AB 1787 conditions cost recovery for large electrical corporations’ smart‑meter and billing system upgrades on offering at least one optional dynamic rate tariff to customers who pay those incremental costs — and on a suite of data‑access, anti‑cost‑shift, and cybersecurity protections. The bill ties tariff components to time‑varying distribution constraints and day‑ahead wholesale market conditions, requires secure APIs for customer and third‑party access to near‑real‑time usage data, and directs the commission to monitor and mitigate cost shifting between participating and nonparticipating customers.
This matters because it converts smart‑meter deployments into a statutory vehicle for dynamic pricing while imposing explicit rules to preserve cost causation, protect vulnerable customers, and open utility meter data to third‑party energy managers. Utilities, load‑serving entities (including CCAs and ESPs), third‑party providers, and regulators will face new technical, compliance, and tracking requirements if the commission allows recovery of upgrade costs after January 1, 2027.
At a Glance
What It Does
The bill requires a large electrical corporation that receives commission approval to recover smart‑meter upgrade costs (post‑Jan 1, 2027) to offer at least one optional dynamic rate tariff to customers who pay those incremental costs. The tariff must include time‑varying distribution and generation components and nonbypassable charges, and the commission must impose data‑access and anti‑cost‑shift safeguards.
Who It Affects
Large electrical corporations (over 100,000 service connections), load‑serving entities that set generation rates for participating customers, community choice aggregators and electric service providers (protected from commission rate regulation), third‑party energy managers seeking meter data access, and residential and commercial customers with newly installed smart meters.
Why It Matters
The bill embeds dynamic pricing into the smart‑meter upgrade playbook while demanding operational changes: utilities must provide secure APIs and realtime meter access, track subscription and wholesale costs separately, and the commission must evaluate adoption, load shifts, and distribution‑level impacts to prevent hidden cross‑subsidies.
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What This Bill Actually Does
AB 1787 makes a single, conditional trade: if the California commission approves a large utility’s smart‑meter and billing‑system upgrade and allows the utility to recover those incremental costs, the utility must offer at least one optional dynamic rate tariff to customers who bear those costs. The bill limits the obligation to customers with smart meters installed on or after January 1, 2027, and it sets minimum tariff components: a time‑varying distribution charge (where feasible), a time‑varying generation charge for bundled customers tied to day‑ahead wholesale conditions, and nonbypassable charges.
The commission must also consult FERC on transmission‑ratemaking consistency.
Data access and interoperability are central. If the new meters include wireless capability, the utility must let customers pull their own usage data directly from the meter in real time via a customer‑owned device.
The utility must also expose usage data through a secure API so customers can authorize qualified third‑party providers — certified to NIST cybersecurity standards and commission privacy rules — to manage onsite energy demand. The bill expressly forbids a utility from favoring its own customer program administrator over a qualifying third party.To protect people who do not opt into dynamic pricing, the bill requires the commission to make the same time‑varying delivery/transmission/distribution rates available to bundled and unbundled customers in the same geographic areas, to ensure parity for customers with the same demand levels, and to periodically evaluate and mitigate cost shifting.
The commission must collect and review adoption metrics, time‑differentiated sales volumes, revenue and cost‑shift estimates, and any disproportionate effects on vulnerable residential customers. If a utility offers an energy subscription option (a fixed quantity at a fixed rate) as part of the tariff, the utility must track the associated wholesale costs separately and assign them to participating bundled customers so nonparticipants aren’t subsidizing the subscription.Operationally, the bill leaves generation‑rate setting for participating customers to their load‑serving entity, not the utility, and it clarifies that the commission cannot regulate CCA or ESP retail rates or terms.
Definitions clarify who is a "large electrical corporation," what an "energy subscription option" is, and the cybersecurity and privacy standards a "qualified third‑party provider" must meet. Overall, the statute ties regulatory approval and cost recovery to explicit consumer‑facing and monitoring obligations intended to enable dynamic pricing while limiting cross‑subsidies and preserving data portability.
The Five Things You Need to Know
The bill conditions utility cost recovery for smart‑meter upgrades (installed on or after Jan 1, 2027) on offering at least one optional dynamic rate tariff to customers who pay those incremental costs.
A qualifying dynamic tariff must include (1) time‑varying distribution charges reflecting distribution constraints where feasible, (2) a day‑ahead wholesale‑linked time‑varying generation charge for bundled customers, and (3) nonbypassable charges.
Utilities must provide customers real‑time meter access (including direct meter reads for wireless meters), a secure API for usage data, and allow customers to authorize NIST‑certified third‑party providers to access that data.
The commission must periodically evaluate and mitigate cost shifting between participating and nonparticipating customers, collect adoption and time‑differentiated sales data, and assess effects on vulnerable residential customers.
A "large electrical corporation" is defined as having over 100,000 service connections; load‑serving entities set generation rate options for participating customers; the commission may not regulate CCA or ESP retail rates under this section.
Section-by-Section Breakdown
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When utilities must offer an optional dynamic tariff
These paragraphs establish the trigger: if the commission approves a large utility’s smart‑meter and billing upgrades on or after Jan 1, 2027 and allows cost recovery, the utility must offer at least one optional dynamic rate tariff to customers whose incremental upgrade costs are recovered. It also limits the obligation to customers who actually receive a newly installed smart meter on or after that date, clarifying the roll‑out cohort and avoiding retroactive imposition of tariffs on customers with older meters.
Required components of the dynamic tariff
This subsection specifies minimum tariff mechanics: a time‑varying distribution rate tied to distribution‑level constraints where the commission deems feasible, a time‑varying generation rate for bundled customers linked to day‑ahead wholesale conditions, and nonbypassable charges. From an implementation perspective, the distribution component will require utilities and the commission to develop distribution‑level costing methods and feasibility tests before those signals can be applied.
FERC coordination on transmission ratemaking
The commission must consult FERC to ensure the dynamic tariff’s implementation does not conflict with federal transmission ratemaking authority. Practically, this creates a coordination requirement early in design to avoid jurisdictional mismatch over transmission charges embedded in time‑varying rates.
Conditions for approving cost recovery — customer choice and data access
The commission cannot approve smart‑meter upgrade cost recovery unless customers who pay those costs can choose between the dynamic tariff and a flat or TOU rate, and unless utilities enable direct meter access and secure API access for customer data. Utilities must provide timely usage data to other load‑serving entities and must permit customers to authorize qualified third‑party providers to act on their data. The commission must police discriminatory behavior by utilities favoring their own program administrators, tying approval to concrete interoperability and nondiscrimination conditions.
Anti‑cost‑shift rules and monitoring
This section requires parity in time‑varying delivery/transmission/distribution rates for bundled and unbundled customers in the same geographic area and mandates periodic commission evaluation of cost shifting, including scenario analysis. The commission must collect detailed adoption and sales data, revenue and cost‑shift estimates, and assess disproportionate impacts on vulnerable residential segments. If an energy subscription option is offered, costs for wholesale resources supporting that subscription must be tracked separately and borne by participating bundled customers.
Role of load‑serving entities, preemption and definitions
Subdivision (e) assigns generation‑rate setting for participating customers to the customer’s load‑serving entity. Subdivision (f) preserves CPUC limits on regulating CCAs and ESPs under existing sections. Subdivision (g) defines key terms — large electrical corporation (>100,000 connections), qualified third‑party provider (NIST cybersecurity certification plus commission privacy standards), energy subscription option, and smart meter — which set the technical and regulatory thresholds for compliance.
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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
- Customers with new smart meters who opt into dynamic tariffs — they gain access to time‑differentiated price signals and can lower bills if they shift load, and they get technical means (direct meter access, secure API) to control their usage or enable third‑party management.
- Qualified third‑party energy managers and demand‑management vendors — the bill creates a clear pathway (secure API + NIST requirement) for third parties to access near‑real‑time customer data and offer services, expanding the market for energy‑management products.
- Grid operators and distribution planners — time‑varying distribution charges and data on customer adoption/behavior improve visibility into distribution constraints and provide a price signal to relieve congestion at the local level, aiding operational planning and DER integration.
Who Bears the Cost
- Large electrical corporations — they must implement secure APIs, preserve meter‑level direct access, track subscription wholesale costs separately, and defend nondiscrimination practices; those system and administrative costs may be significant even when recoverable.
- Nonparticipating customers and vulnerable residential customers — while the bill mandates monitoring and mitigation, short‑term adoption patterns risk leaving nonparticipants to pick up fixed costs if load shifts reduce utility revenue allocated to them.
- Load‑serving entities and CCAs — LSEs must set generation‑rate options for participating customers and may need to develop new rate products and wholesale hedging strategies; CCAs and ESPs will also need to handle incoming usage data and privacy compliance when their customers adopt dynamic tariffs.
Key Issues
The Core Tension
The central tension is between using smart meters to send granular price signals that lower system costs and integrate distributed resources, and protecting nonparticipating and vulnerable customers from bearing hidden costs; enabling broad data access further empowers energy innovation but raises cybersecurity and privacy risks that require costly technical safeguards.
The bill balances dynamic pricing rollout with protections, but it leaves key implementation details to the commission. How the commission defines "feasible" for time‑varying distribution charges, what statistical or modeling standards it will require for periodic cost‑shift evaluations, and the frequency and granularity of required reporting are open questions that will determine whether ant‑subsidy protections are meaningful or merely informational.
The practical cost of building secure APIs, certifying third‑party providers to NIST standards, and maintaining nondiscriminatory program administration could be substantial and may fall unevenly across utilities of different sizes and legacy IT architectures.
Privacy and cybersecurity trade‑offs are real. The bill mandates customer access and third‑party authorization while requiring NIST certification and commission privacy rules, but it does not specify which NIST profile or how to certify compliance in the context of mass consumer access.
That gap creates operational uncertainty for utilities, third parties, and the commission about acceptable authentication flows, data minimization, and liability for breaches. Finally, the bill assumes dynamic rates will produce meaningful load shifts; if adoption remains low, the monitoring obligations may reveal cost shifts that are politically and legally difficult to rectify without redesigning rates or imposing new surcharges.
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