# Implementing Golden State Energy: A Governance, Financing, and Delivery Architecture for Public Power in California

## TL;DR
- California already has a public, ratepayer-owned utility on the books — Golden State Energy (GSE), created by SB 350 (Hill), the Golden State Energy Act, signed June 30, 2020 (Chapter 27, Statutes of 2020) — but it remains an empty shell: unstaffed, unfunded, never incorporated, and legally dormant unless PG&E fails. The state can and should build out its governance, financing, and delivery architecture now, but the ambitious "statewide public takeover" vision must be trimmed to what state and federal law actually permit.
- The lawful core of the concept is strong: tax-exempt municipal financing gives public power a real cost-of-capital advantage (a 210-basis-point spread per the Public Finance Network/APPA), publicly owned California utilities charge far lower rates (SMUD reports rates "on average more than 50% lower than those of neighboring PG&E"), and existing vehicles (CCAs, municipal utilities, the I-Bank, the CAISO/EDAM markets) already accomplish pieces of the design. But several signature ideas — forcing contractors to eat all overruns, mandating local voter ratification of a state project, taxing residents to fund a utility, and imposing state revenue-sharing on interstate/export sales — collide with the Spearin doctrine, Propositions 13/218/26, and the Federal Power Act and dormant Commerce Clause, respectively.
- The highest-value near-term moves are: fund a statutory feasibility/transition study (as SB 332 (Wahab) and city resolutions urge), capitalize and staff GSE through the I-Bank pathway SB 350 already authorizes, use revenue bonds (not taxes) secured by utility revenues, deliver capital through progressive design-build with calibrated risk-sharing rather than absolute risk-shifting, and treat nuclear as a "shelf-ready" framework contingent on repeal of the Public Resources Code § 25524.2 moratorium.

## Key Findings

**1. GSE exists but is skeletal.** SB 350 added Division 1.7 (commencing with § 3400) to the Public Utilities Code and amended the Code of Civil Procedure (§§ 564, 568.6, 1240.655), the Government Code (Article 10, § 63049.70 et seq.), and PU Code §§ 748.1, 3289, 3292. It authorizes the Governor to incorporate GSE as a nonprofit public benefit corporation under the Corporations Code, with eminent domain and bond-issuance authority, an initial board of five gubernatorial and four legislative appointees (transitioning to six ratepayer-elected and three appointed), and I-Bank financing eligibility. But it activates only on a "material bankruptcy" (PG&E's failure to exit Chapter 11), CPUC revocation of PG&E's CPCN, or a PG&E asset-sale process — none of which occurred, because PG&E emerged from bankruptcy July 1, 2020. GSE has never been incorporated, staffed, or funded.

**2. Public financing works; tax financing largely does not.** Publicly owned utilities finance capital primarily through tax-exempt revenue bonds repaid by ratepayers, not taxpayers. Proposition 13, Proposition 218, and Proposition 26 make tax- or fee-funding of a utility very hard, but a revenue-bond/ratepayer model sidesteps most of these constraints because utility service charges tied to actual usage are generally not "taxes."

**3. Eminent domain is available but slow and contested.** California's Eminent Domain Law lets a public entity condemn IOU distribution/transmission assets, but valuation and "more necessary public use" fights are protracted, as South San Joaquin Irrigation District's decade-plus effort shows. The California Supreme Court is currently resolving the standard of review (Town of Apple Valley). PG&E's rate base — roughly $69 billion in 2025 — signals the sheer scale of a full acquisition cost.

**4. Federal law caps state ambitions on wholesale and export sales.** Under the Federal Power Act, FERC has exclusive jurisdiction over wholesale and interstate transmission rates; FERC v. EPSA and Hughes v. Talen confirm states cannot set or adjust interstate wholesale rates. A California public entity would sell into CAISO markets under FERC market-based rate authority, and can now access the Extended Day-Ahead Market (EDAM), live May 1, 2026. Exports to Mexico/Canada require federal (DOE/FPA § 202(e)) authorization.

**5. The county/CCA layer is real and growing but cannot own wires without a new pathway.** California has 25 operational CCA programs serving more than 15 million customers — over a third of the state's population — across 200+ jurisdictions; Clean Power Alliance is the largest. CCAs procure power; the IOU still owns the poles and wires. Taking over distribution requires eminent domain plus LAFCO approval — not a power CCAs currently hold.

**6. Labor is a swing vote and a legal constraint.** SB 350 protects PG&E workers by requiring GSE to assume collective bargaining agreements and pension obligations. IBEW Local 1245 is strongly opposed to a takeover. Prevailing wage, PLAs/CWAs, MC3 pre-apprenticeship, and High Road Training Partnerships give the state ready-made workforce architecture.

**7. Cost-overrun risk cannot be fully dumped on contractors.** The Spearin doctrine and California's differing-site-conditions statute (Public Contract Code § 7104) mean an owner who supplies plans warrants them and must issue change orders for genuinely different conditions. Absolute risk-shifting raises bids and invites disputes. The lawful discipline tools are progressive design-build, calibrated pain-share/gain-share, liquidated damages, performance bonds, and the statutes of repose (CCP §§ 337.1 and 337.15).

**8. Nuclear is legally frozen but can be designed now.** PRC § 25524.2 bars new nuclear certification until a federally approved high-level waste disposal method exists — still unmet in 2026. Diablo Canyon's life was extended by SB 846. Vogtle 3 & 4 (~$35B vs. ~$14B, ~7 years late) is the cautionary benchmark.

**9. The prosumer layer is governed by NEM 3.0 / net billing.** Export compensation now tracks the Avoided Cost Calculator, roughly 75% below retail. Municipal utilities (SMUD, LADWP) set their own rules — so a public entity has latitude the IOUs lack.

## Details

### 1. Golden State Energy — Current Status and Statutory Detail

**Enactment and structure.** SB 350 (Hill; principal coauthors Dodd, Holden, McGuire) was approved by Governor Newsom June 30, 2020 and filed with the Secretary of State the same day, becoming Chapter 27, Statutes of 2020, effective as urgency legislation. The act is described in its own text as: "An act to amend Section 564 of, and to add Sections 568.6 and 1240.655 to, the Code of Civil Procedure, to add Article 10 (commencing with Section 63049.70) to Chapter 2 of Division 1 of Title 6.7 of the Government Code, and to amend Sections 748.1, 3289, and 3292 of, to amend and renumber Section 855 of, to add Sections 222.5 and 713 to, to add Article 7 (commencing with Section 1825) to Chapter 9 of Part 1 of Division 1 of, and to add Division 1.7 (commencing with Section 3400) to, the Public Utilities Code, relating to energy."

**Powers.** SB 350 authorizes the Governor, or the Governor's designee, to "incorporate Golden State Energy as a nonprofit public benefit corporation pursuant to the Nonprofit Public Benefit Corporation Law … for the purpose of owning, controlling, operating, or managing electrical and gas services for its ratepayers." GSE is empowered to (a) acquire PG&E, including by eminent domain — "Golden State Energy may take possession of Pacific Gas and Electric Company property upon deposit in court, and prompt release, of an amount determined by the court to be the probable amount of just compensation"; (b) issue debt/bonds to facilitate the acquisition, with a rate covenant to debtholders, subject to CPUC application/approval; and (c) receive financing from the California Infrastructure and Economic Development Bank (I-Bank) or a special purpose trust — SB 350 specifies that "the financing of energy and project costs on behalf of Golden State Energy is in the public interest and eligible for financing by the I-Bank." GSE would be regulated by the CPUC (including its rates), unlike municipal utilities.

**Board.** As reported at passage, the initial board would include five members appointed by the Governor and four by the Legislature; future boards would transition to six members elected by GSE customers and three appointed by the Legislature and Governor.

**Activation triggers.** SB 350 permits GSE to act only upon (A) the earliest occurrence of a "material bankruptcy" (defined to include "failure to confirm on or before June 30, 2020, a plan for Pacific Gas and Electric Company to exit bankruptcy"), (B) a CPUC determination that PG&E's Certificate of Public Convenience and Necessity should be revoked (per the processes in CPUC Investigation I.19-09-016), or (C) PG&E's initiation of a sale process for its assets/stock. Within 45 days of any trigger, the CPUC must open a proceeding to develop rules to regulate GSE. Because PG&E's reorganization plan was confirmed and it exited bankruptcy on July 1, 2020, none of the triggers fired.

**Labor protections.** SB 350 provides that GSE's acquisition of PG&E "shall not be subject to Sections 851 to 854, inclusive" (the ordinary CPUC transfer-approval provisions) if GSE agrees to: "(a) Assume, take assignment of, and be bound by all collective bargaining agreements and related obligations, including pension and benefit agreements, then in effect that cover the business being acquired. (b) Assume any obligations for funding under pension plans then in effect." IBEW Local 1245, which represents about 12,000 PG&E workers, secured this language and remains, in its own words, "STRONGLY OPPOSED to the takeover of PG&E by the State of California or takeover of parts of PG&E by cities and counties," stating "IT IS LOCAL 1245's MOST URGENT DESIRE THAT SB 350 NEVER TAKES EFFECT."

**Current implementation status (2026).** GSE remains unincorporated, unstaffed, and unfunded. As the City of Berkeley's February 11, 2025 resolution put it, "SB350's design is skeletal, and GSE remains unstaffed and unfunded, creating significant uncertainty in the state's ability to act quickly in the event of PG&E's unexpected failure."

**Advocacy and follow-up.** The Reclaim Our Power (ROP) Utility Justice Campaign, anchored by the Local Clean Energy Alliance, published "The Case for Golden State Energy: Benefits of a Nonprofit Utility Model to Serve California" (June 2024) and, with the SF LAFCo, "An Outline for a Comprehensive Statewide Analysis of Golden State Energy" (September 2023). Berkeley's February 2025 resolution (Councilmembers Tregub and Lunaparra) supports commissioning a state feasibility study; San Francisco (Supervisor Connie Chan) and Richmond passed similar resolutions. In the Legislature, SB 875 (Wiener, 2025-26) sought to ease municipalization via eminent domain but failed passage in committee (April 21, 2026, 4-1). SB 332 (Wahab, 2025-26), the Investor-Owned Utilities Accountability Act — sponsored by Reclaim Our Power and the Center for Biological Diversity — would require the CEC to select a research institute to study transitioning the IOUs to a public/nonprofit/cooperative model (analysis due January 1, 2029); it was held in committee in August 2025. (Note: SB 332 is authored by Sen. Aisha Wahab; Sen. Josh Becker chairs the Senate Energy, Utilities and Communications Committee that heard it.)

### 2. Financing Architecture

**Municipal bond mechanics and cost advantage.** Public power capital is financed chiefly through tax-exempt municipal bonds — mostly revenue bonds secured by the utility's own service revenues, rather than general obligation (GO) bonds backed by taxes or general tax revenue. The federal tax exemption on interest lowers borrowing costs materially: the American Public Power Association, citing the Public Finance Network, reports a roughly 210-basis-point spread — in APPA's July 2025 Issue Brief, "a 30-year AAA tax-exempt municipal bond would have a 3.90 percent rate, but a comparably rated taxable bond would have a 6.00 percent rate." Municipal bonds "are ideally suited to finance capital-intensive and long-lived public infrastructure, such as the assets of a public power utility, with the cost of investments repaid over time by the customers who use the infrastructure." IOUs also lack public power's tax advantages; conversely, IOUs deduct interest and depreciation and pay dividends, which public entities avoid. Note the important caveat, raised in a Congressional Research Service analysis, that a public authority "can always go to the taxable market for capital" — tax-exempt status is an advantage, not a precondition.

**Case studies.** LADWP is the largest US municipal utility, governed by a mayor-appointed board with rates subject to LA City Council approval; SMUD (created 1946) is governed by an elected seven-member board that sets its own rates without CPUC approval. Both charge markedly less than the IOUs — SMUD's own residential-rates page states its rates are "among the lowest in California, and on average more than 50% lower than those of neighboring PG&E" (based on 750 kWh/month). Nebraska is the only 100% public-power state, with no investor-owned utilities, a structure built 1933–1946 under Senator George Norris; it is the only state where no agency approves retail rates (they are set by public boards under a "fair, reasonable, and nondiscriminatory" standard). The Tennessee Valley Authority (TVA Act of 1933, 16 U.S.C. § 831 et seq.) is fully self-financing — "TVA is fully self-financing, funding virtually all operations through electricity sales and power system bond financing … makes no profit and receives no tax money." The Bonneville Power Administration (Bonneville Project Act of 1937) markets federal hydropower to 136 preference customers (public/coop utilities first) and finances via US Treasury borrowing authority raised to $17.7 billion by the 2021 infrastructure law; it is federal precisely because it markets federally owned hydropower and borrows from the Treasury. Long Island Power Authority is the cautionary tale: a public authority that contracts out operations (to PSEG Long Island through 2030 under a 2025 extension), it has faced criticism over duplicative governance and storm-response failures (Tropical Storm Isaias, 2020), and New York has debated full municipalization to eliminate the contractor layer.

**California tax/fee constraints.** Proposition 13 (1978) capped property taxes and required two-thirds legislative votes for state taxes. Proposition 218 (1996, the "Right to Vote on Taxes Act," Articles XIII C and D) requires voter approval for taxes and imposes procedural requirements (notice, hearing, majority protest, and often ballot) on property-related fees and assessments; property-related fees may not exceed the cost of service. Proposition 26 (2010) broadened the definition of "tax" so that most levies are taxes unless they fit an enumerated exception (e.g., reasonable regulatory-cost charges, or charges for a benefit/service not exceeding reasonable cost). The practical implication: a utility funded by usage-based service charges, repaid via revenue bonds, is generally lawful, but funding a utility through a new tax or a property-related parcel charge would trigger Proposition 13/218/26 supermajority and voter thresholds. Sinclair Paint Co. v. State Board of Equalization (1997) upheld regulatory "mitigation" fees, illustrating the narrow fee/tax line.

**Eminent domain valuation.** Just compensation in California is measured by fair market value (CCP § 1263.010 et seq.); IOUs argue for going-concern/fair-market value while condemning agencies favor depreciated rate base, and the methodology gap can be enormous. In South San Joaquin Irrigation District v. PG&E (2023) 95 Cal.App.5th 819, the Third District held PG&E could defeat a taking by disproving, by a preponderance, one of the District's statutory findings, and that courts exercise independent judgment on "more necessary public use." Town of Apple Valley v. Apple Valley Ranchos Water (2025) created a district split (deference to the agency), and on April 23, 2025 the California Supreme Court granted review to resolve the standard. SB 875 (Wiener) would have made the "more necessary public use" presumption conclusive for public entities in PG&E's territory and removed the litigation-expense exposure, but it failed in committee. San Francisco's attempt to buy PG&E's in-city assets stalled amid PG&E delay and valuation disputes. Boulder, Colorado's decade-long municipalization effort (ultimately abandoned in 2020) is the out-of-state warning about cost and duration.

**IOU rate base scale.** PG&E's weighted-average rate base was about $69 billion in 2025, with a $73 billion five-year capital plan targeting a $106 billion rate base by 2030. This is the order of magnitude of a full acquisition price for PG&E alone; SCE and SDG&E add tens of billions more. The delivery (transmission and distribution) portion, which a public entity would target, is the majority of the rate base and of residential bills.

### 3. Federal Preemption and Market Structure

**FERC/state division.** The Federal Power Act vests FERC with exclusive jurisdiction over wholesale sales and interstate transmission; states regulate retail sales, distribution, and resource procurement. FERC v. EPSA (2016) upheld FERC's authority over wholesale demand-response compensation and confirmed the FPA "prevents the creation of a regulatory no man's land." Hughes v. Talen Energy Marketing (2016) struck down Maryland's subsidy program because it "adjust[ed] an interstate wholesale rate," invading FERC's turf — but the Court stressed its holding was "limited" and does not foreclose state measures "untethered to a generator's wholesale market participation." Implication: California may own generation, subsidize clean energy, and set retail rates, but it may not dictate or share in FERC-jurisdictional wholesale rates.

**Selling interstate.** A GSE-type entity would obtain FERC market-based rate authority and sell into the CAISO markets, the Western Energy Imbalance Market (WEIM, live since 2014, $5.6B+ cumulative benefits), and the Extended Day-Ahead Market (EDAM), which launched May 1, 2026 with PacifiCorp; Portland General Electric joins October 2026, with more entities in 2027+. Note BPA chose the competing SPP "Markets+" over EDAM in March 2025, fragmenting the Western market.

**Exports to Mexico/Canada.** Cross-border electricity exports require DOE authorization under FPA § 202(e) (16 U.S.C. § 824a(e)); cross-border transmission facilities historically required a Presidential Permit under Executive Order 10485. In May 2025 DOE proposed to streamline § 202(e) authorization and rescind the Presidential Permit requirement for electric transmission facilities — a development to watch, as final adoption status should be verified.

**State conditions on interstate/export sales.** A state attempt to impose revenue-sharing or conditions on interstate or export power sales faces both FPA preemption (per Hughes) and dormant/foreign Commerce Clause scrutiny; economic protectionism favoring in-state interests over interstate or foreign commerce is presumptively invalid. The closest lawful alternative is to capture value through ownership and generally applicable, non-discriminatory retail policy rather than through conditions tethered to wholesale/export transactions.

### 4. The County and CCA Delivery Layer

**Landscape.** Community Choice Aggregation was authorized by AB 117 (2002, Migden) and refined by SB 790 (2011, Leno). Per the California Community Choice Association, there are 25 operational CCA programs serving "more than 15 million customers—over one-third of the state's population—in 200+ cities and counties" (2025). CCAs procure generation; the IOU continues to own and operate transmission and distribution and to handle metering, billing, and maintenance. CCAs are political subdivisions/JPAs. Their economics are shaped by the Power Charge Indifference Adjustment (PCIA), an "exit fee" charged to departing (CCA) load so that remaining bundled IOU customers are not left holding the cost of resources the IOU procured on the CCA customers' behalf; the PCIA is a perennial CCA-IOU battleground because it can erode CCA rate advantages.

**Clean Power Alliance.** CPA, established in 2017 by Los Angeles County and the cities of Rolling Hills Estates and South Pasadena as a JPA, is the largest CCA in California and one of the largest load-serving entities in the state. Per its own materials, it is "the locally-operated electricity provider for 38 communities and more than one million customers across Los Angeles and Ventura Counties," led by CEO Ted Bardacke. It is governed by a board of one elected official per member agency and has a community advisory committee. It cannot serve LADWP territory, which is a chartered municipal monopoly.

**Can CCAs own wires?** Not today without a new step. CCAs are statutorily generation-procurement entities. To own distribution, a CCA (or county) would need to acquire the wires by eminent domain and obtain LAFCO approval to expand its powers/service — there is no existing streamlined pathway, and the SSJID litigation shows how hard the acquisition step is.

**Service-territory/county mapping.** IOU service territories do not track county lines: PG&E covers most of northern and central California (70,000 square miles, ~16 million people); SCE covers much of the south and central coast/inland; SDG&E covers San Diego and southern Orange counties; and municipal islands (LADWP, SMUD, Anaheim, Riverside, etc.) carve out large populations. This patchwork means a "county delivery layer" would have to be assembled parcel-by-parcel against multiple IOUs.

**County authority and new districts.** Counties do not currently own/operate electric distribution as a general matter. Forming a new public utility district or municipal utility district (under the Public Utilities Code's district acts and the Government Code) requires LAFCO approval and typically local voter approval, plus acquisition of any incumbent facilities.

### 5. Workforce and Labor Architecture

**Prevailing wage and labor agreements.** California prevailing wage law (Labor Code § 1720 et seq.) applies to public works over $1,000; DIR apprenticeship requirements attach at $30,000+. Notably, § 1720 excludes work done directly by a public utility company but expressly includes work for "irrigation, utility, reclamation, and improvement districts" — so how GSE is structured determines coverage. Public entities structure Project Labor Agreements (PLAs) and Community Workforce Agreements (CWAs) to set terms, local hire, and apprenticeship utilization.

**Pipelines.** The Multi-Craft Core Curriculum (MC3) is NABTU's nationally recognized, typically 10-week pre-apprenticeship that yields an industry-recognized credential and feeds state-approved apprenticeships under the Division of Apprenticeship Standards. California delivers MC3 through the California Workforce Development Board's High Road Construction Careers initiative, funded via SB 1 and cap-and-trade revenues; CWDB has directed over $20 million to these partnerships. High Road Training Partnerships are the state's model for equity-focused, union-aligned workforce development. The California Conservation Corps and state apprenticeship system provide additional public workforce models.

**Union positions.** IBEW Local 1245 is opposed to municipalization/takeover (above). The California State Building and Construction Trades Council generally supports prevailing-wage, PLA-covered public construction. Only trained/certified workers may perform on-site electrical work, which is precisely why a build-out must be paired with apprenticeship pipelines.

**Funding training pipelines.** Workforce development funds (WIOA, state High Road funds, cap-and-trade) can lawfully support paid pre-apprenticeship and training pipelines; unemployment insurance trust funds are more narrowly restricted to benefit payments, though the state's workforce agencies coordinate UI claimants into training.

### 6. Project Delivery and Cost Discipline

**Risk-shifting tools and their limits.** Owners use fixed-price/lump-sum, design-build and progressive design-build, EPC turnkey contracts with performance guarantees, liquidated damages, performance/payment bonds, and target-price contracts with pain-share/gain-share. But an owner cannot lawfully force a contractor to absorb all overruns. Under the Spearin doctrine (United States v. Spearin, 248 U.S. 132 (1918)), an owner that provides plans and specifications impliedly warrants their adequacy: "if the contractor is bound to build according to plans and specifications prepared by the owner, the contractor will not be responsible for the consequences of defects in the plans and specifications." General "visit-the-site/check-the-plans" disclaimers do not defeat the warranty. California's differing-site-conditions statute (Public Contract Code § 7104) requires a differing-site-conditions clause in public trench/excavation contracts over four feet and requires the owner to investigate and issue a change order for genuinely different subsurface conditions; California courts have refused to let general disclaimers circumvent § 7104.

**Empirical evidence on risk-shifting and overruns.** Shifting all risk to contractors raises bids: RAND Journal of Economics research (Luo, 2025, Florida DOT data) finds fixed-price contracts raise the cost of project risk (exceeding 3% of construction cost) and that risk-averse contractors demand a "sizable risk premium." Bent Flyvbjerg's megaproject research finds cost overruns are "both prevalent and predictable," averaging roughly 45% for rail, 34% for bridges/tunnels, and 20% for roads, driven by optimism bias and strategic misrepresentation; his remedy, reference-class forecasting ("outside view"), is mandatory in the UK Treasury Green Book. (Flyvbjerg's database methods are academically contested, a caveat worth noting.)

**Statutes of repose.** California caps an owner's ability to hold a contractor liable: CCP § 337.1 gives a four-year repose for patent defects and § 337.15 a ten-year absolute repose for latent defects, both running from substantial completion (with fraud/willful-misconduct exceptions).

**Fee-shifting.** Prospective agreements shifting litigation costs as a condition of public contracting face enforceability limits; California courts scrutinize such provisions, and public-contracting law constrains the state's ability to disclaim liability for owner-caused changes.

**Bottom line.** The lawful discipline package is: progressive design-build to align design and price, calibrated target-price with pain-share/gain-share caps, robust liquidated damages and bonds, reference-class forecasting on budgets, and reliance on the statutes of repose — not an unenforceable "contractor eats everything" mandate.

### 7. Nuclear — Shelf-Ready Framework

**The moratorium.** PRC § 25524.2 bars certification of new nuclear plants until the CEC "finds that there has been developed and that the United States through its authorized agency has approved and there exists a demonstrated technology or means for the disposal of high-level nuclear waste." This condition is unsatisfied as of 2026. The moratorium survived preemption challenge in Pacific Gas & Electric Co. v. State Energy Resources Conservation & Development Commission, 461 U.S. 190 (1983), because it rests on economic (waste-disposal) grounds, not radiation-safety grounds reserved to the Atomic Energy Act. Recent bills (e.g., AB 65; AB 2647 (Calderon) to carve out advanced reactors) would amend or repeal it, but none has repealed § 25524.2.

**Federal waste status.** The Nuclear Waste Policy Act of 1982 (as amended 1987) designated Yucca Mountain, but the program is stalled; the federal government missed its 1998 acceptance deadline; the Nuclear Waste Fund holds roughly $40 billion. Consolidated interim storage licensing (Texas/New Mexico) was contested in the Fifth Circuit and reached the US Supreme Court in 2025 (status to verify). No federally approved disposal method exists — so § 25524.2's condition remains unmet.

**Diablo Canyon.** SB 846 (2022) reversed the planned retirement; the CPUC approved extended operations (through 2029/2030), and PG&E sought a 20-year NRC license renewal, backed by a $1.1 billion federal Civil Nuclear Credit award and a state loan. Operation beyond 2030 still requires legislative action.

**Advanced licensing and the Vogtle benchmark.** The NRC's new 10 CFR Part 53 framework becomes effective April 29, 2026; NuScale's uprated US460 SMR design received Standard Design Approval May 29, 2025. Realistic first US SMR operation is 2029–2032. Vogtle Units 3 & 4 in Georgia are the sobering benchmark: as Grist reported, they became "the most expensive infrastructure project of any kind in American history, at a total cost of $35 billion … nearly double the original budget … seven years behind schedule" (against an original 2009 estimate near $14 billion; Unit 3 commercial July 2023, Unit 4 in service April 2024). A "shelf-ready" framework (site, licensing pathway, financing, workforce) can be designed now to execute only if the moratorium lifts.

### 8. The Prosumer / Distributed Generation Layer

**NEM history and NEM 3.0.** California moved from NEM 1.0 and 2.0 (near-retail export credits) to NEM 3.0 / the Net Billing Tariff (CPUC D.22-12-056, effective April 15, 2023), which values exports using the Avoided Cost Calculator — a cut of roughly 75% from near-retail compensation — driving a surge in battery attachment. The CPUC Public Advocates Office estimates the NEM "cost shift" to non-solar customers, in its August 22, 2024 fact sheet: "This cost burden … to non-rooftop solar customers of Pacific Gas and Electric, Southern California Edison, and San Diego Gas & Electric has risen from $3.4 billion annually in 2021 to $8.5 billion annually by the end of 2024, and it will continue to grow." Solar advocates contest the framing. The California Supreme Court ordered reconsideration of aspects of NEM 3.0 in August 2025, with proceedings ongoing.

**County/CCA variation.** IOU customers are bound by the statewide NEM 3.0 tariff, but municipal utilities (SMUD, LADWP) set their own compensation — so whether export rates could lawfully vary by county/CCA depends on the entity's status: a municipal/public utility has latitude, while CCAs operating within IOU wires generally take the CPUC framework. Full geographic variation is practically constrained by the need for consistent interconnection and cost-allocation.

**Community solar and FITs.** AB 2316 (Ward, 2022, Chapter 350) created a Community Renewable Energy Program requiring at least 51% low-income subscribers; implementation (CPUC D.24-05-065) has slipped toward 2026. Virtual net metering and feed-in tariffs exist but are limited.

**Rule 21 and the over-the-fence rule.** Interconnection is governed by Rule 21. PU Code § 218 defines "electrical corporation" and, via the "over-the-fence" rule (§ 218(b)), excepts a person selling power to no more than two immediately adjacent properties without an intervening public street — the key line a master-planned development or microgrid must not cross to avoid becoming a regulated utility. The core "own use" exception excludes from regulation electricity "generated on or distributed by the producer through private property solely for its own use or the use of its tenants and not for sale or transmission to others." Submetering "safe harbors" (e.g., mobilehome parks/apartments) let owners bill tenants at capped rates without utility status. Recent bills (SB 1215, SB 1018) sought to widen these exemptions for microgrids and large clean-energy loads.

### 9. Governance and Precedent for State-Owned Enterprises

Public power authorities succeed when insulated from annual budget politics and funded by ratepayer revenues (TVA, BPA, SMUD, Nebraska's boards), and struggle when governance is fragmented or operations are contracted out without clear accountability (LIPA). The federal preference-customer model (BPA, TVA) — a wholesale public entity selling first to local public distributors — is the cleanest template for a "state wholesale entity + local public distribution" design, but it is federal because it rests on federal hydropower and Treasury borrowing. The US Postal Service is an instructive but cautionary governance analogy: its universal-service obligation, congressional oversight, and (until the 2022 Postal Service Reform Act) a retiree-health prefunding mandate of roughly $5+ billion/year that drove most of its losses show how universal-service mandates and overpromised retiree obligations can financially cripple a public enterprise. The lesson for GSE: fund pensions/retiree health realistically, insulate rates from politics, and avoid the LIPA "hollow authority" trap.

### 10. Multi-Stage Project Approval

The CPUC has existing authority to approve staged/phased infrastructure through Certificates of Public Convenience and Necessity, and coordinates with the Integrated Resource Planning process and CEQA review; staged approval and proof-of-concept phases are feasible within these tools. However, making local voter approval (a county ballot resolution) a precondition of a state infrastructure project is legally fraught: the state generally cannot delegate a binding veto over state projects to local electorates, though local approval is routine for forming local districts and for local funding measures. The CEC's Integrated Energy Policy Report is the vehicle for state energy planning; SB 332 (Wahab) would direct the first formal state study of transitioning the IOUs to public/nonprofit ownership (due 2029), and the UCLA Emmett Institute's June 2025 report "Power Struggle: California's Electric Utility Ownership Dilemma" and the LAO's January 2025 rate analysis provide the current evidentiary base.

## Recommendations

**Stage 1 — Study and capitalize (2026–2027).**
1. Enact and fund a statutory feasibility/transition study (the SB 332 mechanism, or a budget-directed CEC/LAO study), selecting a recommended ownership model (public benefit corporation vs. public utility district vs. cooperative) and a valuation methodology. *Benchmark to advance: a completed study identifying a preferred model and a credible acquisition cost range.*
2. Direct the Governor to incorporate GSE and appoint the initial nine-member board now, and appropriate seed funding (staff, counsel, financial advisors) — using the I-Bank pathway SB 350 already authorizes rather than new taxes. *Benchmark: GSE incorporated, board seated, executive director hired.*

**Stage 2 — Finance and pilot (2027–2029).**
3. Structure all capital as tax-exempt revenue bonds repaid by ratepayers; avoid any tax- or parcel-fee model that triggers Proposition 13/218/26 thresholds. *Threshold that would change this: only if a court or counsel confirms a specific charge qualifies as a non-tax service fee.*
4. Pursue a bounded pilot — e.g., a single distribution acquisition or a greenfield public generation/storage project — using progressive design-build with calibrated pain-share/gain-share, liquidated damages, and reference-class-forecasted budgets. Do not attempt to contractually force contractors to absorb all overruns (Spearin/§ 7104 make it unenforceable and bid-inflating). *Benchmark: pilot delivered within a reference-class-forecasted budget envelope.*
5. Register GSE for FERC market-based rate authority and CAISO/EDAM participation; do not attempt to condition or tax interstate/export sales (FPA/Hughes preemption). *Benchmark: FERC MBR authority granted; EDAM participation agreement executed.*

**Stage 3 — Scale via the CCA/county layer (2029+).**
6. Where local acquisition of wires is desired, pair eminent domain with LAFCO approval and local voter authorization for the local entity — not as a veto over the state project, but as the lawful route to forming or empowering a local public distributor. Use the SB 875 reforms (if revived) to reduce IOU litigation leverage.
7. Build the workforce architecture in parallel: MC3 pre-apprenticeship + High Road Construction Careers + PLAs/CWAs, funded through cap-and-trade and workforce (not UI) funds, and honor SB 350's CBA/pension assumption to bring IBEW 1245 to the table.

**Nuclear (contingent).** Design a shelf-ready nuclear framework (site, Part 53 licensing pathway, financing, workforce) now, executable only upon repeal of PRC § 25524.2 and a federal waste-disposal solution. Budget against the Vogtle benchmark (~2.5x cost, ~7 years late), not vendor estimates.

## Caveats
- GSE is dormant, not dead: its powers exist only on statutory triggers that have not occurred. Building it out proactively requires new legislation and appropriations, not merely executive action, on several points.
- Several 2025–2026 legal questions are unresolved and material: the California Supreme Court's Apple Valley eminent-domain standard-of-review case; the fate of SB 875 (failed 2026) and SB 332 (held 2025); the NEM 3.0 reconsideration; the CIS/Yucca waste-storage litigation reaching the Supreme Court; and DOE's May 2025 proposal to rescind cross-border transmission Presidential Permits. Currency should be re-verified before drafting statutory language.
- Cost estimates for acquisition are order-of-magnitude only; PG&E's ~$69B rate base is a proxy, and going-concern vs. rate-base valuation disputes could swing the number by tens of billions.
- Flyvbjerg's overrun statistics are influential but methodologically contested; treat the averages as directional.
- Some rate-comparison figures ("more than 50% lower") derive from utility and advocacy sources (SMUD's rates page, the Berkeley resolution, ROP); the SMUD and LAO figures are the most authoritative and should anchor any published comparison.