3. Background on Issues and Policy
3.1. Overview of Cost-Benefit Approaches
Our inquiry with regard to a DG cost-benefit methodology evolves from our desire to promote as much DG as is sensible for California, armed with information about the costs and benefits of DG resources. DG differs somewhat from other generation resources in that it is small, can be located in or near the load center, and it may have fewer environmental impacts than more traditional energy resources. We have elaborated on the value of DG facilities to California utility customers and its economy in several Commission orders and the Energy Action Plan, issued by this Commission and the CEC. The full value of supporting investments in DG is not solely determined by performing a quantitative cost-benefit analysis, but such an analysis can be a useful tool in evaluating DG policies and programs.
This order proceeds to identify and specify the quantification of all relevant costs and benefits related to DG, which function as inputs to a cost-benefit methodology. The methodology may then be used to analyze the wisdom of ratepayer funding for DG projects, the allocation of project development costs between project developers and ratepayers, the benefits of DG relative to other energy resources available to jurisdictional utilities, and the progress that the state's market transformation programs have made in making DG competitive with central station energy resources.
The parties to this proceeding identified a variety of possible costs and benefits associated with DG, either in workshops or during the hearings. Parties identified the following potential costs of DG projects:
· Costs to integrate the DG project with the utility's distribution system;
Utility revenue loss due to displaced usage of transmission and distribution facilities;· Utility/Department of Water Resources (DWR) revenue loss due to avoided commodity purchase-energy, capacity, bonds;
· DG project costs-investment, maintenance, fuel, metering;
· Reduced stability and power quality;
· Costs of Ancillary services/VAR support, 2
· Utility loss of revenue due to displaced thermal load, reduced sales of natural gas, and cost of ratepayer incentives for combined heat and power (CHP) generators;
· Costs of mitigating air and water pollutants, and noise abatement;
· Utility DG program-related administrative costs;
· Cost of tax and other incentives; and
· Net metering costs.
Among the potential benefits of DG identified by the parties are:
· Reduced transmission and distribution line losses;
· Avoided purchases of other energy and resource adequacy capacity;
· Enhanced reliability;
· Improved stability and power quality;
· Provision of Ancillary Services/VAR support;
· Environmental benefits compared to central station facilities, including reduced air and water pollutants, promotion of environmental equity compared to large central station power plants;
· Thermal load provided in CHP applications;
· Increased responsiveness to load growth resulting from DG's modularity and scale;
· Lower market prices for power;
· Increased employment and tax revenue in California;
· National security benefits associated with reduced security risk to grid;
· Conservation of natural gas (i.e., reduced utility and/or end-user purchases of natural gas);
· Avoided utility capital costs (such as deferral of investment in transmission and distribution facilities);
· Avoided utility administrative, maintenance, insurance, and installation costs;
· Net Metering benefits; and
· Market transformation impacts (such as greater acceptance and increased demand for DG facilities and reduced system costs, both material and installation).
In this decision, we do not discuss each and every one of the potential costs and benefits that parties initially raised. Rather, we provide this list as background to show the starting point for our work. The actual DG costs and benefits that we incorporate into our methodology are discussed in Section 5 of this order and delineated in detail in Attachment A of this decision.
Of the costs and benefits identified in this proceeding, some will be relatively straightforward to quantify, while others will be more challenging to quantify, such as market transformation impacts. DG costs and benefits vary based on technology, fuel variable, application, size, location, and frequency and duration of the facility's use. Significantly, the value of DG depends on whether the calculation is from the perspective of the DG project owner, the utility or program administrator, or society overall. In D.03-02-068, the Commission found that DG can serve different purposes, such as onsite generation or as a distribution system alternative. The value of a DG project may depend on how the power is used, technology, fuel, and application. For this reason, this order evaluates a variety of methodologies that reflect various perspectives and types of DG.
Creating a cost-benefit methodology for DG programs is a technically complex exercise but is not a novel one. For many years, the Commission has used cost-benefit tests for energy efficiency programs. The Commission has used avoided costs both for analyzing energy efficiency cost-effectiveness and for assessing the value of and setting prices for "qualifying facilities," which are privately-owned energy resources that sell power to the utilities under the Public Utilities Regulatory Policies Act of 1981. Calculation of avoided costs in the context of energy efficiency has taken on even greater importance as these costs serve as the basis for incentive payments the utilities can earn under the Risk Reward Incentive Mechanism adopted by the Commission in D.07-09-043.
In this proceeding, our primary objective is to specify a methodology that reflects the appropriate costs and benefits of DG. A secondary but essential objective here is to determine the type of data or information to use to establish values for each of the variables used in the methodology.
The parties have used some existing studies and references in advocating for cost-effectiveness model types and specifications. The Commission has developed and used a cost-benefit model for existing energy efficiency program proposals in the "Standard Practice Manual" (SPM) used to guide energy efficiency program administration. The SPM presents a cost-benefit model using four tests. The SPM model was intended to be used for resource assessments generally but has so far been used primarily to evaluate energy efficiency programs. Although the SPM describes four cost-benefit tests, the Commission focuses on two of the tests, the Total Resource Cost Test and the Program Administrator Cost Test, when evaluating utility energy efficiency programs. (See D.05-04-051, Ordering Paragraph 5, at 91.)
Also providing a foundation for the debate in this proceeding were two reports sponsored by the CEC and the Commission. One, issued by Itron in March 2005, is titled "Framework for Assessing the Cost-Effectiveness of the Self Generation Incentive Program" (Itron Framework).3 The other, issued on October 25, 2004, by Energy and Environmental Economics, Inc. (E3), is titled "Methodology and Forecast of Long-Term Avoided Cost(s) for the Evaluation of California Energy Efficiency Programs" (E3 Report) and was submitted to the Energy Division and examined in R.04-04-025, the Commission's inquiry into energy avoided costs.
The Itron Framework uses the SPM cost-benefit methodology as a starting point, and specifies the model inputs that are relevant for DG projects. The E3 Report presents various avoided cost estimates, which were adopted by the Commission in D.05-04-024, and updated in D.06-06-063.4 Avoided costs are inputs to cost-benefit models. For example, we could specify a cost-benefit model that measures avoided generation costs and avoided transmission line losses. An avoided cost in this context generally refers to a type of cost the utility avoids when the DG facility serves load the utility would otherwise have to serve. The generic avoided cost calculation may accurately reflect a DG facility's value to the system or it may serve as a baseline to which we might include "adders" in the cost-benefit model to reflect an additional benefit (or cost) that is specific to a DG facility or DG facilities generally compared to other energy resources. For example, we may find that in addition to avoided transmission costs that are common to all resources that reduce load, we may include an adder in the cost-benefit calculation that recognizes the deferral of investment in a transmission line to serve a specific large customer with a DG facility.
Several additional reports provide additional views on a cost-benefit methodology for assessing DG resources and programs. In February 2007, Itron released a report titled "Solar PV Costs and Incentive Factors" (Itron Solar Cost Report). Itron has also released several reports evaluating the performance of SGIP, including the "CPUC SGIP Preliminary Cost-Effectiveness Evaluation Report" (Itron SGIP Evaluation) in September 2005, the "CPUC SGIP Fifth Year Impact Evaluation" (SGIP Year 5 Impacts) in March 2007, and the "CPUC SGIP Sixth Year Impact Evaluation" (SGIP Year 6 Impacts) in August 2007. Each of these reports contributes to the determination of accurate inputs into the methodology described in this document.
Finally, in November 2008, the CEC released a report entitled "Cost-Benefit Analysis of the Self-Generation Incentive Program," prepared by the CEC's consultant TIAX LLC. The report, which we refer to as the TIAX Report, was prepared pursuant to Section 379.6(f),5 which required the CEC, in consultation with the CPUC and the California Air Resources Board, to evaluate the costs and benefits of ratepayer subsidies for renewable and fossil fuel ultraclean and low-emission distributed generation. The TIAX Report categorized SGIP impacts in three categories, namely environmental, macroeconomic, and grid impacts. The TIAX Report is consistent with the core elements of the SPM, but is not bound by the SPM. The TIAX Report acknowledges that there are costs and benefits that have not been included in its analysis, and it further states that the Report "is intended to contribute to the ongoing debate related to the costs and benefits of DG, rather than settle it." (TIAX Report, at 74.) One notable difference between the TIAX Report's analysis and the methodology discussed in this decision is the TIAX Report's focus on macroeconomic effects, such as job gains and losses and tax revenues. The TIAX Report provides additional insight into cost-benefit approaches for analyzing DG and, in our view, its analysis is not inconsistent with the methodology we adopt in this decision.
3.2. Development of Avoided Costs in R.04-04-025
The Commission considered avoided costs in a separate docket, R.04-04-025, which is now closed. R.04-04-025 was initiated to establish avoided costs for the purpose of payments to Qualifying Facilities (QFs) and to develop a common methodology, consistent input assumptions, and consistent updating procedures for avoided costs across various Commission proceedings, with the goal of establishing "apples to apples" comparisons across resource options, to the greatest extent possible. (See R.04-04-025, issued April 22, 2004, at 2.) The various resource options we refer to include energy efficiency programs, demand response programs, utility resource planning and procurement, energy supply contracts with QFs, and DG programs. Significant decisions in R.04-04-025 include D.05-04-024, wherein the Commission adopted an avoided cost methodology for the purpose of evaluating the utilities' energy efficiency programs and D.06-06-063, wherein the Commission refined the interim avoided costs adopted in D.05-04-024. Also, in D.07-09-040, the Commission adopted a Market Index Formula to determine payments to QFs.
As the scoping memo issued in R.04-03-017 explains, the avoided costs developed in R.04-04-025 may be useful as elements of the cost-benefit models we adopt in this proceeding. Our intent here has been to identify the types of elements appropriate for a cost-benefit model to assess DG projects, which would include an avoided cost and may include other elements. To the extent a DG project avoids capacity, that avoided cost would be included in the DG cost-benefit model. The variables for that cost-benefit model, however, would not necessarily be limited to the avoided cost developed in R.04-04-025, without any consideration of specific DG avoided costs. The DG project may also provide additional benefits to ratepayers or society, or impose additional costs, relative to those that are incorporated in the avoided cost.
While the overall purpose of our effort in R.04-04-025 was to promote consistency in our application of avoided costs across programs and evaluation exercises, we do not pursue consistency in a vacuum. Where it is sensible to distinguish one type of facility or program from another because of costs or benefits associated with the facility or program, we intend to tailor our analysis. In this proceeding, we tailor the cost-benefit models in ways that reflect the unique circumstances of DG facilities, and do so without unreasonable delay.
For purposes of our DG cost-benefit methodology, we direct that the DG cost-benefit tests use the avoided cost methodology (also referred to herein as the E3 Calculator) 6 adopted in D.05-04-024, and later modified by D.06-06-063. The E3 calculator adopted in D.05-04-024 is named after Energy and Environmental Economics (E3), the consultants that developed it. In D.05-04-024, the Commission specified the use of the E3 calculator for evaluation of energy efficiency programs, but also described the relevance of the calculator to other resources like DG. (See D.05-04-024, p. 12.) In D.06-06-063, the Commission set forth specific updates to the E3 Calculator. (See D.06-06-063, Ordering Paragraphs 16 and 17.) Further rulings and decisions in the Commission's energy efficiency proceedings continually refine the inputs used in the E3 Calculator to evaluate energy efficiency programs. We direct the use of the E3 Calculator for our DG cost-benefit tests, and we further specify that the inputs for avoided costs used in this methodology should be the same as those inputs currently in use for evaluating energy efficiency programs, except in limited exceptions as discussed below.7 In other words, the avoided costs used to evaluate energy efficiency programs and DG should be the same, with few exceptions. Modifications to the E3 avoided cost data inputs must be documented and publicly vetted, as discussed below.
These avoided costs shall form the framework for our cost-benefit analysis, but we do not preclude the possibility of future modifications to these avoided costs to tailor them to DG facilities. The contractor chosen to perform our DG cost-benefit analysis shall provide thorough documentation of and justification for any modifications to the avoided costs currently used for evaluation of energy efficiency programs to adapt them to DG facilities. After the cost-benefit analysis has been performed, the ALJ will solicit comments on the completed analysis. If the contractor has suggested avoided cost modifications, the ALJ will solicit comments on those modifications and may hold workshops or hearings as deemed necessary on any avoided cost modifications.
3.3. Defining DG for Purposes of Modeling Costs and Benefits
As we stated in the opening of this order, DG facilities have evolved over the time period we have taken to establish a cost-benefit methodology. DG facilities vary significantly with regard to technologies, applications, size, and ownership. However, they all serve load in close proximity to the generation. When this proceeding began, the focus of our methodology was to evaluate customer-owned DG serving load on the customer-side of the meter. Generally, this meant facilities interconnected at distribution level voltages, and sized under 20 MW. At the present time, we recognize that DG may not always be customer-owned, as it could be owned by a third party, and it may be located on the utility, or system-side of the meter, expressly designed as a net exporter of power to the grid.
In the early course of this proceeding, one party, namely, CAC/EPUC suggested the Commission adopt the following standard definition for DG:
"DG is generation located on a customer's site that produces electricity to serve some portion of the customer's load, or nearby load, or both."
CAC/EPUC suggested that this definition includes CHP facilities, also called cogeneration plants. CAC/EPUC argued that cogeneration is reliable, efficient, and environmentally beneficial. CAC/EPUC objected to any definition of DG that was limited to facilities that are connected to the utility's distribution system, arguing that such a definition inappropriately imposes size limits on projects that may be identified as DG (because some large cogeneration plants are connected to the grid at the transmission level). Generally, CAC/EPUC believed there should be no requirement that a project be connected to the utility grid. CCDC agrees with these comments.
We will not adopt the definition of DG proposed by CAC/EPUC for several reasons. First, it appears that one of CAC/EPUC's goals was to have CHP generation facilities interconnected at the transmission level considered DG. The proposed definition could create confusion about what facilities qualify for our various DG programs. We will not consider facilities interconnected at the transmission level as DG. Second, by adopting a cost-benefit methodology, we are not changing program parameters or creating new incentives. To qualify for incentives under SGIP, a DG facility must meet the eligibility requirements set forth in Pub. Util. Code § 379.6 and Commission decisions implementing that code section. To qualify for incentives under CSI, a DG facility must meet the definition of a "solar energy system" set forth in Section 2852 and Section 25781 of the Public Resources Code.8 We see no reason to adopt a new definition here for cost-benefit analysis purposes, and potentially create confusion. Finally, we do not want to create a standard definition when the technologies, sizes, and uses of DG continue to evolve. Rather, we want to be able to apply our cost-benefit methodology to DG in its various forms, as they arise.
3.4. Assigning Specific Values to Adopted Variables
In addition to determining the types of models we should use to analyze DG projects, we specify the variables for each and identify data that should be used to calculate actual costs and benefits. This latter exercise is likely to be a moving target since many of the values for each cost-benefit model may change. These values may be derived from various information resources depending on the cost or benefit in question. For example, estimates of utility incentives are available in program guidelines and a total would be estimated according to DG facility energy production forecasts or metered data. Some model variables would use avoided costs as adopted in D.05-04-024 (as modified by D.06-06-063), or subsequent orders or rulings directing input updates for energy efficiency evaluation purposes.
The parties differ to some extent with regard to whether the Commission has the appropriate data to calculate costs and benefits immediately. ASPv would defer the adoption of final values, stating that third parties do not have ready access to much of the data needed for the models. It suggests conducting further proceedings to develop values for each variable. SCE also would await the final avoided costs adopted for DG in R.04-04-025. However, in the time period since SCE made that comment, R.04-04-025 closed without considering DG specifically. Other parties propose using what is available today, subject to future adjustments.
Several events have occurred since parties first made these comments in 2004 and 2005. The Commission updated avoided costs in D.05-04-024 and
D.06-06-063 and the Commission has directed input adjustments to its avoided cost methodology for energy efficiency evaluation purposes as discussed previously in Section 3.2. Moreover, we have the benefit of additional SGIP evaluation reports prepared by Itron. We see no reason to further delay adoption of a cost-benefit methodology and we believe we have adequate data to analyze DG programs immediately. We also state our intent to modify inputs where existing information, data or estimates may be improved upon.
In order to avoid further delay in developing reasonable cost-benefit models, we herein either assign values to each variable or indicate the data source for the input, which may be historical program or utility information or more current, actual program data. In some cases, we describe a methodology for obtaining the needed value or input, such as avoided costs currently used for energy efficiency evaluation. Where relevant, we use existing tariffs, incentives and tax rates. The input variables and their data sources are summarized in Attachment A. We will modify these values as additional information becomes available or underlying values change. Specifically, we will allow parties an opportunity to comment on the final cost-benefit analysis, once it is completed. At that time, we will accept suggestions for refinements or alterations to the variables and data sources used in the analysis. The ALJ and/or Assigned Commissioner may then hold further workshops or hearings as deemed necessary.
We find that the E3 avoided costs methodology adopted in D.05-04-024 and modified in D.06-06-063 should form the framework for our analysis, as long as it uses the most current inputs in use for energy efficiency evaluation purposes. The contractor performing the cost-benefit calculations may suggest modifications to these avoided costs to adapt them to DG facilities, as long as the modifications are thoroughly documented and justified in the accompanying report.
2 Ancillary services/volt-ampere reactive power (VAR) support refers to services that ensure reliability and support the transmission of electricity from generation sites to customer locations. Such services may include: load regulation, spinning reserve, non-spinning reserve, replacement reserve, and voltage support.
3 During hearings in May 2005, the Itron Framework was accepted into the evidence of this proceeding as Exhibit 37.
4 In D.06-06-063, the Commission refined the interim avoided costs adopted in D.05-04-024 for specific energy efficiency resources and updated the natural gas and generation avoided costs to reflect more recent market realities for natural gas prices.
5 Section 379.6 was added to the Public Utilities Code by Assembly Bill 2778 (Lieber), Ch. 617, Stats of 2006. Except as otherwise noted, all statutory references are to the Public Utilities Code.
6 The E3 calculator is a costing methodology implemented using a spreadsheet model and publicly available data, resulting in avoided cost estimates that are transparent and can easily be updated to reflect changes in major cost drivers, including the price of natural gas and the cost of new generation. D.06-06-063 refined the original E3 calculator by adopting time-of-use (TOU)-averaging correction factors and updating natural gas and electric generation avoided costs. The E3 Calculator, or avoided cost methodology, should not be confused with the E3 Calculator Tool, which is a spreadsheet that takes the avoided cost outputs of the E3 Calculator and calculates SPM cost-benefit test results using those avoided costs.
7 The Commission's current requirements were set forth in "Assigned Commissioner's and Administrative Law Judge's Ruling Regarding May 15, 2008 Energy Efficiency Portfolio Plans for 2009-2011," R.06-04-010, April 21, 2008. The ruling requires updated 2007 generation cost values (2007 Market Price Referent) as adopted in Resolution E-4118 (October 4, 2007).
8 See Attachment B for the relevant language of these code sections.
