V. Variables of Cost-Benefit Models
Each cost-benefit calculation will specify costs and benefits. Most parties agree with the basic list of costs and benefits identified by the Commission and reflected in the Itron report. However, the parties did not agree on some variables proposed for cost-benefit models, as discussed below.
Some costs and benefits may be captured in an avoided cost designed for general application. For example, avoided costs capture the value of reduced natural gas usage. The inclusion of additional costs and benefits-or adders-in the calculation would reflect those impacts of a DG facility that are better (in the case of benefits) or worse (in the case of costs) than central station facilities or which are not captured by the avoided cost calculation at all.
A. Utility Administrative Costs
The utilities and the Itron report include in their cost-benefit tests the costs incurred by the utilities for managing DG programs. No party opposed inclusion of these costs in the RIM and TRC tests and we include them in the models we adopt today. CCDC believes PG&E's interconnection costs are overstated and asks the Commission to inquire as to why those costs exceed the charges to DG customers.
The estimates of administrative costs we include are those presented by the utilities in testimony. With regard to interconnection costs, the CEC is working with parties to develop information about interconnection costs using current and historical data, a matter which has been the subject of inquiry in this proceeding. We agree the CEC's final estimates of interconnection costs should be used as part of the non-participant and societal cost-benefit models adopted today. In the interim, we direct the utilities to use the estimates they provided in the record of this proceeding.
DG facilities reduce utility line losses because the energy resource is at the customer's premises and therefore does not need to be transported over transmission lines. There is some debate about how to reflect a project's size in the cost-benefit calculation. SDG&E/SCG observes that the cost-benefit calculation could make simplifying assumptions for small projects. For projects more than 100 kilowatts (kW), SDG&E/SCG suggests that engineering studies are required to calculate avoided transmission and distribution (T&D) costs and line losses.
D.05-04-024 adopted avoided costs for line losses on the basis of estimates presented in the E3 report. We find that those adopted line losses are appropriately used in the cost-benefit models we adopt today. The exception to this would be for large projects where engineering studies may be used to calculate line losses, as SDG&E/SCG proposes. We may update these estimates in R.04-04-025.
The Commission has found that DG facilities can reduce the need for new investment in utility T&D facilities. D.03-02-068 adopted several criteria for assessing the extent to which a DG facility might permit the utility to avoid T&D investments, among them the requirements that the facility be operating in time for the utility to avoid system expansion, that it must be of a size that serves the utility's planning needs, and that it provide a "physical assurance" that the customer will not ever require the utility service that would have otherwise been provided over the deferred investment. Thus, transmission and distribution investment deferrals are currently site-specific. There is no recognition of T&D deferral benefits for DG projects overall.
CCDC and ASPv believe cost-benefit models should identify T&D investment deferrals as among the benefits of DG, notwithstanding the specific characteristics of an individual facility. More specifically, CCDC would eliminate the "physical assurance" requirements of DG projects that are not parts of utility resource plans and which are compensated for their inclusion in those plans. CCDC argues that small DG projects together are likely to have very strong reliability benefits because the probability of simultaneous forced outages is very small. ASPv proposes to measure the physical assurance of DG projects at the program or portfolio level, which would recognize the combined value of the state's DG facilities. ASPv believes that even a single DG facility provides value to the system in terms of avoided T&D usage, although it does not estimate that value. CAC/EPUC asks the Commission to assure that large cogeneration plants receive recognition for transmission and distribution investment deferrals.
SDG&E/SCG, PG&E, and SCE argue that the inclusion of this benefit is contrary to the Commission's existing policy and that the DG parties have not justified the automatic inclusion of T&D deferrals in cost-benefit calculations for every DG. PG&E concedes that such a benefit might at some point be included in cost-benefit methodologies when there is sufficient DG in its territory that system planners can rely on their availability.
Overall, SDG&E/SCG believes the Commission should continue to recognize the prospect for DG projects to respond to load growth, recommending that projects be evaluated in the context of the distribution planning process established pursuant to Section 353.5.
Discussion:
Our existing policy is to reflect T&D investment deferrals only in specific circumstances where a facility can demonstrate its location, capacity size and operational characteristics justify an investment deferral. Eliminating these requirements for smaller projects and recognizing a benefit attributable to them would require us to presume that those projects, taken as a whole, permit the utilities to defer T&D investments even in cases where the individual project might not result in short-term deferrals because of size, location or operating characteristics. The potential for DG projects to result in systemwide T&D deferrals will depend largely on the number of projects installed.
This matter was litigated extensively and resolved less than two years ago. We find no compelling reason to change our policy regarding T&D deferrals and intend to measure any potential benefit by applying the existing criteria to specific projects, as set forth in D.03-02-068. We will reconsider this if and when a party can demonstrate that the load served by DG has had an impact-or should have an impact-on the utilities' T&D investment planning. In the meantime, we concur with SDG&E that this is a matter for consideration on a plant-specific basis and consistent with each utility's distribution planning process.
Some parties propose that the cost-benefit calculation recognize lower market prices that might occur as a result of a DG project's operation. This effect is also referred to as "price elasticity of demand." The Itron report includes a market price adder in its societal and non-participant tests.
SCE, SDG&E/SCG, and PG&E oppose including a variable for market price impacts in the equation.
It is conceivable that the introduction of many DG projects could reduce a market price by reducing system demand. PG&E argues that a market price adder is inappropriate because a DG facility adds supply as well as reducing demand and therefore the net effect of the facility on the market is zero. PG&E appears to misapply economic theory in this case. Although a DG facility reduces demand by increasing supply, its increased supply is not offered in the relevant market. More relevant to the issue, however, is that additional supplies in a market put downward pressure on prices. We will adopt the market price adder recommended by the Itron report for the societal test and the non-participant test. The tests should reflect any changes to the market price adder that may be adopted in R.04-04-025.
Some parties have proposed that the cost-benefit calculation include increased system reliability as a benefit. Conceptually at least, DG may improve system reliability under certain circumstances, for example, by providing a disbursed and versatile source of power supply. On the other hand, those reliability benefits could be offset by the unpredictability of a DG customer's need for power from the utility's system or an operator's decision to shut down the generator when market prices are low.
SDG&E/SCG stated enhanced systemwide reliability is unlikely but concedes that DG has the potential of reducing RS (or RMR) costs for a utility where DG reduces peak load in constrained areas. It believes these benefits will be nearly zero by 2010, however, when new generation is expected to come on-line. SDG&E/SCG also states that DG does not have the control capabilities to provide ancillary services and should therefore be treated as load reduction for purposes of ancillary services and VAR support, as Itron proposes. SDG&E/SCG proposes the Commission use the values presented in the E3 report and adopted in D.05-04-024.
PG&E believes the avoided cost calculation reflects a DG facility's value as a generation resource generally, although it does not assign more or less reliability to the DG facility than a central station facility.
CCDC concurs that quantifying the value of DG to the transmission system will not be possible immediately and proposes the utilities be ordered to conduct a transmission system simulation to determine those potential benefits. The utilities oppose such an effort as time consuming and expensive, and believe this type of task is part of the Independent System Operator's (ISO) transmission system planning process. CCDC also recommends that the Commission adopt E3's estimate for transmission reliability improvements by DG during peak hours.
The extent to which DG projects can improve reliability is unclear. Nevertheless, we believe that, on balance, DG facilities may relieve the strain on some critical elements of the utility system, as SDG&E/SCG observes. We will include a variable for these net benefits using the avoided costs estimated in the E3 report for energy efficiency projects and adopted in D.05-04-024 for energy efficiency cost-benefit measurements. We apply this value for the societal test and the non-participant test. The tests should incorporate any changes to this avoided cost if we adopt new values in R.04-04-025.
DG facilities may also improve the reliability of the DG customer because of its value as back-up power or voltage support. We do not have estimates of the value of a DG facility to the customer who owns it. The utility or the project developer should develop an estimate for each project, which would be incorporated into the participant test.
DG proponents propose the Commission include increased employment as among the benefits of DG. As the utilities argue, we have no evidence in this proceeding to suggest that DG installations would create more jobs than those displaced as a result of the reduced demand for central stations or energy efficiency. We therefore do not include in the cost-benefit model a variable for increased employment.
G. Market Transformation Effects
Some DG Proponents propose the Commission treat DG development as a "market transformation" program and that the cost-benefit calculations include market transformation effects as a benefit. Market transformation in this context refers to development of a self-sustaining market for DG whereby customers have a wealth of potential suppliers of DG and can make independent and free-ranging choices about DG installation. We would also expect a transformed market to need minimal or no public subsidies in order to remain competitive and support multiple providers and options for consumers. PV Now explains that the models presented in this proceeding are narrowly defined to promote immediate resource acquisition and do not take into account the more important long-term objectives of assuring that photovoltaic technologies, in particular, are sustainable in competitive markets without subsidies. CalSEIA, the City of San Diego and ASPv offer similar comments.
SCE and SDG&E/SCG object to recognizing market transformation objectives in cost-benefit models, noting that the result would be expensive and unjustified. They also believe the SGIP program has been developed as a resource acquisition program rather than one that is intended to have long-term market impacts. We disagree.
This Commission has stated its strong support for solar photovoltaic generation and other DG projects as part of a larger effort to promote the development of diverse and environmentally sound energy production system. We have expressed our support of such "green" energy production and other DG in the Energy Action Plan, requiring them to be deployed ahead of other energy production technologies. The SGIP program is explicitly designed to promote DG development, as are several tariff exemptions or discounts for DG operators and customers. Recently, the Governor has also publicly endorsed solar technologies in a program we are reviewing in this proceeding and refer to as "the California Solar Initiative."
There is no question that the Commission intends to support the development of a viable market for DG projects, especially those using renewable resource technologies, as alternatives to energy facilities employing fossil fuels, coal and nuclear resources. Notwithstanding the short-term goals of the SGIP program, we believe the program will and should influence the types of energy technologies deployed in California and the structure of the state's energy production and delivery system.
The nature and extent of support required for-or the value of-"market transformation" is neither specified nor quantified in the record of this proceeding. We do not have information to suggest the long-term value of solar technologies, which ones are likely to be most viable and the types of risks that accompany their development. Although we are not prepared to include market transformation benefits in the cost-benefit models we adopt today, we state our interest in quantification of long-term benefits of market transformation of specified green technologies and initiate a process for considering ways to integrate those benefits in cost-benefit models. We intend to review this matter in R.04-04-025.
CAC/EPUC objects to including decreased T&D revenues from the non-participant or RIM test, believing the lower revenues are offset by lower costs. CAC/EPUC also believes the Commission should follow the Federal Energy Regulatory Commission (FERC) precedent and assume that such lost revenues are normal business risk.
PG&E responds that T&D costs are generally fixed and ratepayers remit T&D revenues on a volumetric basis. In addition, the RIM test does not measure losses to the utility but to ratepayers. Even if T&D costs fell, ratepayers would not receive the benefits of lower costs between general rate cases.
Under existing ratemaking, when the utility's revenues decline as a result of a DG facility, the utility's ratepayers must ultimately make up all or some portion of the difference. Lost transmission revenues will be made up following subsequent transmission rate cases. Ratepayers assume dollar-for-dollar liability for all distribution and generation revenues that are lost as a result of reduced sales. Accordingly, this is not a case where utility "business risk" is an issue. The risk is ultimately risk to the ratepayer.
In order to assure an accurate assessment of how DG facilities affect ratepayers, the cost-benefit model for non-participants should measure lost T&D revenues. The estimates for these costs to ratepayers would be derived from utility rate tariffs and DG production data. These values would change according to T&D rates and DG output.
All parties agree that the costs of installing and maintaining DG units should be included in the participant test and the societal test. We agree that this is appropriate.
CalSEIA proposed to measure DG project costs using estimates of future costs at lower levels than that presented in existing databases. SDG&E/SCG believes the Commission should use data collected from the SGIP and the CEC's Emerging Renewables Program (ERP). SDG&E/SCG observes that this data are derived from actual facilities' costs.
We have no basis upon which to forecast future technology costs and we are not convinced that future costs provide an appropriate proxy for current project costs. We intend to use actual data to measure the costs of DG projects. As costs fall, they will be reflected in the data bases. The CEC retains some data tracking such costs associated with solar photovoltaic projects, which should be used. Otherwise estimates available through manufacturers for specific technologies should be included in the analysis.
J. Environmental Values-CO2, NOx, and PM 10 Emissions
The utilities generally support the use of the E3 avoided cost for generation and fuel to recognize air quality improvements from DG. The E3 data incorporates reductions in CO2, NOx and PM 10 emissions. CCDC would modify the E3 environmental adder by reflecting the actual mix of existing and expected power plants and their operating characteristics rather than using futures prices to estimate electricity market prices. The CCDC estimate would affect emission costs for CO2, NOx and PM. CCDC states that the dirtiest power plants are those most likely to be used during peak periods, and these marginal units should be included in the model, at least for the early years of a DG project. CCDC recognizes that emission avoided costs should be tailored by DG technology, time period, and facility location. CCDC also believes the E3 report's use of the NYMEX futures prices does not accurately reflect California conditions and an environmental adder would improve the price estimate in that regard.
PG&E argues that no value should be given to these environmental effects if they are not regulated or their mitigation mandated. PG&E observes that if they are mandated, their impacts will already be included in the cost of avoided generation. PG&E believes that DG facilities may increase CO2 emissions relative to central station plants because modern plants burn fuel at a much higher heat rate. It therefore proposes that this impact be included as a net cost of DG facilities.
PG&E's logic leads to the conclusion that no DG project should be considered any better for the environment than a gas-fired central station plant. Given that this Commission and the California State Legislature have explicitly recognized the environmental benefits of renewable DG facilities, we reject PG&E's position that no environmental value should be ascribed to a DG facility if the impact is not mandated. We wish to capture all benefits attributable to DG facilities and, in particular, to recognize those that improve environmental quality.
We herein adopt CCDC's proposed modification to the E3 avoided costs for electricity and natural gas for the societal and non-participant tests.
K. Combined Heat and Power Applications
CCDC proposes that the E3 avoided cost estimate for fuel and generation be modified to recognize that cogeneration uses a single fuel to produce electricity and production heat. SDG&E/SCG agrees that this benefit would always accrue to the DG customer and may represent a societal benefit if the efficiency of the DG facility is higher than a central station plant. SDG&E suggests these benefits would be plant-specific and believes the Itron report appropriately accounts for them.
We agree that the participant and societal tests should include a value that recognizes more efficient use of cogeneration facilities, where appropriate. We will direct that each project test estimate the related plant-specific characteristics.
The Itron report includes the loss of revenues from exemptions from standby charges as among the costs that should be included in the non-participant test. SDG&E/SCG concurs with this methodology and suggests estimating this cost using data it has collected as part of the SGIP program.
SCE believes that if the revenue shortfall from standby charges is not offset by total DG benefits, Section 353.9 requires that the shortfall be recovered from members of the DG class only.
We agree that this subsidy should be included as a cost in the non-participant test and also as a benefit in the participant test. Estimates would be derived using the utilities' rate tables and according to the DG facilities' production. We also agree in principle with SCE's observation that any revenue shortfall should be recovered from members of the DG class. This latter issue involves revenue allocation, which is outside the scope of this proceeding. We therefore defer this matter to proceedings that allocate revenues among rates and customer classes. For SCE and PG&E, this would be in their respective general rate cases. For SDG&E, this could be in its general rate case or "rate design window" application.
M. Electric and Natural Gas Avoided Costs
The parties generally agree that DG facilities allow the utilities to avoid electric and natural gas costs. SDG&E/SCG proposes that we adopt the E3 values adopted in D.05-04-024. SCE and PG&E would apply those values until the Commission has modified them for DG in a later phase of that proceeding.
We herein adopt the E3 avoided costs for electric and natural gas avoided costs, as adopted in D.05-04-024, subject to modifications in that proceeding and with the modification addressed previously for air quality impacts.
Certain renewable DG projects qualify for "net metering," which permits the DG operator to receive bill credits for power sold to the utility. The bill credit amounts to a payment-in-kind that is substantially in excess of the avoided cost the DG facility would otherwise receive for selling wholesale power to the utility. Depending on the type of customer served by the DG facility, the DG customer could avoid all energy and T&D charges or, for large customers who pay fixed T&D charges, energy only.
Because this in-kind payment is a subsidy from ratepayers to DG facilities, SDG&E/SCG proposes to include it as a cost in the non-participant cost-benefit model.
Lost revenues from net metering are a subsidy designed to promote DG development. The reason for permitting net metering rather than tracking production more precisely is to avoid the cost of installing multiple meters to monitor both consumption of the facility and output from the DG unit. Thus, these costs are not readily measured, and we decline to require the installation of a new meter for this purpose, which the utilities' proposal implies. While conceptually this subsidy may be considered a cost, the expense of installing a meter to measure that cost would easily dwarf the benefit derived from knowing the amount of the subsidy. We decline to include these amounts in the cost-benefit calculations.
O. Exemptions From CRS Liabilities
DG projects under 1 megawatt (MW) are exempt from the "cost responsibility surcharge" which permits the collection of power purchase liabilities incurred by the Department of Water Resources (DWR) during the state's energy crisis and which are more expensive than market prices.
The utilities argue that the non-participant test should reflect the loss of CRS revenues when a DG facility goes on-line, as the Itron report recommends.
CAC/EPUC believes the non-participant test should not include reduced CRS liabilities because DWR did not purchase power for DG customers and small DG customers are exempt from CRS charges. CCDC makes similar comments.
CAC/EPUC is correct. Revenues associated with exemptions from CRS revenues should not be accounted for in the non-participant test. In developing its strategy for purchasing power during California's energy crisis, DWR believed that it could rely on a forecasted amount of DG power to meet the state's energy demand and purchased power supplies accordingly. For that reason, we found in D.03-04-030 that certain DG facilities should be exempt from the CRS. D.03-04-030 found that DWR excluded 3000 MW of power for DG from its forecast, and therefore the exemption is not a cost shift. For this reason, we include that CRS revenues should not be considered a cost in the non-participant test.
P. SGIP Subsidies
Currently, both the CEC and this Commission sponsor incentive programs for renewable DG projects. Once we establish that DG facilities should be analyzed using the non-participant test, there is no controversy about whether and how to recognize these subsidies in the models. As the utilities suggest, these subsidies are appropriately considered a cost in the non-participant test and as a benefit in the participant test. The subsidy amounts are available through the program rules and are readily applied according to facility characteristics and performance.
Both the state and federal governments provide tax incentives for certain types of DG projects. No party opposes recognizing these subsidies in the models. They should be included as benefits in the participant test. They would not be included in the societal test because they are merely transfers, and would not be included in the non-participant test because ratepayers do not bear these costs.3
Tax incentives should be estimated using Internal Revenue Service regulations and State Franchise Tax Board rules, or the information provided by DG vendors.
3 Of course, the ratepayers of a regulated California electric utility form a subset of California taxpayers and federal taxpayers. The former group, however, do not assume the entire cost of the tax incentive.
