This bill sets the California Public Utilities Commission’s framework for administering the California Solar Initiative (CSI). It authorizes monetary incentives limited to the first megawatt (AC) of a solar system, requires a scheduled annual decline in incentive levels (not less than an average 7% per year), and directs a shift toward performance-based incentives for larger systems.
The statute also prescribes funding and charge rules: a $3,550,800,000 program-wide cap with specific allocations to investor-owned utilities, local publicly owned utilities, and a New Solar Homes Partnership; a $50,000,000 cap on RD&D spending; prohibitions on charging natural gas customers; and exemptions that prevent CARE and FERA participants from bearing program charges except where nonbypassable charges apply. These mechanics determine who pays, how incentives are earned, and how the state targets low-income and new-construction markets.
At a Glance
What It Does
Authorizes declining monetary incentives for qualifying solar systems (limited to first 1 MW AC), mandates a performance-based incentive regime for larger systems, and allows time-variant tariffs to align production with system peaks. It sets a total program cap, allocates funding among utilities and programs, and restricts funding sources.
Who It Affects
Investor-owned utilities (PG&E, SCE, SDG&E) and local publicly owned utilities; solar installers, developers, and third-party owners; low-income households targeted by CSI subprograms; and non-CARE/FERA ratepayers who fund the program.
Why It Matters
The bill defines the financial architecture of California’s large-scale incentive program: how incentives decline, who pays, and how funds are split across market segments. That combination shapes project economics, utility administration burdens, and the distributional effects of solar policy.
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What This Bill Actually Does
The statute gives the CPUC authority to award monetary incentives for up to the first megawatt of alternating-current output from eligible solar energy systems and directs the commission to follow Energy Commission eligibility criteria until the Energy Commission finalizes them. It requires the commission to set a schedule of declining incentive levels (an average decline no less than 7% per year) and to publish that schedule at least 30 days before the first reduction.
There is an explicit carve-out that the incentive for installations under Section 2852 goes to zero on a later date, creating staggered sunset points for different program strands.
On how incentives are paid, the law forces a move to performance-based rebates: by January 1, 2008, 100% of incentives for systems 100 kW and up must be paid on measured output, and at least 50% of incentives for systems 30 kW and up must be performance-based; the commission may require or encourage performance-based approaches for smaller systems. The statute allows the commission to design performance incentives to be more generous than capacity-based payments and authorizes finance options that must ultimately be repaid by the consumer or through rebate streams.The statute couples incentives with energy-efficiency requirements for existing buildings: before an existing building qualifies for a CSI incentive, the commission (with the Energy Commission) must require reasonable, cost-effective efficiency improvements, with exemptions or limitations for low-income residential housing.
The commission may also adopt time-variant tariffs to encourage installations whose peak production lines up with California’s system peaks, and it may exclude participating customers from certain residential rate caps up to a defined baseline quantity.On funding, the law draws bright lines: it forbids imposing any charge on natural gas consumption to fund CSI and restricts program charges to customers who are not participating in CARE or FERA (with a narrowly defined exception for nonbypassable system benefits charges). It caps the total program cost at $3,550,800,000 and apportions funding among IOU-administered programs, local publicly owned utilities, and the New Solar Homes Partnership, while authorizing a limited low-income continuation pot and a specified process for encumbering and disbursing remaining funds.
The CPUC must also coordinate any research, development, and demonstration grants with the Energy Commission and may not spend more than $50,000,000 on that category.
The Five Things You Need to Know
The commission will pay incentives only for the first megawatt (AC) generated by an eligible solar energy system, with the commission determining eligibility until the Energy Commission issues rules.
Incentive levels must decline at an average rate of at least 7% per year and (with a separate exception for installations under Section 2852) reach zero by specified sunset dates (general sunset by Dec. 31, 2016; certain installations by Dec. 31, 2021).
By January 1, 2008 the statute requires that 100% of incentives for systems ≥100 kW be performance-based, and at least 50% of incentives for systems ≥30 kW be paid on measured output; the CPUC may encourage or require performance-based payments for smaller systems.
The statute caps total CSI spending at $3,550,800,000 and allocates $2,366,800,000 to IOU-administered programs, $784,000,000 to local publicly owned utilities, and $400,000,000 to the New Solar Homes Partnership, plus a $108,000,000 low-income continuation authority.
The law prohibits funding CSI via natural gas consumption charges and excludes CARE and FERA participants from program charges (except to the extent costs come from a nonbypassable system benefits charge).
Section-by-Section Breakdown
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Monetary incentives limited to first megawatt and eligibility authority
This provision gives the commission power to award monetary incentives for up to the first megawatt (AC) produced by a solar system and ties system eligibility to Energy Commission criteria once those criteria exist. Practically, it restricts incentive exposure per system and centralizes the eligibility determination process during the interim period before the Energy Commission’s criteria are in place.
Performance-based incentive framework
Requires the CPUC to implement a performance-based incentive program with hard thresholds: by Jan 1, 2008, 100% of incentives for systems ≥100 kW and at least 50% for systems ≥30 kW must be output‑based. The section permits the CPUC to vary treatment by customer class, to set performance-based rates above capacity-based levels, and to approve financing options repaid via consumer payments or rebate flows — which affects how third-party ownership and leasing models are structured.
Energy-efficiency preconditions for existing buildings
Mandates that reasonable, cost-effective efficiency improvements be required for existing buildings before they receive CSI incentives, allowing exemptions or limitations for low‑income housing. This ties solar incentives to building performance upgrades, shifting part of program focus from generation only to integrated energy savings, and introduces an extra administrative step for retrofit projects.
Time-variant tariffs to align solar output with system peaks
Authorizes the commission to develop time‑variant tariffs that maximize incentives to install systems whose peak production coincides with statewide peak demand, and permits excluding participating customers from certain residential rate caps up to 130% of baseline quantities. Importantly, the provision stops short of authorizing mandatory time‑variant pricing for non‑solar customers, limiting the tariff’s application to incentivized participants.
Solar thermal allocation and RD&D limits
Subdivision (b) allows awarding incentives specifically for solar thermal and water‑heating devices up to $100.8 million. Subdivision (c) caps RD&D allocations at $50 million, requires Energy Commission collaboration to avoid duplication, and mandates public‑meeting approval for RD&D grants. Together these provisions fence off how much public money goes to non‑PV technologies and to exploratory projects.
Funding source restrictions and exemptions for CARE/FERA
Explicitly bars levying charges on natural gas consumption or gas ratepayers to fund CSI, and limits program charges to customers not enrolled in CARE or FERA, with the caveat that costs recovered via a nonbypassable system benefits charge may affect CARE participants. That creates a legal and administrative boundary for cost recovery and protects specified low‑income assistance program participants from direct program charges.
Total program cap, allocation mechanics, and low‑income continuation
Sets a $3,550,800,000 ceiling on total CSI costs and breaks funding into defined buckets: $2,366,800,000 for IOU programs (including tracking accounts), $784,000,000 for local publicly owned utilities, and $400,000,000 for the New Solar Homes Partnership (IOU‑collected). Subdivision (f) lets the CPUC continue collecting a charge to fund a $108,000,000 low‑income residential pot once certain amounts are expended or reserved, and allows IOUs to reallocate unspent general‑market funds to lower the IOU collection obligation subject to CPUC approval. These mechanics constrain total liability and prescribe encumbrance and disbursement deadlines for program continuation.
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Explore Energy in Codify Search →Who Benefits and Who Bears the Cost
Every bill creates winners and losers. Here's who stands to gain and who bears the cost.
Who Benefits
- Residential and commercial system owners — The incentive structure (first‑MW cap and performance‑based rebates) improves project economics for systems sized to optimize the first‑MW payout and rewards actual energy production, favoring well‑sited, efficient installations.
- Solar developers and installers — Clear decline schedule, performance metrics, and funding buckets give market participants visibility on rebate levels and program segments (new homes, low‑income, POU markets) to target business plans and financing arrangements.
- Low‑income households targeted by CSI-specific programs — The statute carves out low‑income provisions and a $108M continuation reserve for low‑income residential housing, which prioritizes access to incentives and exemptions from program charges.
- New construction market and homebuilders — A $400M New Solar Homes Partnership, administered by the Energy Commission and possibly continued by IOUs, creates a dedicated funding stream that supports solar on new homes and shapes builder standards and incentives.
Who Bears the Cost
- Non‑CARE/FERA residential ratepayers — The law restricts charges to customers outside CARE/FERA, concentrating program funding pressure on that population rather than spreading it across all ratepayers.
- Investor‑owned utilities (PG&E, SCE, SDG&E) — IOUs must administer programs, track funds in accounts, meet encumbrance/disbursement deadlines, and may be required to continue program administration after Energy Commission funds are exhausted, creating operational and potential cash‑flow burdens.
- Local publicly owned utilities and their customers — POUs must collect and administer their $784M allocation, making their customers liable for those program charges and requiring local administration infrastructure.
- Regulatory agencies — CPUC and Energy Commission carry coordination obligations, eligibility determinations, and public‑meeting approvals for RD&D grants, increasing administrative workload and rulemaking complexity.
Key Issues
The Core Tension
The central tension is between fiscal containment and market certainty: the statute constrains public exposure with a hard program cap and aggressive incentive declines to limit ratepayer cost, while simultaneously trying to preserve deployment incentives and equity through performance payments and low‑income carve‑outs—an approach that reduces budget risk but can accelerate the timing and complexity of program decisions in ways that may suppress projects or unevenly distribute costs.
The statute tries to thread three goals—cost containment, targeted support, and performance alignment—but implementation opens multiple tensions. Capping total program spending at $3.55 billion and mandating steep annual declines in incentives improves fiscal predictability but risks undercutting market momentum if declines outpace cost reductions or grid‑value pricing.
The performance‑based pivot increases economic efficiency by paying for delivered kilowatt‑hours rather than nameplate capacity, but it raises measurement, verification, and billing complexity (interval metering, production accounting, dispute resolution) and may disadvantage small systems or customers without access to high‑quality siting and meter data.
The funding and equity decisions are consequential. Excluding CARE and FERA customers from program charges protects the most vulnerable ratepayers, yet it shifts costs onto a narrower non‑CARE cohort and could make the program politically and financially harder to sustain.
Prohibiting gas charges for CSI funding preserves sectoral clarity but narrows options for cross‑program financing of hybrid or electrification projects. Finally, limiting RD&D to $50 million and restricting how much can go to research versus direct incentives could slow innovation or force hard trade‑offs between deploying mature PV and investing in emerging technologies like storage‑coupled systems.
Operationally the statute leaves open practical questions: how to treat systems with multiple inverters or aggregations when applying the "first megawatt" rule; how the CPUC will verify performance across diverse ownership models (host-owned vs. lease/PPA); and the interaction between CSI performance payments and other compensation mechanisms (net metering successors, resource adequacy value). Those implementation details drive real project economics but are handled by rulemaking rather than text, making outcomes hinge on later CPUC and Energy Commission choices.
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