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California Defines a More Standardized Approach for Cost-Benefit Analysis of Distributed Energy Resources that Includes Cost of Carbon Values


On May 16, 2019, the California Public Utilities Commission (CPUC) issued a decision establishing a cost-benefit framework comprised of four cost-effectiveness tests. This framework will be used to evaluate distributed energy resources (DER) in regulatory proceedings. The most notable impacts of the decision are the revised greenhouse gas (GHG) adder value to existing cost-benefit tests, the creation of a new test to measure societal impacts and environmental externalities, and the universal application of the tests across multiple proceedings. The framework will be applied as the state pursues its aggressive climate goals, including 60% of retail load served by renewable generation by 2030 and 100% served by zero-carbon generation by 2045.

Key Details

  • The CPUC will apply the cost-benefit framework across the following proceedings and programs:
    • Integrated resource planning (IRP)
    • Distribution resource planning (DRP)
    • Renewable portfolio standard (RPS)
    • Integrated distributed energy resources (IDER)
    • Other programs currently using the standard practice manual for cost-effectiveness evaluation (e.g., utility energy efficiency and demand response programs)
  • The framework became effective on July 1, 2019, and it is comprised of three existing tests, plus the new societal cost test (SCT):
    • The Total Resource Cost (TRC) test measures the benefits of a program/resource against the total costs to both the utility and participants. Through this order, the TRC is now designated as the primary cost-effectiveness test.
    • The program administration cost (PAC) measures the benefits of a program/resource against the costs incurred by the program administrator, typically the utility.
    • The ratepayer impact measurement (RIM) measures the effect on customer rates due to changes in utility revenues and operating costs.
    • The SCT is structurally similar to the TRC, but it expands the scope of included costs to those that impact society as a whole, not just the utility and its ratepayers. The SCT will initially be used as an informational test, which will be evaluated through December 31, 2020, after which a final decision on its use will be made.
  • The GHG adder used in the TRC, RIM, and PAC tests is a modeled price meant to achieve an aggressive GHG reduction target. The new values start at $73.24/metric ton of CO2 in 2019, escalating to $150/metric ton of CO2 in 2030.
    • This replaces the interim value ($69.65/metric ton of CO2) and is significantly higher than the second quarter 2019 California Air Resource Board’s auction clearing price of $17.45/metric ton of CO2.
  • Several attributes of the SCT will be evaluated, such as:
    • Applying a societal discount rate of 3% rather than the utility cost of capital. A lower discount rate puts greater emphasis on the societal impacts of the program on future generations.
    • Using an avoided social cost of carbon value which accounts for the damage costs resulting from climate change and differs from the GHG adder applied to the TRC, RIM, and PAC tests. The evaluation period of the SCT will test both a high-impact and an average impact value.
    • Adding an air quality value of $6/MWh that estimates the impact of air pollution from electric generation on human health.


The immediate impact of the cost-benefit framework order will be felt in the revisions to the GHG adder values and the consistent application of the tests across proceedings.

The GHG adder will, as intended, favor resources that produce less, or zero, GHG emissions. Should the CPUC adopt the SCT with its more expansive definition of the social cost of carbon than the GHG adder, non-emitting resources may become even more attractive.

The universal application of the framework is an ambitious step to link planning functions that traditionally have been conducted separately. For California, generation and transmission planning in IRPs must now be coordinated with distribution planning in the IDER/DRP and the utility-run DER programs. Establishing this consistency across planning functions has been challenging for the industry, as, historically, these have been addressed in different regulatory proceedings, performed with different frequencies and time horizons, and coordinated with different utility planners and stakeholders. Looking ahead, the long-term forecasts and procurement for the bulk system will need to account for the uncertainty inherent in distribution planning, requiring tighter coordination and common assumptions between energy supply, transmission, and delivery analysts. Lessons learned through this effort will inform DER integration planning and IRPs elsewhere.

More Information

This report is part of the Grid Edge Minute series. To view all featured Minutes, please click here.

Additional Contributing Author: Todd Bates

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Contributing Authors

Chris Sturgill Director

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