5. Joint Staff's Response to May 2004 Comments and Revised Recommendations
Subsequent to the filing of post-workshop comments, Joint Staff worked with the IOUs to remove electricity sales to resale cities, as well as resale cities' population, from the calculation of sales and per capita usage for each IOU service territory, and to reconcile other technical differences. In addition, Joint Staff removed the impacts of gas sales to thermally enhanced oil recovery customers and sales to the City of Long Beach for the SoCalGas service territory. These adjustments are documented in Attachments 2-4.
As described in these attachments, adjustments to sales, population and other technical differences noted in the comments are relevant when calculating the effect of increased program savings on the forecast of per capita electricity usage, but they have no impact on the Joint Staff recommendations of GWh and MW savings goals for each IOU. This is because the recommended energy savings targets are based on cost effectiveness, funding increase constraints and the projected trend in the effectiveness (kWh saved per dollar spent) ratios for the programs. Raising or lowering the amount of electricity (or natural gas) sales to be considered in the calculation of per capita trends does not affect these factors unless it serves to limit or reduce the target population for programs. Instead, these technical adjustments affect what one might conclude about the impact of a given level of program savings on forecasts of overall usage and per capita usage trends.
More specifically, Attachments 2 and 3 show that removing electricity sales to resale cities from the CEC electricity demand forecast reduces the overall sales forecast by 20% for PG&E and 7% for SCE. Population forecasts are also reduced by 15% and 5.5%, respectively, by removing persons served by municipal utilities. The net effect of both of these changes is to reduce the cumulative savings required to meet a reduction goal of -0.3% in per capita electricity usage by approximately 2% for PG&E and 1.5% for SCE. This change has no impact on the estimates of technical potential because the Xenergy studies started with estimates on IOU customer-only sales, and by definition exclude self-generation, resale cities, and other non-PGC paying entities. Attachment 4 also illustrates that removing natural gas sales to resale cities, cogeneration customers and thermally enhanced oil recovery sales has no impact on the recommended trajectory of incremental natural gas savings from the program over the next ten years. Joint Staff agrees with SESCO that savings achieved by customers that are not included in the calculations of savings potential should also be removed from the calculation of savings accomplishments.
In response to SCE's comments, Joint Staff points out that the Xenergy analysis in the Hewlett Packard Report estimates the statewide economic potential at 40,186 GWh and the maximum achievable potential at 30,400 GWh by 2012. Applying SCE's reported ratios of savings per dollar of expenditure to its relative share of program funding (40%) yields a maximum achievable potential of 12,160 GWh, which is considerably higher than the Joint Staff recommendation of 10,773 GWh for that year.
Joint staff also notes that PG&E's concerns over how private supply will be measured is now moot, since Joint Staff has modified its forecasts from an earlier approach to exclude private supply numbers. Therefore, estimates of the quantity of private supply do not affect either the setting of goals or the determination of per capita reductions equivalents. With regard to the availability of reliable data on these quantities, Joint Staff points out that all private suppliers over 1 MW are required to report their energy production to the CEC on a monthly basis.
On the issue of how to consider direct access customers on the electric side, or non-core customers on the natural gas side, Joint Staff believes that some level of potential energy savings from these markets should be considered in establishing overall savings goals. Although IOUs no longer procure energy on their behalf, Joint Staff points out that direct access and non-core customers continue to pay the PGC and ratepayer-funded programs continue to be designed and implemented to capture savings in these markets. As described in Attachment 5, overall savings goals can be bound by performing sensitivity analysis on what percentage of the non-core (or direct access) market savings potential is achievable. Joint Staff believes that this is a more reasonable approach than eliminating direct access and non-core usage from savings goal calculations altogether, or assuming that all of the economic potential can be effectively captured via ratepayer-funded programs.
In sum, Joint Staff concludes that the March 26, 2004 recommendations for electricity savings goals do not require adjustments in response to parties' May 2004 comments. Those recommendations are presented in Table 2.
However, Joint Staff did perform additional analysis in response to workshop discussion and comments that has resulted in modifications to the March 26 2004 recommendations on natural gas savings goals. That analysis and Joint Staff's revised recommendations are presented in Attachment 5. As a result of revisiting this issue, Joint Staff has increased its recommended savings goals from 290 Mth to 472 Mth in annual savings, by 2013. This represents approximately 40% of the maximum achievable savings levels estimated from the Xenergy potential studies.
Finally, some parties at the workshop and in comments requested that Joint Staff perform a rate impact analysis to reflect increases in program funding consistent with the recommended savings goals. Attachment 6 presents Joint Staff's analysis of the rate increase required to fund the programs associated with its recommended natural gas savings goals and the net rate impact taking into account the resulting natural gas savings. The results indicate that the rate increase to fund the program of 0.6 cents/therm is counteracted by accumulated commodity savings. The net rate impact is calculated to be a negative 2.6 cents/therm, on average. In other words, Joint Staff projects that the extra savings valued at the commodity price of gas will be higher than the accumulated program costs.
Joint Staff was unable to prepare a comparable analysis of net rate impacts on the electric side because of the difficulty and uncertainty in forecasting the difference between avoided costs and retail rates over the next 10 years, which is needed for such a calculation. Instead, Joint Staff prepared a preliminary analysis of the revenue requirements and the program levelized costs associated with recommended savings goals for PY2006. The results and assumptions used in the calculations are displayed in Table 7. Joint Staff estimates that the programs implemented to meet the 2006 savings goals will cost 3.5 cents/kWh
on a levelized cost basis. In Joint Staff's view, this cost is less than any new baseload, combined cycle or peaking plant that can be brought on line over the next 10 years. Therefore, Joint Staff concludes that the rate impacts associated with its recommendations for electric savings goals are also likely to be negative when the value of electric energy savings is taken into account.
Joint Staff recommends that the IOUs be required to provide their best estimate of the net rate impacts of their programs when they file their program applications in mid-2005 for the next funding cycle.
