?

2.5 System Size Adjustment

Recommendation:

· Revise the solar system size limit to 100 % of historical annual energy consumption.

Rationale:

In D.06-01-024, the Commission stated its intent to pay incentives for solar projects used to serve onsite load. In an effort to maximize program funding and avoid paying incentives to oversized systems, the Commission reduced the SGIP solar eligibility size from 200% of peak load to 100% of peak load. This reduction has had the unintended result of restricting the ability of some 2006 SGIP solar projects applicants to take full advantage of net energy metering (NEM) benefits on an annual basis.

We considered two sizing approaches to ensure SGIP projects will be able to optimize net metering:

a) revert back to the 200% peak demand requirement in effect between 2001 and 2005, or

b) base project size on the site's actual or estimated annual energy use.

The table below compares the various system sizing methods, utilizing actual data from a sample of 2006 SGIP solar reservation requests:

Comparison of System sizing Options⁹

Project #	Peak Demand (kW)	200% of Peak Demand (kW)	100% Annual Usage
1	540.6	1081.2	1312.5
2	135.8	271.6	204.1
3	80.0	160	127.6
4	194.0	388	359.7
5	206.0	412	367.1
6	909.6	1819.2	2343.0
7	348.6	697.2	700.8
8	1744.2	3488.4	3037.9
9	175.0	350	211.3
10	238.0	476	478.7
11	188.0	376	300.6
12	56.8	113.6	76.2
13	755.0	1510	309.8
14	89.6	179.2	141.1
15	231.6	463.2	296.5
TOTAL	5892.8	11785.6	10267.1

The table indicates that in most cases, sizing to 200% of peak demand results , in a larger PV system capacity than sizing to annual site energy use. It also results in annual PV output that is uncompensated under NEM rules. Sizing the system based on 100% of annual historical consumption reflects the site's actual usage, maximizes net metering benefits, and prevents potential over sizing of systems relative to annual energy use.

Questions and Unresolved Issues

· With respect to non-solar SGIP projects, should the Commission retain the 100% of peak demand requirement, revert to the 2005 requirement of 200% of peak demand, or apply the same requirement as that proposed for solar of 100% of historical annual use?

3. INCENTIVES FOR NON-PV SOLAR TECHNOLOGIES

Recommendation:

· Provide incentives for these non-PV concentrating solar technologies:

Concentrating PV

Parabolic dish/engine

Parabolic trough

Power tower

· Concentrating Solar Power (CSP) incentive levels and amounts will mirror those for PV.

· Projects must be equipped with a meter capable of measuring displaced energy, including natural gas. Meters for thermal applications must be able to support a BTU to kWh conversion, or supplemental unit converters, along with communication technology to transmit the data to the IOU for incentive calculation and payment.

· Because of near-term advances expected both for CSP technology costs and performance, beginning in 2009, PBI and EPBB incentives for these technologies will begin a steeper decline than for PV, decreasing annually by at least 15%.

·

Rationale:

In a December 12, 2005 joint staff report with the CEC, we recommended that non-PV technologies be eligible for CSI participation. The Commission concurred, and adopted a two-pronged approach to incorporate these types of projects into the program. D.06-01-024 directed SDREO to develop and submit for approval a pilot incentive program for solar water heating, which would be available to SDG&E residential, commercial, and industrial customers. The Commission also stated its intent to explore the details of incentive levels for solar thermal heating, ventilation, air conditioning, and concentrating solar technologies.

This staff proposal is to include incentives for the following non-PV concentrating solar technologies:

· Concentrating PV

· Parabolic dish/engine

· Parabolic trough

· Power tower

We acknowledge the challenge of determining appropriate incentives for customer-side non-PV technologies. California is one of the first states to develop a large-scale solar thermal incentive program for technologies beyond water heaters. Traditionally, small solar thermal incentives are capacity-based, through tax credits, or up-front payments equal to 30-50% of installed costs. For the most part, published capacity factors for CSP technologies are based on installed projects with capacity sizes over the CSI 5 MW maximum size. Our proposal, which includes performance-based incentives for solar thermal projects, is informed through incentive practices in Europe, from Arizona's experience with CPV demonstration projects, and from that state's recently-adopted solar thermal incentive program.

Solar Power Cost and Performance Overview

CSP Technology	Capacity Range	Capacity Factor %	Capital Cost $/kW	Unsubsidized Power Cost Cents/kWh
Concentrating PV	22-140 kW	21-26	5,500	TBD
Dish Stirling	5-50 kW	25.2	2,650	16.7
Parabolic Trough	30-80 MW	22-29	2,877	13.4
Power Tower	30-200 kW	22	2,713	9.0

SOURCE: NREL, Arizona Public Service, and Stirling Energy Systems.

This demonstration data may suggest that "power tower" technology does not require an incentive.

Initially, the CSI will utilize the incentive levels and structure we propose for PV. Our assumption is that solar thermal projects will fall into similar customer categories based on onsite needs and project characteristics. Since solar thermal projects may displace electricity and/or natural gas, payments will be calculated on a system output basis by converting metered BTU into a kWh equivalent, where 3,412 BTUs = 1 kWh. Utility-grade production meters are required on projects sized 100 KW-equivalent and above, and must be capable of measuring and converting displaced energy. Where displaced energy is natural gas, the production meter must have the capability to convert BTUs to kWh and to transmit this data to the applicable utility for incentive calculation and payment.

The general structure for all non-PV solar technologies will be:

· Up to 100 KW: Choice of EPBB or PBI

· 100 KW and over: PBI

We make no incentive recommendations for stand-alone solar water heaters at this time, as SDREO will address this area in an upcoming proposal submitted to the Commission. In the statewide CSI, we propose to include water heating for large commercial installations if the project design includes other solar thermal applications, such as space heating and cooling, ventilation, or process heating and cooling.

We propose to revisit all solar thermal incentives in 2008. By mid-2008, SDREO's solar water heating pilot program will be completed, and the results can be factored into the statewide program. Based on discussions with representatives of solar thermal technologies, staff believes that beginning in 2009, PBI and EPBB incentives for CSP technologies should begin a steeper decline than for PV, and should decrease annually by at least 15% to reflect the anticipated increase in equipment production, and to ensure overall CSI program cost reductions. As with PV, this approach recognizes the differences among small residential, small commercial and large commercial solar thermal applications. As discussed later in this section, large-scale systems provide domestic hot water, space heating and cooling, and process heating and cooling, and displace natural gas and electricity on a large scale. These systems are more complex, and are designed to operate as part of a central system. A long-term PBI for large systems is expected to provide assurance to investors, making it easier to obtain commercial financing.

This approach is also consistent with the Commission's stated goal of developing a long-term, sustainable solar market. We believe this approach will promote development and installation of new solar products at a time when global PV costs are increasing. Silicon, the most expensive PV component, is currently in high demand and short supply. This shortage, combined with worldwide demand for new renewable generation, may create competition for scarce PV cells, which can mean higher costs passed on to California ratepayers. Until such time that solar PV systems offer greater efficiency, concentrating solar thermal technologies can contribute slightly greater efficiencies, and by 2009 at potentially lower prices.

Concentrating PV

PV cells can be more cost effective if optics such as mirrors or lenses are used to concentrate light on the cells. In simple terms, concentrated photovoltaic (CPV) uses inexpensive lenses to leverage PV cell performance. CPV will be eligible to receive CSI incentives.

CPV can have higher efficiencies than flat-panel PV, up to 30%, and can generate about 10 times more power than a non-concentrating PV application. A CPV project should result in lower system costs because it requires only one-tenth the semiconductor material (typically silicon) than flat- panel PV, and because the concentrating optics are cheaper than solar modules. Most CPV projects use tracking mechanisms to follow the sun throughout the day, either through single or dual axis tracking, which allows concentrators to take advantage of as much daylight as possible.

Some companies are now building smaller, higher-efficiency concentrator devices in the 10-200 KW range that may be suitable for commercial rooftops, and possibly even residential settings. Currently CPV project economics need a subsidy, but prices are expected to go down later. in the near term there is an opportunity for CPV to get established over the next two years of the silicon shortage. by 2008 or 2009 when the silicon shortage is expected to resolve, CPV prices and the CSP incentive will be lower. it seems to make more sense that to categorize CPV as PV, and pay the higher incentive to CPV for ten years.

Eligible Solar Thermal Electric Functions

For purposes of the CSI, D.06-01-024 adopted a maximum system capacity size of 5 MW. We propose that solar technologies 5 MW and below are eligible to receive incentives, provided they perform one or more of the following functions:

1. Heating, cooling, and ventilation;

2. Electrical or mechanical power;

3. Any combination of the above by means of collecting and transferring solar generated energy;

4. Swimming pool heaters associated with large projects that also utilize solar thermal for heating, cooling, or water heating purposes.

Eligible solar project applications are discussed in greater detail below.

The collectors, storage units, heat exchangers, and installation must be warranteed for up to five years. The remaining components and their installation must be warranteed for at least one year.

Solar Heating, Ventilation, and Cooling (HVAC)

Active solar thermal space heating, ventilating, process heat, and cooling projects are eligible for CSI participation, including absorption heaters and chillers. All solar HVAC projects must be metered for output to calculate and receive incentives. For this reason, passive solar heating products are not eligible under this program.

In general, the larger the system, the lower the per unit cost of collector area. The economics of an active space heating system improve if it can also heat water in the summer. Significant space heating and/or water heating can be accomplished with the same equipment used for the solar cooling system. Any solar water heating proposal adopted by the Commission must account for these duplicative, complementary design features.

Ventilation preheating systems use air to absorb and transfer solar energy. Solar air collectors preheat the air passing into a heat recovery ventilator or through the air coil of an air-source heat pump. Solar process heat systems typically provide hot water and hot water space heating for large institutions such as schools, office buildings, prisons, and military bases. Ventilation preheating and solar process heat systems are eligible to receive incentives.

Absorption heat pumps use an absorption cycle to provide heating and cooling. A refrigerant is condensed to release its heat, pressure is then reduced and the refrigerant evaporates to absorb heat. If the system absorbs heat from the building's interior, it provides cooling. If it releases heat to the interior it provides heating.

Certain solar thermal applications, such as ventilation air preheating, solar process heating, and solar cooling may be most practical for commercial and industrial buildings, although absorption coolers are now commercially available for very large homes. Since these technologies are being refined continuously, the CSI should not limit their application strictly to non-residential projects.

Questions and Unresolved Issues:

We ask parties to comment on:

· Ways to integrate solar HVAC with the solar water heating program proposed by SDREO.

· Technical solar HVAC specifications for inclusion in the CSI Program Handbook.

· Whether a certification process should be required for BTU-to-kWh equivalent conversion technologies, or for BTU ratings equivalent to solar PV ratings. Alternatively, should we establish the incentives for solar thermal on a per BTU basis?

· Based on current CSP technology costs and performance levels, do we risk over-paying the incentives for CSP technologies? Do they need the same performance-based incentives as PV? Are there effective costs per kWh or BTU produced greater or lesser than solar PV?.

4. INCENTIVE LEVEL TRIGGER ADJUSTMENT MECHANISM OVER 10-YEAR PERIOD

Recommendation:

· A 10% annual ramp down of the incentive is the proposed method for adjusting the incentive level, unless one of the alternatives discussed below is accepted as superior.

· We reserve flexibility to apply special adjustments (downward) to reflect breakthroughs in technology performance and associated cost per unit of output.

· We reserve option to retain an incentive at the same level for a second year if market factors have not produced a lower cost per kWh

· We will provide adequate advance notice of any adjustment OTHER than the annual default 10% reductions

· Separately, as explained in Section 2.2, we will revisit the level of incentive if federal tax incentives change.

Rationale:

Staff considered but rejected four alternative approaches to an annual ramp down of the incentive. These options and our reasoning are described in the text below. Our reasons:

· The approximate 10% annual decline in the incentive level was contained in the January Commission decision., and is consistent with declining the incentive over the program's 2006-2016 period.

· The adjustment of 10% per year is selected because of its simplicity and transparency.

· If we track market price only, we would be reactive, and not seeking to drive down the price.

· If we use more complex economic models to inform the incentive level, we become less transparent, and may not correctly capture or weight market factors.

· If we use an auction approach, we risk being too disruptive to the current market place. Moreover, an auction could result in large commercial systems winning all of the offered incentive funds.

· The proposed mechanism is transparent, and can be tracked via the administrators' weekly website posting of application and budget status.

Many parties have expressed an interest in having the Commission review BOTH the CSI base incentives and trigger adjustment mechanism to reduce incentives. In response to the Commission's March 2006 reduction in the CSI incentive based on a volume trigger having been reached, a number of parties filed comments requesting a review of incentive and trigger issues. One common theme was that market complexities justify the need to develop better analytical tools for a trigger mechanism that accounts for market factors because setting the "ideal" rebate level is very difficult. Comment from parties included the following:

· "SDREO requests that the Commission provide clear direction on how sector-specific market conditions would be evaluated in order to determine when a rebate should be reduced and which market sectors should be evaluated..."

· ASPV stated that "Data collection, transparency and effective communication amongst the parties through an open public process are critically important to ensure that these adjustment points are identified and that the necessary adjustments are made in the most effective way. Transparent data for reasoned, periodic review are required to ensure the success of the CSI."

· Cal SEIA stated that "We are concerned that the proposed triggers insufficiently take into consideration numerous marketplace factors which play a significant role in system prices, and ultimately consumer motivation to purchase. We believe that, particularly given the duration of the proposed program, a much more dynamic evaluation model should be developed for the purpose of determining appropriate incentive reduction timing, which should take into consideration a number of factors beyond the passage of time and the amount of megawatts funded."

In addition to the already-established CSI program budget, variables to consider in setting the CSI incentive level and market trigger mechanism include the following:

(1) time (e.g. incentives drop with the passing of time);

(2) market demand (e.g. incentives drop after reaching pre-determined MW blocks in reservations);

(3) industry economics (e.g. incentives could be linked to the output of an economic analysis tool which takes into account technological innovations such as module improvements and price reductions);

(4) individual customer economics (e.g. to reflect changes in retail energy rates that mirror the value of avoided purchased energy); and

(5) policy changes (e.g. federal and state tax incentives as these affect the tax benefits to different types of solar system owners).

The following are some possible options to more closely tie the CSI incentive level and market trigger mechanism to market forces.

Alternate #1 Increased Monitoring of Market Developments Impacting Installed System Costs

As recommended by various parties, CSI staff and administrators could perform increased monitoring of data regarding average system costs. Staff could also take into account any significant changes affecting customers' installed costs such as global PV module or other component prices. Staff and administrators also could monitor system performance data, since as performance increases and bill savings increase relative to the system size, the required incentive payment should decline. To fully capture the benefits derived from increased system performance will require data from automated monitoring systems and/or the program's measurement and evaluation (M&E) activities. Staff and administrators will need to coordinate this approach with the CSI M&E plan to be addressed in Phase 2 of this proceeding. The method and schedule used to review cost and performance changes could be published in the CSI program handbook.

Alternative #2 Flexible Market Trigger

Another option to more closely tie the CSI incentive level to market forces would be to create a Flexible Market Trigger (FMT) mechanism, which could be used to adjust the incentive rate on a quarterly basis. The FMT would determine when the incentive rate should be reduced based on the volume of applications received relative to the allocated budget for the quarter. The incentive market would be constrained when the dollar value of confirmed incentive reservations exceeds the dollar value of the budget that is available for incentives during that quarter. A confirmed application would be one that has been submitted to the reservation process during that quarter and that has paid the application fee.

When the market is constrained for a given quarter, the incentive for the following quarter would be automatically reduced. The incentive would ratchet down absent specific ALJ approval to retain the previous quarter's incentive level (if there are compelling market conditions. The incentive could be reduced by 10¢ per Watt (or 1¢ per kWh for a PBI structure) for the following quarter. If a market is constrained and too many applications are received during a quarterly period, applications will continue to be accepted in the day/date-stamped order received. Applications not selected could be returned to submitters, or automatically entered into the next quarter's market if the customer so advises.

Alternate #3 Economic Model

An economic model that takes into consideration a variety of data, such as:

- installed cost of solar system

- effective cost of solar system per unit of output (factoring in system performance)

- changes in retail price that host site is avoiding by using solar energy

- setting ratepayer value on a time-of-availability basis for net metered energy (for customers not already on TOU rates)

- tax status of the system owner

- assumption about return on investment or payback levels needed to prompt solar adoption.

Several parties and consultants offered spreadsheet models that applied this kind of approach to determining "optimum" incentive levels for different kinds of solar owners, both taxable and non-taxable. Our preliminary analysis of such models suggested the tendency to pay incentives at higher levels than the market appears to need, based on application volume experience.

Alternate #4 Auction

One approach that was mentioned at the PBI workshop on March 16, 2006 was to let the market establish the CSI incentive level through the use of a periodic (e.g., quarterly) auction. A monthly or quarterly auction of incentive bids from contractors and integrators, offering incentives to the LOWEST incentive levels bid. Through the market clearing mechanism, all relevant market factors would be automatically reflected in the auction clearing price, maximizing the amount of solar installed given the already-established CSI budget. While this maximizes consideration of market factors, it introduces volatility an uncertainty on three fronts:

· for solar system integrators and contractors in their business planning, pricing, and contracting activities,

· for the CSI program budget should incentive bids be higher than expected,

· for buyers.

Variation A: A "Dutch Auction". In such a system the highest-accepted incentive level bid becomes the clearing price for all incentives to be paid that period. In such a system, the monthly or quarterly pro-rata share of the annual incentive budget would be offered for bid.

Variation B: Rolling Auction Bids. From the day after the closing day of the current quarter's auction until the first non-holiday weekday of the following quarter, the CSI Incentive Rate could be set at 95 percent of the clearing Incentive Rate from the previous quarters auction. The Incentive Rate could increase by 1 percent each non-holiday weekday of the following quarter until the program is fully subscribed for that quarter. The program would be fully subscribed for the quarter when applications equal or exceed the quarterly budget. The process would work as follows:

· The Incentive Rate for all applications accepted during the quarter would equal the clearing Incentive Rate for the day that the program becomes fully subscribed; this protects early submitters from being penalized with a lower rate.

· Applications submitted prior to the closing day would automatically receive a reservation; this would reward early submitters for being willing to accept the lower rate.

· Applications submitted on the closing day could be randomly selected until the accepted applications for the quarter equal the quarterly budget.

· Applications not selected could be electronically returned to the applicant so that they can be resubmitted the following quarter.

· Projects would be reserved once the application fee is paid. Accepted applicants would have 7 days to pay the application fee.

· Applications that do not pay the fee or reserved projects that expire from some previous period and the resulting budget that is "freed up" would be added to the following quarter's budget.

· Submitters could have an on-line account where they submit their application electronically and could monitor their own application status.

Although an auction approach averts the inherent difficulties and accuracies of building the model described in #3, we rejected this approach as being too disruptive to the current market place. Moreover, it might result in large commercial systems winning all of the offered incentive funds.

Questions and Unresolved Issues:

· Parties are requested to submit comments regarding the options outlined above.

· If parties feel that an alternate approach is warranteed, they are welcome to supply explicit, detailed proposals for setting the CSI incentive level and adjusting it over time.

· Parties should include discussion of administrative feasibility for all options discussed.

· If an adjustment method other than the 10% per year method is proposed, do parties believe it will be necessary to apply such a trigger on a different basis or different schedule for residential versus non-residential solar systems, or for small versus larger systems, in response to potentially different market segment trends for solar system costs?

·

5. FUNDING LEVELS

Recommendation:

· Annual budgets for the program will follow the revenue requirement schedule published in the January 2006 decision.

· Budgets will be available based on each utility service area's prorated share of funding collection (e.g. PG&E 44%, SCE 34 %, SDG&E 13%, and SoCalGas 9%).

· Budgets could be further divided based on customer class contributions to rates to determine the amounts available each year for award between/among the categories of solar installations and owners. However, as discussed below, this may be administratively difficult to match to the incentive structure and administrator assignments that are based on system size, and not customer class. We have no specific recommendation on this issue yet. *

· In the first half of each calendar year utilities and administrators (to the extent there are non-utility administrators) are free to move funds downward to small customer or system size categories (i.e. transferring funds from large customer funds to smaller customer funds) if demand warrants.

· During the second half of each calendar year, funds may be transferred across customer groups or size categories in any direction on a first come, first-served basis.

· As per the January 2006 decision, the CPUC can authorize administrators to borrow up to 15% of the next year's budget if demand exceeds current year funding. In such a case, and reflecting the overarching principle of managing CSI budgets and adjusting incentive levels in the face of excess demand, any incentives paid out of next year borrowed funds must be paid at the next-year incentive levels.

Rationale:

· We will let each year's funding level act as a "brake" on ratepayer contributions, so as not to use up excessive amounts of funding in earlier years when incentive levels are higher. A table below shows what the annual budget levels would be by utility service area and statewide.

· It is important to preserve equity across service areas by limiting funds available to each utility's pro-rata share of funding. [Question - CEC did NOT do this for their < 30 kW ERP program, where incentives were paid first-come, first-serve, regardless of utility service area. SGIP did impose the per service area limit. Is CPUC required to maintain the latter?]

· We believe it fair to give smaller customers at least the first half of each year to get their applications in without competing for funds with larger customers and systems.

· All current year funds must be exhausted across all customer types and sizes in a particular utility service area before next-year funds can be borrowed ahead.

· Borrowing ahead and using those funds at the next year's incentive level will lead to fluctuation in the incentive offered during individual program years whenever the annual budget is depleted. However, staff believes the tradeoff is reasonable to support a more dynamic balance between market demand and CSI incentive budgets.

IOU Annual Revenue Requirements for CPUC Portion of CSI, and Annual Limit of Funds that Would be Committed at Each Year's Incentive Levels

(in millions of dollars)

Staff has not identified an effective way to reserve funds the first six months of each year for smaller systems versus larger systems (less than 100 kW systems and over 100 kW systems. An under 100 kW system could be put on any kind of customer -- even the largest ones. ). It would be easier to do so for residential versus non-residential systems, although this still would not be perfect. For example, how are multi-family housing buildings of different sizes treated? Most will have individual "residential" meters for the units, and possibly "commercial" meters for common areas and other entire-building energy use?

Questions and Unresolved Issues:

· Parties are invited to comment on whether and how incentive "buckets" could be reserved by type of customer or size of solar system.

· Parties are invited to comment on how to maintain statewide uniformity of incentive levels offered, if solar applications reach their limits I one service areas, but not in all., requiring the "depleted" utility area to borrow against the next year's funds and offer a lower incentive level. Alternatively, should we simply require those applications to wait until the following calendar year?

6. INCENTIVE ADMINISTRATION

6.1 Large systems

Recommendation:

· Current SGIP administrators maintained for now

· Payments based on gross metered performance [the end user still gets paid the allowed NEM credit for power produced in excess of what can be consumed on-site]

· Credit ideally would be applied to a monthly utility bill (electric or gas). However we do not set this as a requirement, and recognize that each utility has different billing systems, with different capabilities, and varying costs associated with offering on-bill performance data and solar performance or NEM credits. Coordination would also be necessary with municipal utilities.

· Incentive payment over 5 years deposited into interest earning account in year that system is completed. This should assure lenders that payouts will be made as per performance agreement.

Rationale:

· Keep the status quo. Minimize any disruption in the market for larger systems.

⁷ The EPBB approach was described in a presentation given by Tom Hoff of Clean Power Research. See workshop slides available at http://www.cpuc.ca.gov/static/energy/solar/060316_pbipresentations.htm

⁸ Lawrence Berkeley National Laboratory recently performed this research. Detailed results of that research will be made publicly available.

⁹ Assumptions: Residential Load Factor 0.45

Small Commercial Load Factor 0.47

Agricultural Load Factor 0.35

Capacity Factor 17%

Inverter Efficiency 95%

¹⁰ Funding for 2006 is in addition to existing SGIP solar-related budget of approximately $42 million.