California's electric utilities have a long history of participating in activities that assist many California citizens. These activities include rate discounts for low- income individuals, programs to improve economic development, efforts like the Women, Minority, and Disabled Veteran-owned Business Enterprise program (WMDVBE) to improve the procurement practices of regulated utilities, energy efficiency efforts, promotion of resource diversity and development of renewable resources, and the development of statewide guidelines for utility research, development and demonstration (RD&D) efforts. Many of these programs are provided because of Legislative mandate. These programs exceed the basic requirement that a utility provide safe, reliable and reasonably priced electric services, and reflect a recognition that the electric utilities are fundamental to the fabric of our society, deliver a necessary service, and can assist in the achievement of valuable social goals. However, as recognized in the May proposals, the continued reliance on utilities to achieve social goals may put the utility at a disadvantage in the move toward a more market-based, customer-oriented electric services industry. Subjecting utilities to the cost of programs that their competitors do not bear may not be a sustainable strategy.
The need for activities performed in the public interest will continue in the future, but the role of electric utilities as the providers of these services is less clear. Given the Legislature's role in creating these programs, we do not view it appropriate to alter them significantly without Legislative guidance. We therefore will maintain the status quo for the time being, but expect to work closely with the Legislature and stakeholders as we implement this policy decision to determine where changes might be appropriate.
For the interim, we will propose the establishment of a target level of generation from renewable resources. This target will be backed by a meaningful penalty for noncompliance. We propose a nonbypassable surcharge, the Public Goods Charge (PGC), on retail sales to fund public goods RD&D and energy efficiency activities, and we will support legislation authorizing a separate surcharge to collect funding for low-income assistance programs. We provide initial guidance on these issues, but recognize the need for additional information on implementation specifics. Toward this end, in Section VIII we describe how we anticipate implementing this decision.
Many other public purpose programs continue to be a responsibility of the regulated utility, and therefore should continue to be collected as part of regulated rates. We indicate whether line-item listing of charges for specific programs on customer bills appears warranted.
The development of our thinking in this area was greatly assisted by the independent Working Group, which we asked interested parties to form to develop implementation options to carry out social, economic, and environmental policy goals. The Working Group submitted its report on February 22, 1995. (Fn. 1)
A. Renewable Resources
Electric generation in California utilizes a very diverse set of resources. The renewable resources currently in operation either are owned by utilities or sell to utilities under QF contracts. The present mix of renewables on the system has been driven by resource diversity interests on the part of utilities and the Commission's QF policy, which encouraged the growth of independent power production during the 1980s. (Fn. 2) The Commission's recent policy of encouraging resource diversity through the development of new renewable resources is derived from 701.1 and 701.3. This policy has been applied only to new resource procurement implemented through the Biennial Resource Plan Update (BRPU), which has not yet led to utility investment in additional renewables. Thus, the renewables that are on line today are the result of the Commission's QF policies and utility practices in place prior to the BRPU.
We are committed to establishing restructuring policies which maintain California's resource diversity for existing resources as well as encourage development of new renewable resources. The May proposals suggested two ways that these goals might be accomplished: 1) establishing a tradeable renewable target (assigned to either the buyer or seller) or 2) setting minimum diversity targets for the pool. The May proposals did not identify additional funding mechanisms to assist in meeting these targets.
In comments on the May proposals, many parties conceptually supported the recommended renewables target, including CEERT, CLECA, EDF, AWEA, Los Angeles Department of Water and Power (LADWP), FloWind, and NRDC. The CEC and PG&E stated that today's electricity system is sufficiently diverse in the near term and no further Commission action is needed. DRA supported this position, if the utility divests its generation plants. EPUC opposes mandating the type of resources used to meet electric demand. SDG&E supports establishing a statewide Environmental and Clean Energy Security Fund to finance renewable resources and fuel diversity, based on a user fee on electricity consumption, instead of the renewables target. Sierra Pacific prefers direct taxes.
Other parties commented that specific funding needs to be in place to stimulate long-term development of new renewable resources because of the high initial costs of these resources. EDF suggested funds could be implemented through a production credit to new renewable production (collected through a surcharge of 0.6% on utility revenues), distributed through a competitive process. CLECA supported this "auctioned renewable credit" approach. This process could be implemented by the Commission or some other entity. SCE advocated a legislatively determined subsidy for incremental renewable production, funded through a surcharge. Others recommended establishing two separate pool prices, one for renewables, one for all other resources, in order to achieve the renewable goals (see comments of AWEA and LADWP). The CEC stated that the Commission's endorsement of a specific long-term strategy on resource diversity is premature.
The MOU indicates support during the transition to full competition for some level of funding for renewable resources (consistent with the statutes) within a cap of 3.3% on utility revenue. (Fn. 3) The Framework Parties addressed the appropriate level of a renewables target, and recommended providing funds to stimulate new development under any new market structure but did not identify a specific funding level. In comments on the MOU, DRA suggested that funding for new renewables development be limited to $75 million of the revenues collected under a broader public purpose surcharge.
The suggestions by the parties are not inconsistent with our recommended policy direction of establishing a minimum renewables requirement under either direct access or a pool. The parties' suggestions primarily concern additional resource procurement or implementation strategies. A policy of developing renewables targets which meet or exceed current or historical (Fn 4) levels may not be sustainable without additional funding, and the parties' recommendations present options for accomplishing a more aggressive renewables target.
We continue to believe that a minimum renewables purchase requirement is the best approach to meet our resource diversity goals. This can be achieved by placing the requirement on either retail providers of electricity, or on generators.
We have not concluded at this time on whom this obligation should be placed. We hope that the Working Group will provide us with further guidance on this, and will address this question further as we implement this decision. Regardless of where the obligation resides, it would be a condition of certification. We prefer that the requirement be set at the same level for all electric utilities on a statewide basis, but recognize that it may be appropriate to develop a transitional strategy given the current resource portfolios of some utilities. Credits for meeting this requirement would be tradeable, similar to tradeable permits programs adopted by Congress in the Clean Air Act Amendments of 1990 and the South Coast Air Quality Management District's Regional Clean Air Incentive Market, in order to allow retail providers the most flexibility in meeting this requirement. We would expect that these minimum renewables levels would be in place beginning in 1998 and continuing through 2000, at which point we would revisit whether the requirement should be modified. As with the tradeable permits programs mentioned above, a meaningful penalty for noncompliance should be established.
We recognize that we will need information on the level of renewables on the utility systems from 1990 to the present, and will identify how we will gather this information when we develop our procedural roadmap (See Section VIII). This information will allow us to determine the appropriate level for the minimum renewable requirement, whether the requirement should be established on a percentage of megawatts or percentage of megawatt-hours basis, and whether a transitional strategy to a statewide minimum level is necessary. We also believe that it may be appropriate to establish floors for certain technology types, in order to maintain the diversity of our renewable resources; this should be explored in the information-gathering process. The cost of the noncompliance penalty will be explored as well.
This market-based approach will allow buyers and sellers to search the market for the best renewables bargains and to internalize such costs in their prices without the need for a surcharge to fund renewables development. Establishing a surcharge to fund new renewables development would require some sort of prescribed allocation mechanism or bidding procedure to disperse the funds. We could use an administrative approach to ensure compliance, but after our experience in the BRPU we are hesitant to do so. The minimum renewables requirement approach will allow the market to provide the most cost-effective renewable resources, without our intervention. Allowing providers to trade in order to meet the renewables requirement may also serve to minimize the stranded costs associated with existing QF contracts by providing new markets for QFs' power. Renewables research and development will be likely to occur under this approach as electricity demand grows and existing renewables are replaced with new renewable resources to meet the minimum requirement.
B. Energy Efficiency
Under the current regulatory framework we authorize funding which allows utilities to pursue energy efficiency, load management, and other demand-side management (DSM) investments that meet specified tests of cost-effectiveness. Information and energy management services programs are also funded but are not required to pass stringent cost-effectiveness hurdles. (Fn. 5) Both May proposals recommended a two-track approach to DSM, similar to that suggested by the Working Group. The May proposals indicated that customer-specific energy efficiency projects should not require future funding from ratepayers, but should instead rely on market-driven funding mechanisms (Track 1). The proposals emphasized that continued funding was appropriate for activities that are designed to transform the energy efficiency market and would not naturally be provided by a competitive market (Track 2). The proposals did not indicate a preference for the recovery mechanism to fund energy efficiency efforts not naturally provided by the marketplace, nor for a specific means to distribute the funds.
Both proposals looked to the Legislature for guidance in arriving at the appropriate level of funding and the means to administer those funds. Fees and trusts were mentioned as options. In its comments on the May proposals, DGS supported the collection of funds through a universal distribution charge and recommended making the funds available on a competitive basis to utilities and nonutilities alike. CLECA supports a surcharge and provides a suggested list of criteria which DSM programs funded by the surcharge should meet. The Southern California Cities Joint Powers Consortium and Turlock Irrigation District recommend use of a surcharge for environmental protection, which appears to cover both energy efficiency and renewables. SCE supports a distribution charge for all customers. SDG&E believes distribution utilities should continue to implement market transformation DSM programs as they have successfully been doing for many years; in the long term, SDG&E supports a bypass-proof collection mechanism. SESCO supports competitive access to DSM funds.
The MOU recommends that the Commission establish a funding level for cost-effective expenditures by utilities and others, not to exceed 3.3% of revenue requirements as of January 1, 1995, collected through a surcharge. (Fn. 6) The MOU does not provide for funding of energy efficiency efforts that do not pass cost-effectiveness tests. Many programs with a market transformation, information, or education focus are not likely to be provided by the competitive market and are also not likely to pass this cost-effectiveness screen. The MOU approach is unlikely to provide funding for such programs.
The Framework Parties also support a surcharge for collection of funds but do not place a limit on that funding. The Framework Parties recommend that utilities continue to administer funds for energy efficiency and conservation programs in the near term, but support development of an independent administrator over the long run. The Framework Parties raise the concern that utilities should not be allowed to use these funds to establish market power or retain market share.
The CEC has convened an Energy Services Working Group (ESWG) as part of its Energy Efficiency Report process to consider how best to promote energy efficiency in a restructured industry. That group has submitted a report to the CEC which recommends policies for legislative action. The ESWG recommendations include a surcharge to fund energy efficiency programs and energy efficiency RD&D beginning January 1, 1996 and support of more market-driven approaches to funding; funding levels and administration of the funds are topics for future discussion. As a transitional strategy, the ESWG proposes that the Commission oversee utility expenditures for DSM programs, as it does today, until 1998, while market structure details are worked out.
Support for a surcharge for funding energy efficiency and conservation programs is very strong. Parties do not agree on the types of programs the surcharge would encompass within the funding level or the dividing line between the two tracks. Parties are unclear or vague about their positions regarding the appropriate level of funding for energy efficiency or the means to administer funds.
In considering the future role of electric utilities in funding and administering DSM activities, we must consider the appropriate application of state policy to a dramatically changing industry. State policy supports utility pursuit of energy efficiency which is not being pursued by other entities (see 701.1). We have promoted utility involvement in these programs to ensure that Californians received the benefits of energy efficiency, consistent with our resource procurement goal of providing least-cost, reliable, environmentally sensitive energy services. The primary motive behind utility investment in energy efficiency has been to defer or avoid the high costs of new generation. However, in a restructured environment, evaluating cost-effectiveness on the basis of utility resource deferral may no longer be as relevant. The May proposals stated a preference for publicly funded energy efficiency programs to shift to those programs in the broader public interest, for example, programs with market transformation effects and education efforts that would not otherwise be provided by the competitive market. We continue to prefer this two-track approach.
We recognize that there are many definitions of market transformation and education activities, and we will not attempt to refine those definitions today. In general, it is appropriate to use public funding to ensure that energy users have information about managing their energy use. It may be appropriate to have more public resources available for educating residential and small business customers than large electricity users, because large users generally have more resources to dedicate to managing their energy use.
It may also be appropriate to continue to provide financial incentives for energy efficient products and services. Any such financial incentives should be focused on transforming the market for energy efficient products and services; some examples of these activities are the Super-Efficient Refrigerator Program, (Fn. 7) and manufacturer rebates for compact fluorescent light bulbs and high-efficiency motors. We expect that public funding would be needed only for specified and limited periods of time, to cause the market to be transformed. Given our focus on market transformation efforts, we disagree with DRA's comments that surcharge funds should predominantly be used as a source of capital for the installation of demand-reducing technologies and measures (October 2, 1995 Comments on MOU, p. 31).
We suggest to the Legislature the adoption of a surcharge to fund energy efficiency activities as discussed above. The surcharge would be applied in the same manner as the CTC and be nonbypassable. We do not intend for the surcharge to collect funds to pursue energy efficiency activities that the competitive market will provide on its own. Delineating between competitive and other DSM activities will be difficult. After a short transition period, we believe the funds collected through a surcharge for energy efficiency should be competitively allocated by an independent, nonprofit organization, but we would like to capture the expertise and knowledge that the utilities have gained in administering DSM programs as we begin the transition. We expect to reach closure on this issue through the implementation activities we will undertake in the next few months and through ongoing coordination with the Legislature.
We anticipate that by January 1, 1997, energy efficiency costs should no longer be embedded in electric rates and instead should be collected as part of the "public goods charge" (PGC) applied to retail electric sales. (Fn. 8) Assuming the Legislature adopts a PGC, it should initially be a line item on utility bills and then change to a surcharge, depending on when legislation adopting such a surcharge is enacted. Initially the line item rate should be set for each utility's service territory to correspond to authorized DSM funding. (Fn. 9) We will modify the level to be collected once we determine the appropriate level of public funding consistent with the above discussion and the workshops we anticipate conducting as part of our implementation of this decision. Until public funding for DSM activities is removed from rates and collected through a surcharge, an Electric Revenue Adjustment Mechanism (ERAM)-type mechanism shall be retained to account for energy efficiency impacts. Over time, we prefer to see the same surcharge applied consistently across all utilities' service territories.
We anticipate that our implementation of this decision will include workshops that will develop information to allow us to establish what types of energy efficiency activities should be funded through the surcharge, consistent with our guidance above. (Fn. 10) This guidance should be considered a starting point and not final; if the workshops flesh out the two tracks in more detail and identify areas where public funding should be expanded or limited, we will consider modifying our definition. Therefore, we do not adopt a specified percentage cap for the charge at this time, as proposed by the MOU. If we order workshops, we will direct workshop participants to explore the details of an independent administrator of these funds and the transition period necessary to move to an independent administrator. How utility expertise can be captured should be explored as well. Because Legislation to ensure the surcharge is nonbypassable is desirable, we will likely ask that the workshops be used to assist us in developing proposed language for that legislation.
C. Research, Development and Demonstration
Electric utility RD&D programs today support both regulated business functions and public purpose goals. For example, the utility conducts research on generation, transmission, distribution, environmental compliance, service and safety, energy efficiency, and low-emission vehicles. Our May proposals recognized that the utility will have a need to conduct research to support its continuing monopoly functions, and that research that serves a broader public interest which may not be pursued by the monopoly should not be lost in the transition to a more competitive environment. Our proposals also noted that in anticipation of full competition in the generation sector, the remaining monopoly utility should no longer use ratepayer funds for generation RD&D.
Both proposals endorsed the Working Group's option of a Consortium or Public Authority to administer public goods funds collected through a surcharge. The surcharge would be calculated to generate funding at current or historical levels, or legislatively adopted levels, for public goods research. The proposals stated that research supporting regulated functions should continue to be funded through utility rates, not through a surcharge.
Few parties commented directly on the proposals' RD&D policies; those who commented supported a surcharge to fund RD&D. (Fn. 11) The CEC supports continuation of public goods research by utilities during the transition to a more competitive market and notes that despite statements in the proposals in support of public goods research during the transition, the Commission has allowed utilities to decrease RD&D budgets significantly in these areas.
The MOU includes funding for research for regulated transmission and distribution services as part of the 3.3% surcharge on total revenues. It does not address public goods research. The MOU diverges from the May proposals because it would use a surcharge to collect funds for RD&D programs that serve a regulated function. The May proposals anticipated that a surcharge would be used to fund public goods research only. The Framework Parties recommend near-term funding for energy efficiency and renewable RD&D consistent with historical levels, and specifically recommend restoration of funding for the California Institute for Energy Efficiency. For the long term, they propose to provide RD&D for energy efficiency and emerging renewable technologies through an independent institute, funded by a surcharge.
We reaffirm that the surcharge should collect funds for public goods research only, not funds for regulated or competitive research functions. The monopoly utility should no longer collect ratepayer funds for generation-related research as of January 1, 1997. Funds for research in support of regulated functions properly remain part of regulated rates.
We recognize that drawing the line between competitive, regulated, and public goods RD&D activities will be difficult. (Fn. 12) We do not intend for the surcharge to collect funds to pursue research that the competitive market will provide on its own. After a transition period, perhaps by January 1, 1998, the funds collected through a surcharge for public goods research should be administered by an independent, nonutility entity.
By January 1, 1997, the public goods RD&D costs should no longer be embedded in electric rates and instead should be collected as part of the PGC applied to retail electric sales.
We anticipate that our implementation of this decision will include workshops to develop information to allow us to establish the boundaries between competitive, regulated, and public goods research, and to develop the public goods RD&D costs and transition policies for an independent administrator. We will also work with the Legislature to change 740.1 and 740.3, (Fn. 13) and we will modify existing Commission decisions to implement these policies, assuming the Legislature agrees with us.
D. Baseline Rates
The baseline rates program is designed to provide residential customers with a specified quantity of electricity (sufficient to supply reasonable energy needs of an average residential user) at a lower rate. (Fn. 14) The pool proposal suggested that the utility would continue to offer baseline rates but that the entry of new, unregulated providers would require us to reconsider how this program is implemented. The direct access proposal would have the utility offer baseline rates, but new entrants would not be required to do so since they would not be defined as public utilities.
The Framework Parties recommend that baseline rates be continued. If rates are unbundled, the baseline concept would be continued through a rate differential on transmission and distribution rates. DRA's comments on the May proposals correctly observe that as "electric restructuring moves forward and we move from cost-of-service regulation to performance-based regulation, utilities may start to feel the pressure of moving rates closer to true costs. As this happens, it is possible that baseline rates will disappear and utilities may impose a fixed monthly customer service charge on residential customers. Since low-income customers consume less than other residential customers, the impact of such charges could be a substantial bill increase" (p. 29).
The Framework Parties, many of whom represent residential and low-income customers, are concerned with what they perceive in the May proposals as a lack of commitment to continuing the baseline rate program. The proposals recognized the difficulty of implementing baseline rates in a more competitive environment as rate design principles change and new market entrants emerge. We are not suggesting the abandonment of baseline rate implementation, but we see inherent conflicts between the types of innovative service offerings new competitors may propose and mandating a specified rate design approach. We would like to receive more information that will allow us to continue effective baseline rates under the market structure adopted today, and that will help to minimize the concerns expressed by Framework Parties. In a subsequent ruling, we will establish a procedural schedule for receiving that information. In the meantime, all electric service providers under our jurisdiction will be required to offer eligible customers service consistent with 739.
E. Low-Income Assistance
The Commission currently implements two types of assistance to low-income residents: rate assistance and weatherization and efficiency services. Rate assistance is provided consistent with 739.1 and 739.2 under the California Alternate Rates for Energy (CARE) program. Under this program, eligible low-income households and group living facilities receive a discounted rate for their electric and gas consumption. (Fn. 15) Costs associated with the rate discount are currently collected as a cents-per-kWh component of rates. Costs of low-income efficiency services costs have been incorporated in general rate case funding for DSM programs; the programs have been administered by the utilities but generally implemented by a variety of community-based organizations or through competitive bidding. Low-income efficiency services are implemented pursuant to 2790.
Under the terms of recent legislation supported by Southern California Gas Company (SoCalGas) (SB 678, Polanco), costs associated with CARE and low-income efficiency services would be removed from gas rates and recovered as a surcharge applied to all gas consumption. (Fn. 16) This bill is designed to ensure that all gas consumers contribute on an equivalent basis to funding the low-income assistance programs. SB 678 requires that the costs collected through the surcharge not exceed the amount currently in rates.
The May proposals both recommend continuation of these programs and a commitment to retain funding for them, through a line-item charge on customers' bills, but suggest that the Legislature should consider transferring these responsibilities to another entity in a restructured environment. The Universal Lifeline Telecommunications Service (ULTS) fund is cited as a model.
The MOU and the Framework Parties propose to recover CARE program costs through a nonbypassable charge at levels sufficient to cover all eligible recipients who apply. (Fn. 17) The MOU recommends that low-income efficiency services costs be recovered at the 1995 funding level. The Framework Parties recommend that the nonbypassable charge should be designed to improve on current funding and participation levels for both CARE and low-income efficiency services, without a funding cap.
We could today require utilities to identify low-income assistance costs as a line item on bills; in fact, this already occurs for some nonresidential customers for CARE costs. The Greenlining Institute, NRDC, UCAN, and TURN argue against line-item identification and point out that itemizing only public policy programs stigmatizes these programs in the eyes of customers, and that other components of utility costs are equally as important to reveal, especially given their impact on rates and bills.
We are concerned about the ramifications of itemizing low-income assistance as a line item during the transition period. The beneficiaries of low-income assistance have little political power, and line-item listing could make this program vulnerable to lobbying efforts by more powerful opponents. The limited rate impact also argues against line-item treatment. (Fn. 18) Our policy preference is to recover these low-income assistance costs as a surcharge on electricity use separate from other public goods charges. Direct access customers would not be able to evade this surcharge by selecting a supplier other than the utility. We establish this separate low-income assistance surcharge to provide a clear funding source for low-income programs which will not be mingled with funds collected for other purposes. Funding for low-income rate discounts recovered through a surcharge should not be capped at current levels but should instead be based on need. We would prefer to see the same level of surcharge applied across the state rather than on a service territory basis as occurs today, but recognize that there may be some transition period necessary to accomplish this goal. We will work with the Legislature to develop any legislation needed to facilitate this change.
In the near term the utilities should continue to administer these programs. The proposal to move administration outside of the utilities is appealing. Low-income assistance funds could be transferred to a ULTS-like fund for distribution, as many parties have suggested. (Fn. 19) Any energy provider could use these funds to provide rate discounts to eligible customers, and energy service companies or nonprofit community-based organizations would compete for use of the funds to provide low-income efficiency services. CARE funds should be used for a customer discount that appears on the bill rather than an after-the-fact refund or rebate. (Fn. 20) There are significant questions regarding how the funds collected for rate discounts would be administered and provided to eligible customers. We need additional information in order to develop the details of how to administer these funds effectively.
Another unresolved issue is whether the level of funding for low-income efficiency services should be capped or uncapped. We would like to see a more detailed analysis of the need for low-income efficiency services before we decide whether the amount of funds collected for these services should be capped or uncapped. (Fn. 21) A subsequent ruling will lay out a schedule for receiving a report on these unresolved questions and identify the issues the report should address. After we have received the report, we will make a recommendation to the Legislature regarding statutory changes that would help us in continuing our support of low-income efficiency services.
F. Women, Minority, Disabled Veteran Business Enterprises
Section 8281 states, "The opportunity for full participation in our free enterprise system by women, minority, disabled veteran business enterprises is essential if this state is to attain social and economic equality for those businesses and improve the functioning of the state economy." To implement 8281 et seq., General Order (GO) 156 initiated the WMDVBE program in 1987, and established goals for regulated utilities' procurement practices. The goals encourage awards of not less than 15% of all contracts for goods and services to minority-owned businesses and not less than 5% to women-owned businesses. Following a 1990 amendment to the Public Utilities Code, GO 156 was expanded to include disabled veteran-owned businesses.
The program is voluntary and goal oriented, not a set-aside program. GO 156 established that utilities should develop outreach programs, internal training of utility procurement staff, and a subcontracting program that encourages prime contractors to use WMDVBE subcontractors. The Commission also oversees a clearinghouse which verifies WMDVBE status. By the end of 1993, utilities had made significant progress toward meeting the goals and in some cases had exceeded them.
The May proposals both support continuation of WMDVBE policies in the restructured electric services industry as they apply to regulated utilities. Both indicate that the utility should continue to be held to the goals established in GO 156. The pool proposal states that to the extent the electric utilities remain involved in generation procurement service, GO 156 will apply as it does today. Under the direct access proposal, compliance costs would be reflected in transmission and distribution rates or in utility procurement services. Both proposals, as well as the Working Group, suggest that the Legislature consider other options, including expansion of the policies to all providers or a complete elimination of the policies.
The Greenlining Institute and Latino Issues Forum recommend expanding the application of the WMDVBE program to include unregulated and out-of-state utilities, as well as other suppliers, generators, and distributors; no other parties commented specifically on this issue. The MOU is silent on this issue. The Framework Parties recommend that any costs necessary to continue WMDVBE programs at current levels should be included as part of a surcharge.
We will apply the WMDVBE statutes and GO 156, unless and until we receive other direction from the Legislature. Generation and related procurement by the regulated utility should be subject to these goals, just as fuel procurement is today.
Costs to comply with GO 156 are related to outreach, internal training, and subcontracting programs, as well as funding the clearinghouse that verifies WMDVBE status. The magnitude of the total compliance costs is so small as to not show up on a typical residential monthly bill. (Fn. 22) For that reason, we will not separately identify these costs on customer bills but will continue to compensate utilities for these costs within the regulated revenue requirement. We do not believe that additional funding or changes to the WMDVBE program are needed for the program to go forward after industry restructuring.
G. Economic Development Programs
Sections 740.4 and 740.7 allows for funding of utility economic development activities to the extent of ratepayer benefit. (Fn. 23) The direct access proposal recommended that economic development program costs authorized by the Commission should be separately identified as a line item. Both May proposals recommended legislative reconsideration of the utilities' role in these programs in the long term, and raise the possibility of taxpayer funding of these activities. We will continue to apply our existing guidelines to funding requests for utility economic development programs. Costs authorized for these activities should be identified as line items on customer bills effective January 1, 1997. We encourage the Legislature to consider whether continuation of utility funding is consistent with a competitive marketplace in the long term.
H. Special Rate Discounts
We currently allow utilities to offer special rates to certain customers based on various statutes (see, for example, 743, 743.1, 744). Utilities are also allowed to offer rate discounts to defer bypass of their systems. Cost-shifting caused by these programs arises because, in general, 100% of the costs associated with discounts are recovered from ratepayers. The costs for these programs are difficult to discern because they are embedded in historical rate design practices. In PG&E's recent Rate Design Window proceeding, we adopted PG&E's proposal that until restructuring is implemented, costs associated with rate discounts should be split between ratepayers and shareholders; once restructuring is in place, 100% of the costs will be borne by shareholders (D.95-10-033). Shifting the cost of discounts to shareholders once greater consumer choice is available is consistent the May proposals.
In D.95-10-033, we recognized that the existence of ERAM gives a utility little incentive to rigorously negotiate the smallest discount necessary to retain a specific customer, because ratepayers effectively compensate the utility for the amount of the discount. We see that this situation will persist in the future, and that retention of customers through rate discounts during the transition period and into the era of competition confers strategic benefits to utility shareholders. In keeping with our policies in D.95-10-033, revenue shortfalls resulting from new rate discounts offered to avoid customer bypass, attract new business, or retain existing or expanding businesses should be shared between ratepayers and shareholders during the transition to a restructured industry.
We will apply these cost-sharing policies to all rate discount cases that come before us during the transition period, including those currently pending. Once restructuring is in place, utilities will not be able to pass the costs of discounts to ratepayers; instead, shareholders should fund any discounts offered to customers.
I. Low-Emission Vehicles
Section 740.2 requires the Commission to encourage energy utilities to conduct research on electric and natural gas vehicles, and 740.3 requires the Commission to implement policies to promote and facilitate development of equipment and infrastructure for low-emission vehicles. Section 740.3 also provides for the recovery in rates of costs incurred in the ratepayers' interest. In D.93-07-054, the Commission established funding guidelines.
Our policies on low-emission vehicles have been addressed in I.91-10-029. That proceeding determined the level of utility funding over the next six years. Utility involvement in LEV programs is primarily focused on building utility infrastructure which will support the use of alternate fuel vehicles. We must determine whether the authorized funding level will be collected within the bundled rate or through a surcharge. (Fn. 24)
Utility involvement in these programs is motivated by public policy goals, which argues that these costs should be recovered as part of the PGC. The funding we are considering in the LEV proceeding is primarily related to utility infrastructure development, arguably part of the distribution utility's functions. Some of the costs associated with infrastructure development are expected to be credited back to ratepayers through charges to LEV rates. Utility customers, unlike nonutility customers, are able to benefit from these expenditures directly through their eligibility for utility LEV programs. For this reason, the costs of utility LEV programs should continue to be collected by the regulated utility and identified as a line item on customer bills, as opposed to being collected as part of the PGC.
One issue not specifically addressed in the May proposals or the MOU is utility expenditures for replacing overhead electric facilities with equivalent underground lines along public streets and roads and on public lands and private rights of way. Undergrounding is carried out by the utilities under a tariffed program. Undergrounding is pursued once a governing civic body has determined that such undergrounding is in the public interest.
We raise this issue because it represents a utility cost which exceeds the costs associated with several of the programs identified above. It is an item that, if allowed to become discretionary, could be expected to be eliminated from the utilities' planned expenditures in a competitive marketplace. It is also a program that the cities and counties of California rely upon as part of their local improvement efforts. This undergrounding activity remains an appropriate activity of the regulated utility, not subject to competition, and therefore should be collected through regulated utility rates.
2. Many QF contracts were structured to allow high capital cost renewables to obtain financing.
3. The 3.3% of revenues would be for investments in energy efficiency, renewables, and transmission and distribution RD&D, but the MOU does not recommend specific allocations to each of these components. It is also unclear whether this funding is meant to apply only to incremental renewable resources or would include existing renewable expenditures. As discussed above, existing renewable resources are either utility-owned or funded under existing QF contracts, and therefore any above-market costs should be covered under the QF transition cost recovery mechanism.
4. Current levels may differ from levels of even two years ago because of contract buyouts which have reduced the amount of renewables on the system. To the extent buyouts. continue to occur, maintaining the target will require the procurement of new renewable resources and may require additional funding.
5. We also authorize funding for low-income weatherization programs as part of the DSM funding level. We address low-income weatherization funding in the discussion of low-income assistance programs.
6. As previously mentioned, the 3.3% of revenues would cover total, unallocated investments in energy efficiency, renewables, and transmission and distribution RD&D. It is unclear how this level was developed, and what current costs it includes. CLECA's July 24, 1995 comments recommended a comparable approach, limited to 3% of revenues.
7. To encourage manufacturers to produce super-efficient refrigerators that significantly exceed appliance efficiency standards, a nationwide consortium of utilities and other entities established a competition between manufacturers to design and market super-efficient refrigerators. The utilities contributed funding to provide a prize for the manufacturer whose product won the competition. This effort motivated manufacturers to produce higher efficiency refrigerators earlier than expected, transforming the market for this product.
8. The public goods charge will collect funds for various activities, including energy efficiency.
9. We recognize that the authorized level of DSM funding is at issue in SCE's 1995 General Rate Case (GRC) and PG&E's 1996 GRC.
10. Gas utilities should also participate in this process in order to provide consistent treatment of comparable costs among competitors.
11. The CEC supports use of a surcharge to collect funds for public goods research. The CEC supports the proposal that funds for research related to monopoly functions should continue to be collected through rates. In their joint comments, PG&E and NRDC do not differentiate what type of research would be supported by funds collected through a surcharge.
12. For example, under our adopted minimum renewables requirement, the competitive market will likely pursue renewables research, but such research has often been considered public goods research. Research related to nuclear waste management, which is tied to nuclear generation, is another area that may provide public benefits but is a component of generation-related RD&D. As these examples demonstrate, research often results in benefits to the general public without having these benefits as its primary focus.
13. Because 740.2 will expire on January 1, 1997, we do not include it on our list of desired legislative modifications.
14. The Legislature and Governor have signaled their continuing support of the baseline rates concept with the passage of SB 248, which amended 739 to expand the category of customers eligible for medical baseline quantities.
15. Low-income assistance programs are provided by both gas and electric utilities. Gas and electric utilities should be treated consistently to ensure that low-income residents receive comprehensive assistance in managing their energy use.
16. This would in essence create a tax on all gas consumption, with some exceptions. SB 678 was not passed by the Legislature in 1995 and has become a two-year bill.
17. Comments by CLECA also support this approach.
18. According to the Fifth Annual Low-Income Ratepayer Assistance Program Report submitted in July 1995 in I.88-07-009, during the May 1993 to April 1994 reporting period, statewide electric utility costs for the Low-Income Rate Assistance program (now CARE) were $64.2 million. This amount is less than 0.4% of the total statewide electric revenue requirement of about $17 billion.
19. The ULTS fund may not have a direct analogy to energy because there is no standard package of basic services for energy as there is for telecommunications.
20. It may be appropriate to extend a reduced service establishment fee to low-income customers as part of the program, as has been implemented for SoCalGas. This can occur today and will serve to reduce outreach costs associated with CARE programs. In addition, the utilities should continue to provide discounted monthly service charges to eligible low-income customers.
21. For example, we would like to see information about the low-income population size, customers served under current utility programs, types of measures installed, and saturation studies, to name just a few.
22. Based on our review of the utility annual reports on WMDVBE, total statewide costs for electric utility compliance with the WMDVBE program were approximately $4 million in 1994. This amount is less than 0.03% of a statewide revenue requirement of $17 billion.
23. In general, the economic development programs anticipated by 740.4 are not rate related, but instead provide technical, marketing, or relocation assistance.
24. Comparable treatment of these costs for both electric and gas utilities should occur.
25. The public interest in undergrounding is found where undergrounding will eliminate an unusually heavy concentration of overhead electric facilities, the area is heavily used by the public and carries a heavy volume of pedestrian or vehicular traffic, and the area is next to or in a civic area or public recreation area or an area of unusual scenic interest.
26. In its June 24, 1994 comments PG&E identified distribution line undergrounding to have an annual cost of $50 million, approximately 0.6% of an $8 billion revenue requirement.