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| Summary and Recommendations | S. Casey | |
| Economic Development Rate Options | S. Casey | |
| Self Generation Deferral Rate Options | S. Casey | |
| Agricultural Bypass Deferral | S. Casey | |
| Environmental Pricing Credit | S. Casey | |
| Fixed Price Contracts | S. Roscow | |
| Real Time Pricing | J. Price | |
| Demand Aggregation Service | J. Price | |
| Revenue and Ratemaking Impacts | S. Casey | |
1. SCE has proposed an extensive range of pricing alternatives to existing tariffs for its customers. In the eight options that SCE proposes it focuses on what it argues are customer needs, or economic competitiveness, or environmental initiatives, or lower rates for all other customers. However this filing must also be viewed from the perspective of the potential competitive pressure faced by SCE under electricity restructuring. Viewed from that perspective SCE is proposing pricing options which will reduce earnings uncertainty both from loss of sales and customers, promote enhanced customer relations, better position SCE for the competitive future, and perhaps even reduce the eventual number of competitors. [footnote: DRA is aware that a number of cities in SCE's service territory are actively investigating options to aggregate load and perform an electric marketing function for electric customers within city boundaries. Targeted marketing by SCE of these options could reduce the size of such an opportunity for these cities.]
2. It is no coincidence that SCE is making these proposals at this juncture. SCE has had previous opportunities to file such proposals with the Commission. Yet now, on the eve of significant changes in its competitive position, SCE presents these proposals. Whatever the motivation for these proposals DRA believes that Commission approval will place SCE in an even more advantageous competitive position than its existing monopoly power already confers. It is from this perspective that DRA has reviewed these proposals. While we are aware of the potential secondary benefits that may result from approval of some of these options such approval must be conditioned upon SCE shareholders paying for an enhanced competitive position.
3. SCE competitive options first reach further than those of any other proposals yet to come before the Commission. For example the Environmental Pricing Credit is available to any size customer, SCE's Fixed Price Contract is available to any customer above 20kw which makes eligible all of SCE's 120,000 GS-2 customers. Furthermore the pricing options have a potentially much larger impact in terms of revenue and customer participation than seen yet in non-tariffed options. For example SCE forecasts that 15% of a combination of its medium sized commercial load and large industrial load could sign fixed price contracts, at a forecast revenue of more than $550 million.
4. For each of the eight options which SCE proposes customers will, of course, have to sign contracts. It also follows that the contracts will, of course, require the customers to take service from SCE for the duration of the contract or pay penalties. Yet SCE states that none of the options will restrict the implementation of electric restructuring, however if SCE successfully and vigorously markets some of these options - particularly the fixed price contract - it will no doubt reduce the initial potential size of the "restructured" market particularly among smaller and perhaps less informed rate classes (with the exception of the Demand Aggregation Option where SCE has stated its intent to end the pilot program if a restructuring decision occurs prior to its termination date). SCE states that customers will be free to terminate their participation in these options "without punitive measures" however liquidated damages will be required for early contract withdrawal, while not insurmountable, this is a barrier to customers participating in new opportunities arising from restructuring. Finally SCE also states that the Commission could take such actions as it deems necessary if, presumably at some future date, the Commission finds the options incompatible with the restructured electric industry. While a laudable statement we are aware of the Commissions understandable reluctance to alter existing contractual arrangements.
5. SCE also states that the Commission could "modify these options if it concludes that is necessary as part of its industry restructuring decision". If the Commission should approve these proposals, irrespective of ratemaking DRA recommends that a generic modification would be to require boiler plate language on the front of each contract to provide the customer with a last minute notification that in signing the contract it may be forgoing other opportunities under a restructured electricity industry. DRA believes that such boiler plate language is particularly required for the smaller customers who lack access to alternative sources of information besides SCE. Finally SCE states that it intends to report contracts on an annual basis to CACD. We support such an intent however details of reporting requirements ed are absent from the SCE narrative and DRA will pursue this matter with SCE.
6. DRA recommends that the Commission not adopt either of the ratemaking proposals of SCE. The ERAM option simply opposes the Commissions trend toward involving shareholders in the decision to offer discounted contracts. SCE's alternative of apparent symmetrical treatment is, based on the utilities own forecasts, a significant direct contribution to shareholder wealth. In DRA's view symmetry consists of utility shareholders paying for discounts as the price to be allowed to provide the utility the freedom of offering these contractual options. SCE shareholders gain from the opportunity to offer these discounted contracts - they gain in the opportunity to reduce future earnings uncertainty, they gain by new opportunities to maintain customer base, they gain in market intelligence, and they gain by the opportunity of developing new customer relationships. PG&E in its recent flexible pricing option package was willing to agree to provide significant shareholder investment for these opportunities, without any so called direct shareholder upside in the form of incremental revenues. SCE's flexible pricing package is broader and larger than that of PG&E, consequently DRA recommends that SCE provide 100% of the discount flowing from its proposed pricing options. Revenues from these options should be treated as standard revenues, and apportioned to the usual balancing accounts (with the potential exception of the differences attributable to the Fixed Price Contract).
1. SCE proposes to offer to manufacturing firms with load of at least 200kw up to 4000kw a variety of economic development rates to encourage customers to add or to retain load. SCE's proposal requires customers to enter into a seven year contract term in exchange for five years of discounts. An additional credit may be available to offset added facilities charges. About 2850 of SCE's existing customers could qualify under the manufacturing criteria proposed by SCE, these customers represent about one third of the large power consumption on SCE's system. The customer can take service under a partial or full requirements contract. SCE's proposal requires the full requirements customer to take service from SCE (or face potential penalties). The partial requirements customer must take, or pay, for a set firm service level, however such customers are also prohibited from purchasing any electricity from anyone other than Edison.
2. SCE proposes that the Commission retain the authority to amend or terminate the EDR agreement. DRA assumes that customers will be required to sign an affidavit that the EDR is a material factor in its decision to remain in, expand in, or locate in SCE's service territory however pro forma contracts for these options have yet to be filed with the Commission. The customer must also demonstrate "commitment of assistance, resources, or incentives from other public or private entities working toward economic development of communities within the service territory". SCE proposes to initially limit the total load for these options to 100MW, or about 6% of existing manufacturing load, SCE expects that it will sign customers at a rate of 20MW per year. Assuming that customers contract at the 20MW per year rate, and accounting for only the expansion and attraction options SCE forecasts, on a present value basis, based on the assumption that the revenues are incremental, an additional $57 million of revenue set against a discount for all options of about $17 million for a total positive revenue impact of about $40 million.
3. SCE asserts that these incentive rates are required for two reasons. First is the continued weakness exhibited by the Southern California economy, second is "predatory attraction" efforts. Edison asserts that such efforts include utility incentives like lower electric rates, to lure manufacturing facilities from Southern California. Edisons assertions are conclusionary and unsupported by specific facts. Edisons showing, under existing ratemaking treatment, does not support a finding that the discounted contracts are reasonable or in the public interest.
4. First SCE cites data regarding the recent very large job losses that have occurred in Southern California, particularly in manufacturing, and it also points to the likelihood of further cutbacks in defense spending, apparently this situation is intended to provide one level of support for these EDR options. If Edison is implying that EDR options are a short run "fix" to economic problems then the Commission should consider the contract length. If the Commission approves these EDR proposals customers can sign such contracts anytime over the next five years and, in the case of two EDR options, not actually commence the discount period for a further two years. Hence a customer could be served by these discounted options in the year 2008 or 12 years from now.
5. DRA believes that the Commission should give little consideration to the vagaries of near-term economic forecasts. Although SCE cites some short term negatives for the Southern California economy, ( a predicted further 60,000 to 125,000 statewide job loss from more defense cuts), other commentators have a far more favorable outlook for the California economy predicting that job growth in the state will outpace national job growth in 1996. [ footnote: For example the October 1995 forecast for the California economy by Bank of America predicts that job growth in 1996 will be 2.4% and that California unemployment will drop from 8.6% in 1994 to a forecast 7.8% in 1995, to 7.4% in 1996. The Bank states in part "But today's economy is significantly different than that of the recessionary California of a few years ago. The bulk of the job losses during the recession were in three broad industries: manufacturing, construction, and retailing. Today, manufacturing jobs are stabilizing, retail jobs are considerably higher than a year ago, and construction jobs are growing quite strongly". Additionally the California Business Roundtable 1995 annual survey found that 47% of respondents planned to add more workers in 1996, this apparently represents a significant increase from the last survey when only 33% of respondents stated intentions to hire more workers.] The point is not whether one economic forecast is likelier to be "right" than another - they may all be equally inaccurate - the point is that the Commission ought not to permit long term discounted rates based on short-term economic forecasts. Edisons showing is unpersuasive given such contradictory forecasts.
6. Edison's argument that efforts by other states to "lure" businesses via incentive packages or adopting preferential electric rates for new business is also meritless. In the first instance, it is DRA's understanding, and certainly SCE's testimony in other proceedings, that there is significant effort within California, both at the local and state level, to retain existing business and attract new business, much of this effort is funded by taxpayers via funding of the State Department of Commerce or via local actions to offer tax breaks and other considerations to attract business. Edison's rationale is tantamount to taxing ratepayers (via utility rates) to pay in another way (the discount) to attract or retain manufacturing business in Southern California on a tariffed basis.
7. While SCE points to a number of other utilities that have retention or attraction tariffs SCE presents no evidence that rate discounts offered by other states were necessary or important in retaining or attracting business. Edison's failure to present any such evidence is consistent with the fact that business location decisions will consider many factors and (except for electricity intensive industries) frequently the price of electricity is merely a tertiary factor in any location decision (this is not to deny that business will not negotiate to lower its electricity prices with threats of relocation).
8. The relative unimportance of discounted electricity prices is shown by SCE's own experience with its existing Economic Development Rate (ED). Since its inception in 1992 one customer has been directly placed on the ED rate and another customer has recently been granted an ED rate due to unusual circumstances. This low level of participation has occurred despite the fact that not only has SCE offered a discounted electricity rate but that the State of California and local governments have offered a variety of incentives to locate in economic development zones.
9. Furthermore Edison's assumption (implicit here, explicit in the SSDGR chapter) that the Commission's approval process for any contracts that SCE would sign under the rubric of economic development are too slow is speculation. In the case of PG&E's special contract with Genetech the process, from initial PG&E filing to Commission decision, took 7 weeks. Any business making a significant location decision which requires, incentives or special arrangements from local or state government should be able to factor into its decision-making review of its discounted contract. The alternative, under SCE's major ratemaking proposal, is to place the complete trust of the requirement for this discounted contract with SCE, without any Commission oversight on behalf of SCE's other ratepayers.
10. Hence DRA's major recommendation, in response to SCE's major ratemaking proposal that all discounts flow through ERAM is to reject SCE's proposal and require SCE to file special contracts for any of these ED options. DRA's secondary recommendation, discussed in Chapter 9, would allow contracting by tariff for ED options if shareholders absorb 100% of the discount, and within the context of the overall ratemaking treatment of these flexible pricing options as a package.
11. A secondary issue raised by Edison's proposal but discussed in the SCE testimony is contract limitations. Edison is potentially seeking to use ratepayer money to "compete" with other California utilities for industrial customers. In D. 95-10-033 the Commission addressed this issue for the business attraction contracts that PG&E proposed. The language in the PG&E decision should be adopted for this set of proposals regardless of ratemaking treatment. [footnote: "The Business Attraction Option shall not be available to existing service customers and existing load of another California Utility (as of the time that PG&E would otherwise make an offer of the Business Attraction Option), even if said existing customers should relocate into PG&E's service territory .............(e.g. restrictions contained in a franchise or certificate of public use and necessity, to the extent applicable". (Ordering paragraph 10, D. 95-10-033 p. 61).]
1. SCE proposes two new tariff rates:- a Simplified Self-Generation Deferral Rate (SSGDR) for customers considering uneconomic bypass of the SCE system and an almost identical Simplified Self-Generation Rate for Existing Projects (SSGREP). These proposed tariffs are intended for customers from 200kw to 10MW size. For customers over 10MW size who are considering decisions to either begin or continue self-generation SCE proposes the reinstatement of the EAD procedure to "speed" the decision-making process for larger size projects.
2. SCE argues that the existing special contract process is unwieldy and impractical from a customer perspective for smaller projects; SCE also argues that the existing process requires a great deal of SCE's and the Commission's time to review and administer the contracts. SCE states that its proposal will not alter the current method of analysis for self-generation contracts - the viability of the proposed project will be determined, as will the method of establishing a competitive rate, and ensuring the ongoing administration of the contract.
3. SCE describes the SSGDR tariffed approach as first establishing eligibility (so as to eliminate free-ridership); next ensuring that only eligible load will be discounted; then establishing the project specific characteristics so as to choose a rate from pre-established project matrices; and finally allowing for adjustments in the rate to take account of changes to the customers consumption or other factors. SCE proposes to adjust the values of the project matrices (i.e. the tariff values) each year based upon revised survey data submitted to the Commission for prior approval. SCE proposes a price floor at least customer specific marginal costs plus 10%. Under the SSGDR option the customer will be offered two alternative service options - a take-or-pay option equivalent to 25% of the net ouput from the project; and a full requirements options where the customer purchases all energy needs from SCE pursuant to the SSGDR. The agreement is for a minimum of five years renewable for a further five years. SCE 's proposal provides for termination by either party with two years notice. SCE also proposes to install advanced metering to provide two-way communication between the customer and Edison, this will entail an additional monthly metering charge. SCE's tariff proposal also allows for customers to obtain the value of the discount via energy efficiency measures rather than reduced rates. SCE expects about five customers a year to take service under this tariff. The value of the expected discounts over a five year period (1996-2000) is $1.4 million.
4. SCE proposes the SSGREP based on its arguments that some existing bypass projects in its service territory face increasing O&M costs, major and costly overhauls, and reduced thermal loads. In combination these factors may change economic bypass projects into non-economic bypass projects. Under this scenario SCE's SSGREP option offers customers an option to shut-down the project and purchase from SCE. SCE's SSGREP applies the same method and project matrices as for the SSGDR. SCE calculates that about $8.4 million is lost in CTM each year due to customers in the 200kw to 10MW range generating their own electricity. SCE estimates that on average about five customers per year will return to the system under the SSGREP, and that over the five year period an additional $33 million of revenue will be added minus about $1.4 million of discount.
5. SCE has not made a convincing case for changes in the current Commission procedures for special contracts for cogeneration bypass deferral. SCE has applied for and received approval of 7 special contracts since 1988 (in comparison PG&E has received approval for 19 contracts ). These contracts have ranged from 800kw to 78MW in size. Special contracts approval processes are necessary to ensure safeguards for other ratepayers - who are paying for the discount via ERAM. Requiring Commission approval may have helped to discipline SCE to offer special contracts to only the most clear cut cases of uneconomic bypass. Based on SCE's proposals the only step in the special contract process avoided by SCE's discounted tariffs is Commission overview and approval.
6. Furthermore SCE has not shown a convincing need for a discounted tariff based on an upsurge in self-generation interest by customers. DRA cannot find a clear forecast of an increase in self-generation in any of the SCE documentation supporting its case. Rather it appears that given the existing 485MW of self-generation in SCE's territory the "easiest" self-generation projects have either been completed or deferred by SCE's special contracts. What SCE's own data show is that since 1988 most projects below 1MW were completed in the 1988 (23 projects) , followed by 1990 (18 projects) and more recently have been reduced to 10-12 projects a year. In total projects below 1MW, (since 1988) only account for 14.5MW of bypass.
7. Since 1988 a total of 99.5 MW of projects above 1MW have bypassed the SCE system these 13 projects do show a consistent pattern of project completion in recent years with 3 projects a year since 1992. However combining these totals shows that of the 485MW of self-generation in SCE's service territory some 371MW was already installed (that is over 75%) prior to 1988. SCE's own forecast of future bypass shows 3 projects above 1MW in 1996, 2 in 1997, and three in 1998. Each of these potential projects has already been offered a special contract, or in some cases (in anticipation of the Commission presumably agreeing to the SCE proposal) an SSGDR. Hence DRA presumes that a significant amount of internal work has already been accomplished on these particular projects.
8. The same arguments also apply to the SSGREP. A number of existing bypass projects have returned to the SCE system in the last several years. SCE has provided data to DRA showing 62 self-generation projects representing 43 MW returning to the SCE system since 1986, with many of these projects having no particular DSM or special rate package offered as an inducement. In short Edison has not demonstrated that a DRA special need exists for these potential customers to have a discounted tariffed rate.
9. However devoting Commission and SCE resources to a special contract process for customers of less than 1MW raises cot-effectiveness issues (indeed this the key reason why the Commission criteria for special contracts specified that projects should be over 1MW in size). This of course raises the question of why SCE should establish a contracting process for such customers in the first place. 101 self-generation projects below 1MW have been installed in SCE's service territory since 1988 but these projects only account for 10% of the self-generation capacity installed in that time. Hence DRA does not believe the below 1MW projects require the elaborate process SCE proposes. But since SCE proposes such a process DRA would not object if SCE "bundled" its smaller self-generation contracts into packages of 1MW or more for Commission approval.
10. SCE asserts that it needs a tariff process because customers cannot factor into their planning the uncertainty regarding timing of Commission decisions on special contract applications. However SCE could not provide written customer concerns to that effect. Moreover in checking the customers who were verbally concerned about Commission timing we found that included in the list supplied by SCE were a college, a hospital, and a laboratory. On its face concerns about timing from institutional customers (who presumably plan over long time periods) seems puzzling.
11. Finally SCE requests that the EAD process be restored for SCE applications for SSDGR or SSGREP applications for special contract loads greater than 4MW. DRA does not find any merit in the arguments raised by SCE to return to the EAD process. Rather given the increasingly competitive nature of the electric market it is imperative that the Commission have a complete record on and complete review of such contracts which ratepayers would fund. DRA would not object, however, if an EAD process was instituted for contracts where Edison shareholders pay 100% of the discount.
1. SCE has proposed continuation of its TOU-PA-6 rate which offers an alternative to reduce the incentive for agricultural customers to convert from electric to natural gas or diesel internal combustion (IC) engines for agricultural water pumping. SCE estimates that 2000 existing agricultural water pumping customers have the ability to bypass SCE. Given SCE assumptions that these customers can be retained at discounted rates above SCE's marginal costs, but that administration and Commission approval of potentially 2000 customer contracts is not cost-effective, SCE requests that this tariffed discount continue. SCE's proposes, based on the cost of the natural gas and diesel alternatives, four rates - two discounted rates for customers, depending upon load size, considering the IC alternative - and two discounted rates for customers, depending upon load size, considering the natural gas pumping alternative. Both discounted rates provide for a three percent premium, above the alternatives, for electric service. The potential reductions in rate level for these customers varies from about 10%-13% depending upon kw size and hours of operation.
2. DRA does not object to this rate proposal. However DRA believes that SCE shareholders should absorb the value of the proposed discounts (in the PG&E case DRA is recommending that PG&E absorb 50% of the value of the discount on a stand alone basis). SCE forecasts that the discount required to maintain these customers would be about $2.5 million to retain a revenue amount of $32 million.
1. SCE proposes to offer ANY customer the option of a pricing credit ( in the form of a bill reduction not a cash payment from SCE) for the addition of new electric load. Specifically the new load is due to customer installation of any one of twenty one electrotechnologies. The credit will be calculated based on 50% of the contribution to margin over a specified period (3,5, or 7 years depending upon length of agreement). Contribution to margin is defined as the differential between long run marginal cost and tariffed rates. The credit would only be available to incremental load (i.e. customers replacing one electric load with a newer electrotechnology are ineligible). SCE reserves the right to separately meter this incremental load. Edison forecasts that this credit could result in the addition of over 1 billion kwh of additional load by 2000, and in present value terms an additional of $160 million of revenue, which, after deducting the $32 million expected value of the discount, results in almost $128 million of net revenue. Apart from the Fixed Price proposal, this option is by far the largest in terms of kwh and dollar impact.
2. SCE premises the need for the credit on improvements to regional environmental quality and customer economic competitiveness, while arguing that all customers will benefit via lower rates.
3. While these are laudable goals SCE has apparently whether customers would themselves install these technologies, without the need for an SCE rebate, due to the same considerations (pressure of environmental regulations and economic competitiveness) , cited by SCE. Indeed SCE does not even require the minimalist "free-rider" protection of a customer affidavit for this particular option.
4. Furthermore SCE's own estimate of the value of its "rebate" for some of these technologies varies from 3% to 49%. While DRA can appreciate that a 50% offer might certainly induce some customers to purchase or finance the electrotechnology (or at least make that decision in the short rather than longer term) we have difficulty accepting the notion that a 3% or a 11% or a 26% offer carries the same inducement. Of course the whole question of free-ridership is also ignored by this approach.
5. Finally SCE's environmental analysis appears to have some gaps. First SCE appears not to have completely captured the impact of its own emissions increases by neglecting to include the impact of increased generation on SCE's SO2 and PM10 emissions. Secondly SCE may not completely captured the impact of RECLAIM trading credits.
6. Since SCE's proposes that these environmental pricing credits flow through ERAM, that is all ratepayers will pay for the credit, DRA recommends that the Commission reject the option. SCE filed this type of electrotechnology promotion in its most recent General Rate Case. The proposed ALJ decision in that case (A.93-12-025) found, regarding a program for $1.5 million in funding, that SCE had not met its burden of proof in justifying its program under the DSM rules. In this instance SCE is proposing to fund electrotechnologies at the $34 million level (present valued) over five years, however there is no showing regarding the DSM rules for fuel substitution/ load building. On this basis alone DRA believes the ERAM ratemaking treatment sought by SCE should be rejected. Furthermore SCE is seeking ERAM treatment since SCE will indirectly fund these options - not through a revenue requirement increase but through a bill reduction - which, ceteris paribus, will increase rates for all other customers through a reduction in all balancing accounts. Therefore this is ratepayer funding for the promotion of electrotechnologies. The argument that the option will increase load to offset the bill reductions requires, as shown above, acceptance that the load would not have occurred absent the SCE inducement. DRA is not convinced that it is SCE's "offer" that will induce a customer purchase. Given SCE's arguments regarding the environmental and economic advantages of this technology DRA can only conclude that customers, over time, will install this technology. Differentiating between those customers who did so solely due to SCE's credit and those who did so in the normal course of business is impossible. DRA urges that the Commission once again reject this option.
7. The question of other ratemaking treatment for this option is considered in Chapter 9.
1. In Chapter IX of its July 1995 testimony on Flexible Pricing Options, Edison proposed to offer some of its customers either three- or five-year fixed price contracts. This testimony was revised in September 1995 to offer any term ranging between 12 and 60 months. According to Edison, the proposed "fixed price contract tariff option" would provide an alternative to Edison's traditional tariffs which are typically subject to changes on an annual basis. Edison believes that the new option would be attractive to business customers wishing to ensure stability of their electricity costs over a period of time longer than one year.
2. The fixed price contracts will be available to general service customers with demands over 20 kW, and large power customers with demands in excess of 500 kW. Edison proposes to limit this "experimental pilot" program to no more than 15% of the projected 1996 sales for TOU-8 and GS-2 customers.
3. The pricing structure of fixed price contracts is composed of two separate components. First, a levelized forecast of rates provides a stable price relative to Edison's forecast of its otherwise applicable tariff rate levels. Second, a risk mitigation fee is calculated by Edison and added to the levelized rate to determine the total fixed price rate. This rate will not change for the life of the contract. A customer on Edison's proposed Schedule RTP-TPP-1 may also choose to apply the fixed price to any percentage of its "base period usage" up to 100%. Base period usage is based on the customer's historical usage for the past 24 months.
4. Edison states that its shareholders will assume the risk that actual tariff rates vary from the forecasts used to set the fixed rate for each customer. This will be accomplished by making entries to the ERAM and ECAC balancing accounts to reflect revenues that customers would have paid if they had remained on the otherwise applicable tariff. In this way, "nonparticipants are fully protected for the risk of any difference between the base rate and fuel-related revenue that would have been collected from the customer and revenue actually collected from the fixed price contract." (Edison testimony, Chapter IX, pp. 95-96)
5. As noted above, Edison's shareholders will take the risk of forecast variations that might affect the levelized rate forecasts, such as changes in inflation, fuel price, and unanticipated regulatory changes. However, in return for assuming these risks, Edison proposes to be compensated by charging each fixed price customer a "risk mitigation fee". According to Edison, "this fee would be designed to compensate Edison for risk of variations in fuel prices and volumes which arise between the time the forecast was fixed and when the customer requests the fixed price contract and in future years" (Chapter IX, p. 96). Edison does not quantify the level of this fee, or its magnitude in relation to the levelized base rate. Edison's testimony is also unclear regarding whether the revenues collected through the risk mitigation fee could exceed the revenues lost if actual contract revenues differed from forecast revenues.
6. Among other terms and conditions, Edison proposed that "the customer will agree that Edison will be its sole supplier of electricity for the account during the term of the contract" (Chapter IX, p. 97). This provision seems unnecessary to implement the essence of Edison's proposal, which allows the customer to enter into a fixed price contract for only a certain percentage of its base period usage. Requiring this customer to nevertheless agree to use Edison as its sole supplier would seem to unreasonably restrict the customer's options regarding electricity supply in the future restructured electricity industry. A multi-year contract at a fixed price, even if it is only for part of a customer's total anticipated demand, ought to be sufficient certainty for Edison. DRA recommends that the Commission reject Edison's "sole supplier" requirement.
7. DRA is concerned that a significant effect of Edison's fixed price contract proposal, however well-intentioned, will be to lock some of Edison's customers into long-term relationships with Edison prior to industry restructuring. This outcome would conflict with efforts to preserve potential competitive options and foster new competitive alternatives where none exist today. By implementing this proposal now, the Commission would enable Edison to engage in "cream-skimming" and thereby remove many customers from the competitive marketplace before real competition even emerges. Furthermore, DRA believes that Edison's proposal, as presently structured, unreasonably prevents these customers from benefiting from whatever competitive options may emerge after industry restructuring is completed.
8. In order to meet customer needs for stability today, while leaving future competitive options open, DRA proposes that the Commission consider three alternatives to simply adopting Edison's proposal:
1. Postpone action until the final restructuring decision is issued;
2. Limit the term of the agreement to a shorter period, perhaps with liberal renewal rights;
3. Provide less punitive off-ramp provisions.
1. Edison proposes to expand its existing real time pricing (RTP) program by adding two new tariffs. Its proposals for RTP (as well as its demand aggregation proposal, discussed in Chapter 8) are generally experimental in nature, and are within the nature of proposals that would normally be considered in rate design windows. As discussed herein (and in Chapter 8), DRA generally accepts these proposals provided that certain conditions are satisfied.
2. Edison's Exhibit II-2 (Chapter VII, Section K) and DRA's Exhibit II-25 (Chapter 12) in Phase 2-A of this proceeding offered proposals and recommendations for Edison's existing Schedule RTP-2 and a new Schedule RTP-3; other options also exist and, because their rate design is based on either Schedule RTP-2 or Schedule TOU-8, their rates would be adjusted as well. As can be seen from those discussions, RTP has existed in Edison's tariffs for several years, with Edison's Exhibit II-2 stating that 35 customers are being served on Schedule RTP-2. In Phase 2-B, Edison proposes to add two new RTP options: Schedule RTP-3-GS for customers with demands exceeding 20 kW, and Schedule RTP-TPP-1, which prices incremental usage based on the hourly marginal cost of energy and capacity.
3. DRA accepts Edison's proposals to create these new rate options but finds that Schedule RTP-3-GS alone does not meet the needs of Edison's GS-2 and TOU-GS customers, and therefore recommends additional options that should also be offered. (If only Edison's version of RTP-3-GS were offered, DRA would oppose it as being inconsistent with current state and federal regulatory practice, as serving Edison's needs rather than its customers' as the era of electric industry restructuring approaches, and as not being sufficiently cost-based.) [footnote: In Phase 2-A, Edison attributed its proposed RTP-3 (also used in RTP-3-GS) ratcheted maximum demand charge structure for all T&D costs as being consistent with Federal Energy Regulatory Commission (FERC) procedures. In addition to overlooking that the CPUC has different rate design policies than FERC and that Edison was referring to wholesale, not retail, rate structures, this claim by Edison mischaracterizes FERC's practices: its recent Notice of Proposed Rulemaking on transmission access and pricing requires utilities to offer a variety of rate options to customers (e.g., annual, monthly, and weekly capacity reservations, in addition to opportunities for innovative rate structures). Instead of addressing customers' needs, then, Edison's proposed rate design serves its own goal of reducing seasonal revenue variations. As shown in DRA's Phase 2-A Exhibit II-68 (p. 8), Edison's ACRM methodology for allocation of generation capacity costs also reduces seasonal revenue swings.]
4. DRA's recommendations are as follows:
5. The Commission is currently debating a restructuring of the electric utility industry, intended to develop competition in generation supplies. Along with a commitment to ensure that benefits from restructuring are received by all customer classes, RTP is frequently cited as a way to achieve those benefits - these citations include (but are certainly not limited to) the one quoted by Edison (R.94-04-031/I.94-04-032, pp. 31-32):
"Although optimally all customers should be able to derive virtual direct access benefits by responding to real time price signals, experience in England and Wales suggests that supplying each customer with an appropriate meter will be time consuming and may best be approached in a phased-in manner. We thus propose that utilities install [RTP] meters in a phased-in manner, starting with large customers not already equipped with such meters, and reaching small customers in 6 years after the pool is formed."
The Commission repeated this general intent as recently as its May 1995 Proposed Policy Decision in the electric utility industry restructuring proceeding.
6. This direction is consistent with DRA's expressed interest in various recent rate cases of developing RTP options for additional customer classes. In Exhibit II-25 (p. 12-3), in Phase 2-A of this proceeding, DRA stated:
"DRA is also concerned that Edison currently lacks a RTP tariff for small and medium commercial and industrial customers. Although Edison states that other utilities' RTP rates are targeted at large customers, DRA has previously emphasized the need for equity among customer classes in structuring rate options, and the Commission has supported DRA's goals in developing RTP. Furthermore, the Commission's current discussions of electric industry restructuring frequently turn to RTP as an important part of the future structure, and this GRC is the ideal time to begin developing RTP for additional customer classes. The structure that DRA recommended for Schedule TOU-8-RTP is simple enough to be feasible for implementation for smaller customers. Therefore, DRA recommends adoption of a new Schedule TOU-GS-RTP for small and medium light and power customers, with structure similar to TOU-8-RTP, for which all customers eligible for Schedule TOU-GS-2 would also be eligible. This rate structure simply replaces the on-peak demand charge with a charge based on a customer's average load during on-peak hours of summer weekdays, and this charge is set as a ratio (1.25) to the final adopted TOU-GS-2 demand charge to achieve revenue neutrality. Finally, any incremental metering or billing expenses should be recovered through a meter charge."
Because Edison later introduced a RTP proposal for medium commercial and industrial customers in Phase 2-B, DRA deferred this recommendation so that it could be considered in the context of all new options that may become available to these customers.
7. Although great reliance must be placed on RTP as a means of ensuring that smaller customers benefit from electric industry restructuring, RTP can take many forms, and the needs of smaller customers concerning the structure of RTP rates are not really known. What is known is the response of smaller customers to existing rates: Edison itself has recognized that many of its smaller customers have difficulty with rate designs that include high demand charges, and offered proposals in Phase 2-A to address this issue. In Exhibit II-2 (Chapter VI, Section I) Edison proposed new time-of-use (TOU) rates, Schedules TOU-GS-1 and TOU-GS-2-A, with low (or no) demand charges, explaining: "… these customers find a demand-metered TOU schedule difficult to understand. Edison is proposing Schedule TOU-GS-1 to respond to the needs of those customers. … Edison is proposing Option A of Schedule TOU-GS-2 in response to requests by demand-metered LSMP customers who cannot manage as well the higher summer on-peak demand charge under Option B. These customers consider the increase in their summer monthly bills under the current TOU-GS rate, due to inadvertent and intermittent summer on-peak demand, highly punitive." During hearings, Edison's witness Goeddel elaborated on the need for rate options without high demand charges, for smaller customers (Tr. Vol. 68, pp. 7659 - 7660):
"Q. Has one response also been Edison's proposal for a Time-of-Use GS No. 1 and Option A of Schedule TOU-GS-2?"
"A. Yes. In addition to complying with the Commission's order to handle the bill impacts in this situation, we found that there was a need for additional options for customers that were on energy-only rates, and so we proposed in this proceeding a time-of-use rate schedule without demand charges for our smallest commercial customers to make that option available to them. … We currently have a time-of-use rate for our medium-sized commercial and industrial customers, our GS-2 customers, that has fairly significant demand charges on it and fairly low energy charges on it, and these lower load-factor customers that were transferred to Schedule GS-2 could not really take advantage of that kind of schedule, having a low load factor. So in this proceeding we've proposed an additional time-of-use rate for these lower load-factor demand metered commercial and industrial customers that has lower demand charges but higher energy charges such that the schedule is still revenue-neutral but there is a time-of-use option available for these customers."
8. As in TOU rate design, it is appropriate to offer a variety of RTP options to meet the differing needs of different customers; this is especially true in important but relatively unexplored areas like RTP rate design. For smaller customers, the general desire to accurately reflect variations in energy costs must be balanced with the need for customer understanding, which Edison emphasized in its arguments during Phase 2-A. In order to determine the proper balance of these factors, experimentation with a variety of rate options for these smaller customers will be appropriate, whereas Edison introduced only one option, which then has a feature that many customers are known to dislike: the level of non-time-varying, maximum demand charges on RTP-3-GS exceeds the total level of time-varying plus non-time-varying demand charges on Schedule TOU-GS-2-B. If customers found TOU-GS-2-B's demand charges punitive and difficult to understand, one can imagine their reaction to ratcheted maximum demand charges (especially on a RTP tariff, with sophisticated metering and rate design) that include costs of service that Edison otherwise explains occur only at times of system peaks (Edison/Jazayeri, Tr. Vol. 69, pp. 7864 - 7865):
"Q. If I could direct your attention to page 54 of Exhibit II-2, I have a couple questions for you. At lines 12 through 13, you state that: 'Facilities-related charges are designed to recover the cost of transmission and distribution facilities installed to serve a customer.' Do the costs you are referring to exceed 10 percent of transmission or 68 percent of primary distribution marginal cost?"
"A. The costs I am referring to as facilities-related charge, there are basically the noncoincident portions of marginal transmission and distribution costs. And as you mentioned, that consists of 10 percent of the transmission costs and 68 percent of the marginal distribution costs."
"Q. Okay. Is your answer no then, that those costs do not exceed the 10 percent of transmission or 68 percent of primary distribution marginal cost."
"A. Yes, it does not exceed the sum of those two values."
…
"Q. For a customer who has a meter that is capable of recording the time when the customer's peak load occurs, like a time-of-use meter, would the cost base level for any facilities-related charge or other maximum demand charge exceed 10 percent of transmission or 68 percent of primary distribution marginal cost?"
"A. When we allocate, as I said, those two costs, transmission and distribution costs, to various customer groups, those are considered to be the non-coincident portions of those. And basically those are the ones that we apply to a customer's maximum demand regardless of when it occurs, regardless of whether the customer has a time-of-use meter or not. Depending on when his maximum demand occurs and what the magnitude of what that maximum demand is, we charge him those volumes that you just mentioned scaled out basically by an EPMC factor."
"Q. Okay. And they don't exceed those values?"
"A. Under our proposal, they do not."
Because its demand charge structure is not cost-based, DRA opposed Edison's proposed Schedule RTP-3 in Phase 2-A, where it was offered without a broad context of experimentation with a variety of rate structures, as DRA proposes here for the GS-2 and TOU-GS customer classes.
9. Furthermore, Edison has admitted that it does not have experience in serving smaller customers on RTP rates, and that implementing a workable rate could be difficult (SCE/Jazayeri, Tr. Vol. 69, p. 7871 - 7872):
"Q. Okay. I have a couple of questions about real-time pricing, I think, your discussion on page 58 and 60 of your testimony. You describe Edison's real time pricing programs and certain programs of other utilities. Given this discussion, does Edison have any direct experience in serving customers with loads in the [range] of Schedules GS-2 or Time-of-Use GS on real-time pricing rates or in a market - marketing real-time pricing to these customers?"
"A. I think we have a significant amount of experience in marketing of the time-of-use rates to general service customers. … In terms of providing real-time price signals, which I assume that you mean hourly prices, we do not have any experience with the general service customers because they do not have a program, RTP program, for our general service customers yet. …"
"Q. Do you think designing a successful real-time pricing program for GS-2 and Time-of-Use GS customers is a fairly easy task to accomplish?"
"A. I mean the technical calculations are pretty easy. Their communication with the customer, trying to make the customer understand the nature of the rate, to be able to establish the communication equipment, to send those price signals to the customers, that could be difficult."
Given the importance of RTP in implementing electric industry restructuring and ensuring that its benefits are received by all customer classes, this is a critical time for meaningful experimentation with alternative RTP rate structures. Edison has responded to customers' concerns in its proposed structure of TOU rates by offering a variety of rate options, and DRA recommends that as it attempts to set up "flexible pricing" options to meet customer needs, it must determine what those needs are in RTP as well.
10. Useful experimentation to serve this purpose must include a basis for judging any effects that are observed in customers' response to an experimental rate option. Edison's proposed Schedule RTP-3-GS lacks such a basis because it departs significantly from existing rate structures in its demand charge in addition to the RTP characteristics of its rate design. If a response to the rate structure is observed, one would not be able to tell why it occurred. At this time, DRA does not reject Edison's RTP-3-GS proposal as a useless experiment, but for it to actually be useful, it must be accompanied by other tests of RTP for smaller customers, so that the effects of innovative rate features can be distinguished from each other. (For the same reason, DRA recommends that if Edison's proposed RTP-3 demand charge structure is adopted in Phase 2-A, an option for large customers, over 500 kW, with RTP-2's time-varying T&D charges and RTP-3's market-based generation cost component should also be implemented, for meaningful experimentation. If Edison's proposed demand charge structure for RTP-3 is rejected by the Commission in Phase 2-A, in favor of DRA's variable T&D charges, it should be rejected for Schedule RTP-3-GS as well.)
11. In addition to RTP-3-GS, options available to GS-2 and TOU-GS customers should include: (i) a rate structure, TOU-GS-RTP, similar to Edison's existing Schedule TOU-8-RTP, as proposed by DRA in Exhibit II-25, and (ii) a Schedule RTP-2-GS, similar to Edison's existing Schedule RTP-2. If Schedule RTP-3-GS is feasible for smaller customers, so are TOU-GS-RTP and RTP-2-GS: the simplicity of TOU-GS-RTP was discussed in DRA's Exhibit II-25, and Edison's witness Jazayeri stated that RTP-2 is also now administered on a simplified basis (to determine which of its nine pricing menus is in effect, the only thing the customer needs to know is the previous day's maximum temperature at Los Angeles Civic Center; Edison/Jazayeri, Tr. Vol. 70, pp. 7888 - 7889). If DRA's area load analysis methodology is used in Phase 2-A for hourly allocation of T&D costs on Schedules RTP-2 and/or RTP-3, it should be applied in Phase 2-B as well. Otherwise, the "PCAF" formula that is part of DRA's analysis should still be applied when time-differentiated T&D rate components are used, but should be based on generation system-level loads rather than DRA's preferred geographically-disaggregated loads. DRA's recommended rates for RTP-2-GS, and for the T&D component of RTP-3-GS, are presented in Tables 7-1 and 7-2; for comparison to Schedules RTP-2 and RTP-3 (and because rates using the PCAF formula with generation-level loads may be needed to complete the record from Phase 2-A), these schedules' rates are presented in Tables 7-3 and 7-4.
12. Edison's rate design for Schedule RTP-TPP-1 shares many of its features with the existing Schedule TOU-8-CR-1 (with the obvious addition of RTP energy and capacity charges). Thus, it provides a means for comparing customers' rate response on this tariff with customers' behavior on related schedules, and therefore constitutes a reasonable experiment. For Schedule RTP-TPP-1, Edison proposes to allocate marginal transmission costs to different hours of the day based on the Commission-adopted methodology for allocation of transmission costs in calculating rate groups' marginal cost revenues. The methodology for this allocation has been an issue in Phase 2-A, and will be decided by the Commission prior to a decision in Phase 2-B. The "Commission-adopted methodology" used in RTP-TPP-1's rate design should be the then-current method, which is not necessarily the historical method used by Edison in preparing its proposals.
13. Edison proposes that the service contracts for Schedules RTP-3-GS and RTP-TPP-1 will require customers to keep real time prices confidential, as commercially sensitive, proprietary information of Edison. Edison proposes that all price information would be for the private use of program participants only, and that similarly customer information would not be disclosed. If the Commission adopts these provisions, it must ensure that the Commission and its staff retain the ability to readily review all aspects these programs' operations and results. All information that is now available (on a confidential basis) to the Commission and its staff, including customer load and billing data and prices that are charged to customers, must continue to be available. To do otherwise would jeopardize the Commission's ability to exercise regulatory oversight of the utilities and of the competitive markets that the Commission is seeking to create.
14. The Commission should monitor the implementation and results of Edison's RTP rates through an annual report. The Commission should also ensure that Edison will actually market all of its RTP rate options to all qualifying customers, not just its own pet projects: Edison's Phase 2-B exhibit describes Schedules RTP-2, RTP-2-I, and PA-RTP, and ignores its Schedule TOU-8-RTP - DRA hopes that Edison is not ignoring this or any other rate option that has been endorsed by the Commission.
1. Edison proposes a new service, as a pilot program, that will allow a limited number of customers with multiple accounts at different sites to aggregate their time-related demands for a two-year term. Under this option, the time-related demand component of the bill for each account will be based on the demand of the individual account meters at the same time the aggregated maximum demand for all accounts under the contract occurs. DRA accepts Edison's proposal on the limited basis for which it is offered, under the condition that any future extension should review Edison's experience with this pilot program to determine whether it can be integrated with some form of real time pricing.
2. DRA's recommendations are as follows:
3. As discussed in Chapter 7 (Real Time Pricing), it is important when undertaking an experiment in rate design to be clear about what the experiment is. In the case of its "time-related demand aggregation service", Edison's exhibit has clearly stated its experimental purpose (beyond meeting "customer requests"): (a) gather information about how this option influences customer use of electricity, (b) determine optimum metering equipment and billing methods necessary to successfully implement aggregation, and (c) determine whether this contract option provides an incentive to improve system loading characteristics. In addition, this billing option can be viewed as cost-based. Costs of service that are considered to vary with time (i.e., with system loads) are to be assessed on the combined usage of a customer's multiple accounts at the same time. In contrast, the traditional "time-related" demand charge, which actually covers a broad range of hours, is a fairly crude way of measuring a customer's coincidence with system loads.
4. DRA believes that Edison's experimental goals can be accomplished within the limitations that Edison has proposed for this program. Beyond the limited scope that Edison has proposed, however, the experience that will be gained under Edison's proposal should be used to explore improvements before any future extensions to it are considered. Edison's proposal will base customers' bills on their own simultaneous loads, which will require use of hourly (or sub-hourly) metering. The same metering data could be combined with system load data to determine the customers' contributions to system peaks. This is done, for example, in San Diego Gas and Electric's Schedule A6-TOU (which can therefore be considered a simple form of RTP). Similarly, the hourly metering data could be combined with hourly pricing to produce various forms of RTP rates. Edison's proposed experiment can determine whether simple rate options can achieve reductions in customers' contributions to system peaks, but having learned that, more refined rate structures (using the same or similar equipment) should be considered.
1. SCE's primary proposal is that ratemaking impacts of these flexible pricing options flow through ERAM and other accounts in a business as "normal" approach (except for the Fixed Price Contract).
2. This ratemaking proposal ignores recent Commission decisions in PG&E special contracts, the SCE special contract with UNOCAL and in PG&E's own flexible pricing options package (D.95-10-033). DRA, for a variety of reasons, many of which are cited in these decisions, regards SCE's primary proposal as moving in the opposite direction to that of the Commission. The Commission has recognized that special contracts, in an increasingly competitive environment, and perhaps on the verge of significant changes in the Commission regulation of electric utilities, are a source of competitive advantage for the utility and its shareholders. The not gain to shareholders of such special contracting ability does not have to be specified - although the recent PG&E decision - where the utility accepted that its shareholders would pay a considerable portion of various discounted options - demonstrates that PG&E placed a significant value on this opportunity for specialized contracts. DRA can only assume that SCE places a similar if not greater value on the prospective benefits of this proposed contracting opportunity - particularly given the larger scope and scale of its flexible pricing option package.
3. Superficially SCE appears to have recognized this new approach in its secondary ratemaking proposal. Here Edison proposes that discounted sales options for existing load be funded by shareholders and that revenue gains from incremental sales (after contributions to miscellaneous accounts and the ECAC account at short-run avoided cost) flow to shareholders. However analysis of the dollar flows of the SCE proposal as shown in Table 10.1 reveals that under this ratemaking approach SCE expect its shareholders to profit by about $107 million over the next five years with profits extending into 2005.
4. Hence SCE has presented the Commission with two choices - neither of which reflects the future direction to a more competitive industry. Under one option (ERAM&balancing accounts) the utility obtains a variety of benefits in the future restructured industry via specialized contracting opportunities, with minimal regulatory oversight, to obtain significant medium term contracts with a variety of customers, and thereby considerably reduce the possibility of the loss of this load during the time period. In its alternative SCE not only retains all of the above but also has a reasonable opportunity to add even further and more directly to shareholder wealth.
5. There is an alternative to either of these options which better aligns SCE's risk and reward. Under this option SCE would still pay 100% of the discount on those options which retain load or otherwise incur revenue losses that is SCE's shareholders will fund all of the discounted options which SCE proposes (with the exception of the RTP programs and the Demand Aggregation Program). In addition all revenues from these options will flow through ERAM. SCE may argue that such ratemaking treatment provides its shareholders no upside. DRA disagrees, SCE shareholders will gain all of the benefits cited above on a package of proposals which taken together result in an enhanced strategic marketing position as the Commission moves toward restructuring. This has considerable value to SCE. DRA's initial estimate, based on SCE forecasts of discounts occurring due to these programs, is that SCE shareholders would pay a discount value of about $66 million (not present valued) of the next five years due to these programs. [footnote: SCE has also requested that incremental revenues from its ISR and SPA rate schedules also be included in its shareholder participation mechanism. DRA recommends instead that the ISR, SPA, TOU-CR-1, and ED rate schedules discounts also be paid by shareholders.]
6. DRA has omitted the RTP and Demand Aggregation Programs from this treatment both because the value of the discount or changes in revenue are unclear and because these are the types of programs which DRA would not have objected to, in broad policy terms, in a standard SCE General Rate Case.
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