Navigant Research Blog

CPUC Passes Residential Rate Reform

— September 3, 2015

The recent California Public Utilities Commission decision (D.15-07-001) to alter the composition of residential electrical rates provides necessary reforms—despite suffering from poor public perceptions. While the changes reduce costs to high energy users and increase electric bills for early energy efficiency and solar adopters, they are a necessary correction to policies implemented over a decade ago during the California energy crisis and a step toward the sustainable growth of renewable energy.

Current Rate Structure

Prior to the energy crisis, the California utilities had two tiers of electric rates. Customers would pay a lower rate for each unit of energy until a baseline quantity was consumed and then a higher rate (only a 15%–20% increase over the base rate) for all additional energy. When utility revenue requirements increased significantly during the crisis, a law was passed to freeze lower rates in order to protect lower-income households from price volatility. Additional tiers were created, and increased revenue requirements were passed to the upper tiers so that the highest rate is now over 200% more than the lowest.

With high energy users paying significantly more than their cost of service, alternative options like residential solar are often in the customers’ financial interests. However, as long as the alternative costs are greater than the cost of service and less than the utility bill, individual incentives drive toward an outcome that is more expensive for the system as a whole. CPUC’s rate reform is an effort toward correcting the price signals while presenting a consistent bill to the customer and continuing to promote energy efficiency and distributed renewables development.

Components of Rate Changes

After consideration of several proposals, the utilities will return to a two-tier system with a 25% difference between high and low. The tier reduction will be implemented gradually from 2015 to 2018 to reduce rate shock to customers. A Super User Surcharge rate of 219% of the first tier rate will be charged for energy in excess of 400% of the baseline in order to maintain an incentive for conservation.

Rate Reform Comparison

Rate Reform Blog Graphic

                                           (Source: Navigant Research)

In the interest of aligning customer bills with system costs, the utilities are allowed to include a minimum bill of up to $10 per month. While residential rates blend energy and delivery costs into a single volumetric rate, the delivery costs are largely fixed and are based on customers’ maximum usage. Even if a customer’s net usage is near zero due to onsite generation, the grid is expected to be available on demand, and the minimum bill reflects this cost.

By 2019, customers will be moved to a default time-of-use (TOU) rate. Cost of service is greater when demand is high in the late afternoon and early evening, and lower overnight when demand is low. Charging customers commensurate with the system costs is expected to drive more efficient behavior. Utilities are required to begin developing pilot TOU tariffs immediately and deliver a final tariff in 2018 for implementation the following year.

Effects on Distributed Resource Economics

While these changes will reduce the incentive for the highest energy users to implement energy efficiency or rooftop solar, bringing the bottom tiers closer to the cost of service may allow for an overall increase in solar adoption. Similarly, customers already driven to solar by high utility rates may see a longer-than-expected payback period because of the flattened tiers. Despite the criticism for lowering costs for high energy users and increasing them for lower use households, the rate reform was a long delayed but necessary correction to support California’s energy policy goals.


Distribution Resource Plans: Integrated Capacity Analysis

— August 24, 2015

As discussed previously, California investor-owned utilities recently submitted their inaugural Distribution Resource Plans (DRPs), establishing a framework for the integration of distributed energy resources (DER) into the existing electric grid. As adoption rates for rooftop PV generation, behind-the-meter storage, and electric vehicles (EVs) rise, it becomes increasingly important to determine the extent to which the distribution system can accommodate the newcomers. To this end, the DRP filings include an integration capacity analysis (ICA), providing utility estimates of the ability of each of their circuits to incorporate DER. One of the goals of this analysis is to improve the efficiency of the grid interconnection process by providing DER hosting capacity data to the general public and third-party providers.

Integration Constraints

Per the guidance of the California Public Utilities Commission (CPUC), the utilities collaborated and developed a common set of constraints on integration capacity. The distribution system is designed to operate below equipment thermal limits, maintain voltage within acceptable bounds, avoid compromising protection schemes, and function safely. Therefore, each circuit segment was evaluated to determine the maximum amount of DER that can be connected to the existing electric systems without violating these rules. Southern California Edison (SCE) performed this analysis on a set of representative feeders and extrapolated the results to its entire service territory while Pacific Gas and Electric (PG&E) studied each individual circuit. Navigant expects that the next iteration of the DRP filings will require individual circuit analysis. In addition, there are plans to extend the set of evaluated criteria, as well as include an assessment of hosting capacity during expected switching operations and abnormal conditions.

Integration Capacity Criteria

Fig 1 blog
(Source: Pacific Gas and Electric)

DER Profiles

Because each category of DER has its own effect on the grid, the utilities had to perform different calculations for each resource type. Each utility had a different approach for this task. SCE separated resources into load-reducing (PV and storage) and load-increasing (EVs and storage) resources, while PG&E considered the hourly profile of each resource type separately. As the integration metrics are driven by net load, using hourly load impact profiles for each resource type will be necessary to optimally perform the analysis in the future. San Diego Gas & Electric (SDG&E) notes that it will acquire customer demand profiles from its advanced metering infrastructure (AMI) and localized DER impact profiles in order to improve the locational granularity of its next ICA.

DER Profiles 

Fig 2 blog
(Source: Pacific Gas and Electric)

Streamlining Interconnection Processes

One of the requirements of the CPUC guidance on DRP content was consideration of the applicability of the ICA to Electric Rules 15, 16, and 21 governing EV and distributed generation interconnection requirements. Perhaps contrary to CPUC expectations, while the utilities each allowed that the results of the ICA could be used to inform the interconnection process, none allowed it to immediately replace any of the required screens for fast track analysis. An augmented iteration that includes fast-tracked circuits and estimates of locational value would strongly support the integration of distributed resources.

The approach to the ICA displays a consistent theme across the DRP filings. Despite organizing around the same principles, the outcome methodologies are different enough to portend plenty of alignment discussions heading into the 2017 filing period.


In California, IOU Filings Spell Out DER Forecasts

— July 28, 2015

On July 1, California’s investor-owned utilities (IOUs) submitted the first iterations of their Distribution Resource Plans (DRPs), a new regulatory filing detailing how each will integrate distributed energy resources (DER) into their conventional planning process. Among a wealth of other information, these DRPs include a 10-year adoption forecast of different resource types, which will be used to analyze the range of potential impacts of DER on the electric grid. The California Public Utility Commission guidance provided a framework for three different DER growth scenarios, allowing each utility to use consistent underlying assumptions. The utility filings presented the forecasts with a variety of different metrics for different resources types, from annual energy impact to installed capacity to territory peak impact.

DER Coincident Peak Impact by Type, Trajectory Scenario: 2025

Trajectory Scenario(Source: Navigant Consulting)
Note: Figures display the Navigant estimate of territory peak impact based on the data provided in the resource plans.

DER Growth Scenarios

These scenarios include a low Trajectory case, a moderate High Growth case, and an aggressive Policy Impact case. The Trajectory case portrays business-as-usual based on the existing economic and regulatory drivers. The High Growth case incorporates improved cost-effectiveness for many of the technologies and results in higher adoption. Finally, the Policy Impact scenario assumes California pursues aspirational greenhouse gas reduction, zero net energy, and electric vehicle goals.

The utilities were also required to allocate their system-level resource projections down to individual distribution circuits in order to consider potential location-specific effects from increased DER concentrations. In this iteration, the method and level of detail for this allocation varies both by IOU and resource type, as many categories were not actively tracked in the conventional distribution planning process. However, future filings will likely place additional emphasis on this difficult but impactful component.

Peak Impact Forecast Scenarios

PG&E Peak Impact

SCE Peak Impact

SDG&E Peak Impact

(Source: Navigant Consulting)

Potential Grid Impacts

Each of these planning forecasts is used to determine potential impacts to the future distribution grid. The major categories are changes to the load growth forecast, consequences for grid operations and reliability, potential for capital investment deferral, and impacts to the planning process. While it is clear that these DRPs are the first step in an iterative process, it is also increasingly evident that these issues will have significant influence on the future of California’s electric power system. The variances and magnitudes of DER impacts estimated in the DRPs demonstrate the importance of incorporating location-specific DER adoption trends into California’s already complex load forecasting, procurement, and transmission planning processes. They also indicate the value of upcoming filings in the DRP proceeding that will seek to understand location-specific costs and benefits associated with DER.


CA Utilities Unveil Distribution Resource Plans

— July 9, 2015

On July 1, 2015, California’s investor-owned utilities (IOUs) submitted the first iterations of their Distribution Resource Plans (DRPs), detailing how to integrate distributed energy resources (DER) into their distribution systems. For reference, DER includes energy efficiency, demand response, rooftop solar, combined heat and power, electric vehicles, and energy storage.

The IOUs organized their filings around the California Public Utilities Commission (CPUC) guidance released in February under Rulemaking 14-08-013, taking approaches specific to their territories. The DRPs come at the intersection of increased DER deployments and the pending replacement of significant amounts of the state’s conventional electric grid. This confluence of changes in generation on the supply and demand sides of customers’ electric meters highlights the growing need to develop accurate and widely accepted valuations for all types of energy resources. Satisfying this need will enable wider DER integration into IOU resource adequacy and long-term procurement planning proceedings; a critical path to realizing the emerging opportunities materializing in the Energy Cloud and a more dynamic, responsive, and decentralized California electric grid.

Integrated Capacity Analysis

One of the most important questions that the DRPs address is the extent to which the grid is able to integrate DER without significant changes. The IOUs developed a common methodology to quantify this capacity, calculating the number of DER that can be installed on a circuit without violating voltage requirements, equipment thermal ratings, protection scheme limits, or safety standards. The results of the analyses have been provided as online maps by Pacific Gas & Electric (PG&E), Southern California Edison (SCE), and San Diego Gas & Electric (SDG&E).

SCE DER Interconnection Map

SEC DER Interconnection Map

(Source: Southern California Edison)

The CPUC expects these interconnection maps will help direct third-party DER investments toward more beneficial locations. The commission guidance requires the analysis to be performed down to individual circuit segments, and the variable nature of distributed resources necessitates an intraday time scale. This modeling approach represents a significant increase in locational and temporal granularity as compared to existing distribution planning approaches.

Optimal Location Benefit Analysis

In addition to the engineering analysis establishing integration capacity, the DRPs include a study of the financial impacts of all distributed resources. The framework was created jointly by the IOUs and includes guidance from the More Than Smart working group. The framework enhances previous tools to include the locational detail and dynamic timing required to accurately value DER contributions. The value components from the SCE filing are shown in the following table.

SCE Value Components

SCE Value Components

(Source: Southern California Edison)

The DRP locational benefit analysis considers many of the same questions as the CPUC’s Net Energy Metering Successor Tariff proceeding, though it remains to be seen how closely the two proceedings will be coordinated. The DRPs are a critical first step toward integrating DER into electric system planning, and hopefully the beginning of fruitful convergence of utilities, consumers, and third-party provider interests.


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