Small and Medium Commercial Customers in California have Options in a High Rate Future

The commercial electricity landscape in California in 2026 is defined by a profound structural shift in how grid costs are recovered and billed to small and medium enterprises (SMEs). For facility managers, the historical predictability of volumetric energy costs has been replaced by a multifaceted regime of wildfire mitigation surcharges, infrastructure hardening capital recovery, and increasingly aggressive demand-based pricing. This report provides a comprehensive analysis of the rate trajectories for Southern California Edison (SCE) and Pacific Gas and Electric (PG&E), focusing on the specific tariff structures that define the operational reality for commercial customers. As Southern California Edison implements rate escalations widely projected to reach over 12% for many segments, the ability of facility managers to decode these regulatory signals will determine the long-term competitiveness of their operations.

The Regulatory Foundation: General Rate Cases and the Revenue Requirement

To understand the 2026 rate environment, it is necessary to examine the mechanisms of the General Rate Case (GRC), the primary vehicle through which the California Public Utilities Commission (CPUC) authorizes the total revenue a utility may collect from its customer base. The "revenue requirement" represents the sum of the utility’s operating expenses and a fair return on its invested capital, including the massive investments required for grid modernization and wildfire risk reduction.

Southern California Edison: The +12% Trajectory

In late 2025, the CPUC issued decisions concluding multi-year proceedings regarding SCE’s revenue requirement for the 2025–2028 period. While the final authorized baseline was lower than SCE's initial 23% request, it still represented a double-digit increase over previous authorized levels.

The 2026 fiscal year is particularly volatile for commercial customers due to the implementation of a 24-month recovery mechanism of the GRC revenue requirement. Because the GRC decision was delayed, SCE must utilize this surcharge to collect the delta between the rates it actually billed in early 2025 and the higher levels approved for the test year. This "catch-up" recovery, combined with the authorized post-test year increase for 2026, creates more than a 12% rate spike reported by industry analysts and forward-looking forecasts.

Within the GRC, increases in wildfire mitigation, grid modernization, and infrastructure upgrades to support increasing demand are putting rate pressure on the Small and Medium Commercial customer classes. Additionally, SCE began its securitization cost recovery of the wildfire bonds for the Thomas Fire and Montecito Debris Flow in January 2026 and has issued its proposed recovery for AMI 2.0 implementation which would start in 2026 as well.

Pacific Gas and Electric: Revenue Stabilization and the B-Schedule Shift

Pacific Gas and Electric enters 2026 following a period of intense rate growth. For PG&E, the 2026 landscape is defined by the final implementation phases of its 2023–2026 GRC, which prioritized grid hardening and the undergrounding of thousands of miles of power lines. However, PG&E has entered a "stabilization" phase where bundled rates are projected to see a modest decrease.

On January 1, 2026, PG&E implemented Advice Letter 7797-E, which projected a 5% to 6% decrease in bundled electric rates.5 This reduction is driven primarily by the Energy Resource and Recovery Account (ERRA) forecast, which reflects lower anticipated costs for energy procurement.

Despite these bundled decreases, facility managers utilizing Community Choice Aggregators (CCAs) or Direct Access (DA) providers must remain vigilant. While the PG&E generation rate falls, the Power Charge Indifference Adjustment (PCIA)—the fee paid by CCA customers—and delivery surcharges are projected to jump significantly, potentially by 19% to 23.2% for non-bundled customers, which includes a large swath of California.

Specific Rate Analysis

Southern California Edison: Commercial Tariff Analysis

The rate escalations at Southern California Edison are distributed based on the "marginal cost of service" for each rate group. Small and medium commercial customers typically fall under the General Service (GS) schedules, segmented by peak demand.

Small Commercial: Schedule TOU-GS-1 ( < 20 kW)

Schedule GS-1 is the default for small enterprises with demand that does not exceed 20 kW. For these customers, the 2026 rate structure is primarily sensitive to volumetric usage ($/kWh) rather than demand charges. Under TOU-GS-1, the peak period occurs from 4:00 p.m. to 9:00 p.m. during summer weekdays. Facility managers must recognize that the +12% increase is most acutely felt in the "On-Peak" energy rates, which can reach more than $0.60 per kWh during the hottest summer months. Avoiding these rates will be necessary to keep energy costs down.

Medium Commercial: Schedule TOU-GS-2 (20 kW – 200 kW)

Medium-sized facilities face the added complexity of "Demand Charges," calculated based on the maximum power (kilowatts) drawn from the grid during any 15-minute interval. The 2026 GS-2 rate structure features a critical distinction between "Facilities-Related Demand" (FRD) and "Time-Related Demand" (TRD).12

1. Facilities-Related Demand (FRD): Applied to the maximum kW demand recorded at any time during the monthly billing cycle to recover distribution infrastructure costs.

2. Time-Related Demand (TRD): Calculated based on the highest recorded demand during "On-Peak" and "Mid-Peak" hours, signaling the cost of supplying power when the grid is most strained.

For 2026, facility managers should be careful choosing their "Option" within the GS-2 tariff to reduce costs. Those with "spiky" loads will see their costs soar under Option D, while those who can shift energy use to off-peak hours may find Option E more resilient to the rate hike.

Example: The Medium-Sized Restaurant

A 4,000-square-foot restaurant in Orange County with a peak demand of 45 kW and usage of 15,000 kWh per month, operating under TOU-GS-2 Option E.

• 2025 Average Monthly Bill: $4,200 ($0.28/kWh blended)

• 2026 Projected Increase: +12% (including catch-up recovery)

• New Monthly Bill: $4,700

• Annual Impact: +$6,000

Example: The Retail Strip Mall

A mall with demand of 150 kW and usage of 50,000 kWh per month, utilizing TOU-GS-2 Option D.

• 2025 Average Monthly Bill: $11,000 ($0.22/kWh blended)

• 2026 Projected Increase: +12%

• New Monthly Bill: $12,500

• Annual Impact: +$18,000

Pacific Gas and Electric: The "B" Schedule Landscape

PG&E’s small and medium commercial customers are typically under the B schedule tariffs, which are a set of tariffs meant to align the peak time of use periods to a 4pm to 9pm timeframe between schedules. In general, the B schedule rates for bundled customers have fared well in 2026 with many rates declining.

Small Business: Schedule B-1 ( < 75 kW)

Schedule B-1 targets small general service customers with energy demand less than 75 kW. As of January 2026, the bundled total rate for B-1 is approximately $0.415 per kWh, a decrease from the September 2025 rate of $0.433 per kWh. This makes B-1 competitive for low-demand businesses, although rising delivery components limit total savings.

Medium Business: Schedule B-10 ( < 500 kW)

Schedule B-10 is the standard tariff for facilities with moderate demand under 500 kW and includes a demand charge based on maximum load. For a typical B-10 customer with 61 kW of demand, the 2026 delivery rate is nearly 70% higher than the generation rate, reflecting massive capital expenditure for wildfire hardening.

Large Commercial/Industrial: Schedule B-19 ( > 500 kW)

While mandatory for customers over 499 kW, B-19 is a voluntary option for medium customers seeking lower energy rates in exchange for higher demand charges. A typical B-19 customer at secondary voltage sees a blended rate of approximately $0.289 per kWh, but remains highly sensitive to summer peak demand surcharges, making operational timing of high energy use equipment a necessity for facility managers.

Example: The Cold Storage Warehouse

A 100,000-square-foot cold storage facility in the San Jose area with a peak demand of 150 kW and usage of 55,000 kWh per month, served under Schedule B-10.

• 2025 Average Monthly Bill: $18,645 ($0.339/kWh blended) 

• 2026 Projected Decrease: -3.5% (Bundled Electric Decrease)

• New Monthly Bill: $18,000

• Annual Impact: -$7,740

• Strategic Note: While the bundled bill falls, if this facility uses a CCA, the 19% projected jump in PCIA surcharges could erase these savings entirely.

Strategic Solutions: Mitigating the 2026 Cost Surge

Facility managers can control their facility’s exposure to these hikes through four primary strategies.

Tariff and Rate Plan Optimization

The fastest way to reduce costs in 2026 is ensuring the facility is on the mathematically optimal rate schedule. Businesses often remain on default plans that do not align with their actual load profiles.

• SCE GS-2 "Option" Selection: Medium commercial customers must choose between Option D and Option E. Option D features higher demand charges but lower energy rates—ideal for facilities with high, consistent usage (high load factor). Option E features lower demand charges but higher energy rates, making it more cost-effective for facilities that can shift most usage to off-peak windows.

• Voluntary B-19 for PG&E B-10 Customers: Medium-sized businesses on Schedule B-10 with demand consistently under 500 kW can voluntarily switch to Schedule B-19. This plan features significantly lower per-kWh energy rates in exchange for higher demand charges. For high-usage facilities that can manage their peak, this switch can yield immediate double-digit savings.

• Opting into Peak Day Pricing (PDP) or Critical Peak Pricing (CPP): These optional programs offer summer bill discounts in exchange for higher prices on 9 to 15 "Event Days" per year. Both utilities offer "Bill Protection" for the first year, meaning if the program costs you more than your regular rate, you are credited the difference—making this a risk-free way to test the facility's load-shedding capabilities.

HVAC and Refrigeration Optimization

HVAC and refrigeration are the dominant energy expenses for commercial facilities, especially cold storage where they can account for 70-80% of the load.

• Load Staggering: Staggering compressor starts after defrost cycles can eliminate the largest demand spikes of the day.

• Thermal Mass Utilization: Using frozen inventory as a "thermal battery" allows for pre-cooling during off-peak hours, reducing draw during the expensive 4-9 p.m. window.

• Demand-Controlled Ventilation (DCV): Using sensors to adjust outdoor air can reduce HVAC energy use by 15% to 20%.

Operational Demand Response

1. Emergency Load Reduction Program (ELRP): This voluntary program pays $2.00 per kWh for reductions during grid emergencies and is implemented by all major utilities within California.

2. Building Automation Integration: By 2026, AI-powered Energy Management Systems (EMS) can automatically trigger "load-shedding protocols" (e.g., dimming lights by 30%) upon notification of an Event Day, turning flexibility into revenue.

Solar and Battery Storage

The transition to NEM 3.0 has reduced export credits to an "avoided cost" of $0.05 to $0.08 per kWh.

• Storage is Essential: By storing midday solar and discharging it during the 4:00 p.m. to 9:00 p.m. window, managers can offset peak charges.

• Peak Shaving: Battery Energy Storage Systems (BESS) can reduce Facilities-Related Demand charges by discharging for 15 minutes during massive load starts.

Conclusion: A Roadmap for Facility Management in 2026

The 2026 utility environment represents a signal that delivery costs—not generation—are the new driver of energy volatility. Southern California Edison’s rate hike is a mandate for facility managers to evolve from passive bill payment to strategic tariff decisions and active load management. By shifting usage to off-peak windows, utilizing storage for peak shaving, and participating in demand response programs like ELRP, commercial customers can maintain financial resilience in an increasingly expensive market.