10. Demand Response Programs
10.1. PG&E's PTR Program Proposal
PG&E's proposed PTR program would offer new monetary incentives to encourage residential customers to reduce their peak period usage on up to 15 event days per summer. PG&E states that the PTR program is being proposed in part to allow for a consistent residential DR program offering across all three major California investor-owned utilities, and in part to achieve additional DR participation from residential customers who might not otherwise be reached by residential CPP rates alone. By PG&E's proposal, the PTR program will be available to customers starting in summer 2010.
The PTR program would be established as an overlay to the customer's otherwise applicable residential tariff (OAT) by applying bill credits of $0.60 for each kilowatt-hour (kWh) reduced during an event day. The energy reduction from each event will be measured against a customer-specific reference level (CRL) that is calculated for each customer. The proposed peak period times are from 2:00 p.m. to 7:00 p.m. According to PG&E, this approach is similar to those currently under consideration for both SDG&E and SCE, but has been adapted to comport with PG&E's adopted residential CPP program -- the residential CPP and PTR programs offered to PG&E's residential customers would match both in terms of operating hours (2:00 p.m. to 7:00 p.m.) and pricing level ($0.60 per kWh). PG&E also anticipates initiating CPP calls and PTR events on the same summer peak days.
According to PG&E, due to AB 1X,74 residential customers currently cannot be placed on a mandatory rate schedule or overlay that can result in higher bills for Tier 1 and Tier 2 usage. PG&E argues that the limitations created by AB 1X mean that dynamic pricing programs that could potentially increase customer bills (e.g., CPP) may only be offered to residential customers on a voluntary basis.75
PG&E states that until the AB 1X restriction is lifted, PTR will be a preferred choice for maximizing DR from residential customers.76 Because there is no downside risk, PG&E recommends that all residential customers be automatically enrolled in PTR once they are fully connected to the network, unless they are enrolled in CPP. PG&E reasons that automatic enrollment in PTR overcomes the hurdle of inertia (i.e., maintaining the status quo) that comes with recruiting customers onto a new program. In addition, the positive reinforcement provided by a "carrots only, no sticks" approach facilitates customer acceptance, since it will guide them towards understanding dynamic rates without the possibility of a higher bill.
As with the CPP program, PG&E proposes to restrict eligibility to individually-metered bundled service customers. Master-meter accounts would be excluded from the program because it would not be possible to determine load reductions for individual tenants. Net-metered accounts would be excluded from PTR because these customers' loads are served by a combination of their own equipment and utility generation, and it would not be possible to evaluate demand reductions for such customers independently of changes in output from their customer-owned generation equipment. Finally, direct access and community choice aggregation customers would be excluded from PTR (just as they are excluded from participating in CPP), because the generation portion of their service requirements is provided by third parties.
PG&E has evaluated potential interactions between the CPP and PTR programs, with the expectation that customers may want guidance in helping choose between these two demand response participation options. Its analysis shows that customers who are believed to have significant central air conditioning (CAC) usage would divide almost equally between finding CPP vs. PTR participation most advantageous. Also, nearly 90% of customers who are not believed to have significant CAC usage would be better off on CPP than under PTR. Nonetheless, PG&E does not expect high levels of initial CPP enrollment from customers without CAC, because non-CAC customer savings under CPP would still be relatively modest and because PG&E's marketing efforts for CPP will be focused on customers with significant CAC loads.
PG&E explains that customer bill savings associated with the PTR program will be attributable to two factors: "structural" savings, and savings attributable to actual demand reduction efforts undertaken in response to PTR calls. Structural savings are sometimes referred to as "free rider" savings. In the context of the PTR program, these are rebates that customers would receive as a consequence of ordinary variation in their daily energy usage (e.g., if they happen to be on vacation on the day a PTR event is called, but were home during the period reflected in their CRL allowance). Customers will realize additional bill savings under the PTR program if they initiate real demand reduction efforts in response to PTR calls. In practice, each customer will realize a combination of bill savings under PTR (structural and demand response), although such effects must be estimated statistically and could never be measured independently for each household.
PG&E proposes to estimate the structural component of PTR savings for the residential class, using the best available load research information when rate updates are prepared for January 1 rate changes each year. This structural savings estimate would then be treated as an external adder to the residential class cost allocation for the purpose of setting generation rates, so as to prevent non-residential customers from having their own rates affected by the cost of the free-rider portion of rebates received by residential customers. (The first such estimate would be prepared in the fall of 2010 and will then be reflected when rates are set for January 1, 2011.) After providing for this adjustment for the structural component of the rebates, PG&E proposes that all actual rebates be recognized as reductions to revenues from generation rates. This approach is based on an assumption that the demand response component of PTR bill savings will be in reasonable accord with procurement cost savings that can be attributed to the program.77
DRA recommends that approval of the proposed PTR program should be separated from a review of PG&E's proposed AMI Upgrade system. DRA recommends that the Commission approve the PTR program with modifications in the 2009-2011 Demand Response Programs and Budget Application.
Regarding program design, DRA recommends that the Commission adopt a two-level incentive structure to minimize free-ridership, as DRA recommended for SCE and SDG&E's PTR program proposals, and as adopted by the Commission for SDG&E's PTR program in D.08-02-034. Furthermore, PTR program measurement and evaluation should conform to the demand response load impact protocols adopted in D.08-04-050. Specifically, DRA emphasizes the ex post assessment of free-ridership and the distribution of load impact across customers.78
PG&E opposes DRA's proposal to address PTR in PG&E's 2009-2011 demand response (DR) program case. According to PG&E, the 2009-2011 DR case is a consolidated proceeding for PG&E, SCE and SDG&E and it needs to move forward expeditiously to allow the next cycle's DR programs to proceed in time for customers (primarily commercial and industrial) to know what will be offered and to decide whether they will participate. PG&E states that adding the DRA PTR proposal to that case would unreasonably delay the timetable and expand the scope of the 2009-2011 proceeding.
PG&E notes that the SDG&E and SCE PTR proposals have been moved to those utilities' respective GRCs, but if PG&E's PTR were moved to Phase 2 of its next GRC, implementation would be delayed beyond summer 2010, the program start date. PG&E also notes that the Commission specifically stated that PG&E's Upgrade case is an appropriate forum to consider PTR.79
With respect to DRA's proposed program design, PG&E states that DRA's proposal is flawed conceptually and lacks critical details. In the absence of any presentation of these details, the DRA recommendations should be rejected.
DRA's description of its higher and lower PTR incentives raises the potential for the higher PTR incentive to exceed avoided cost, which PG&E cautions should not be allowed to happen. PG&E is also concerned about practical issues for establishing, enforcing and monitoring a two-tier incentive program. For instance:
· How will the required technology measures be identified (and updated)?
· How will individual customers' adoption of such measures be known and confirmed?
· How would continued on-going operation of installed measures on the customers' individual premises be monitored?
PG&E also notes the additional costs to implement, market and administer a DRA two-tier, technology enabled PTR program, beyond what PG&E has requested for a single-tiered PTR incentive.
We believe the PTR program will encourage residential customers to reduce their peak period usage on peak days. We also agree that the program is allowable while the AB 1X rate protections remain in place. However, the PTR program should be regarded as a transitional program that the Commission intends to review when the AB 1X rate protections change.80
As discussed in other parts of this decision81 the costs and benefits of PG&E's proposed PTR program will be considered in the cost effectiveness analysis of the Upgrade. We would also prefer to address the program design as part of this proceeding. As DRA indicates a two-tier design has been adopted for SDG&E.82 Also, a two-tier settlement proposal for SCE has been deferred to SCE's Phase 2 GRC proceeding.83 We are therefore reluctant to move forward with PG&E's single tier proposal. In other sections of this decision, we emphasize consistency in how we treat the IOUs. We see no reason to stray from that principle in this instance and will adopt a two-tier design for PG&E. However, we do acknowledge that the details of DRA's proposal are lacking and there are a number of practical considerations that would need to be addressed. For that reason, we will defer the PTR program design to PG&E's November 2009 rate design window filing, where we will require PG&E to propose a two-tier PTR incentive design and the associated PTR program costs for such a design. This will allow PG&E time to (1) work with DRA and other parties to work out program details and costs; (2) consider the adopted design for SDG&E along with any solutions to practical considerations, if any; and (3) monitor and evaluate what has happened or will happen in SCE's Phase 2 GRC with respect to implementing a two-tier PTR program design. Hopefully, this cooperative effort will allow time for the Commission to adopt and implement a two-tier design for PG&E in time for the anticipated Summer 2010 start of the program. If it turns out that this is not possible, PG&E's PTR program should instead be implemented in 2011. PG&E's rate design proposal should be consistent with the rate design guidance adopted in D.08-07-045.
10.2. PTR Benefits
The PTR benefits are calculated by PG&E with the same price elasticities as the CPP program using the model developed from the AMI business case in A.05-06-028. The model in this application assumes a total participation rate on both PTR and CPP of 50 percent of the residential customer sector based on PG&E's proposed awareness marketing. Estimated CPP participation is subtracted out annually and the residual MW reduction is estimated as the incremental DR benefit attributable to the PTR program. PG&E forecasts avoided capacity of 6,307 MW through 2030. PG&E values the avoided generation capacity costs at $85/kW-yr.
In considering the demand response benefits PG&E attributes to the Upgrade proposal, DRA argues that the Commission should consider the metering functionalities needed to implement the proposed PTR program, and compare that to the added functionalities offered by the Upgrade. Specifically, if PTR implementation does not depend on the added functionalities, particularly the HAN gateway and the integrated service switch, then the PTR costs and benefits should not affect the Upgrade cost-benefit analysis.
DRA states that to implement a Peak Time Rebate program as PG&E has proposed, PG&E needs to do the following:
(1) Notify customers the day before a peak event day, and
(2) Collect interval customer usage data, and compare usage on the event day to average usage of the previous three-of-five days.
DRA examined Commission records and PG&E's original AMI application prepared testimony exhibits, and concluded that the listed requirements for the proposed PTR program can be met with the already authorized AMI system, without the added Upgrade functionalities. DRA recommends that the $290 million PG&E includes in its benefits calculations for PTR should therefore be excluded.
In response to DRA, as well as TURN who makes essentially the same recommendation, PG&E states that both DRA and TURN completely fail to recognize the value of HAN and IHDs to reach more customers and communicate most effectively with them, which is necessary to achieve the desired result of an effective PTR program.
TURN believes that any benefit from PTR rates is not incremental to the hardware requested in this application but could be obtained (albeit at higher marketing and IT cost) from the functionality specified for existing hardware. In the event that demand response benefits from PTR are considered, it is TURN's position that those benefits, as estimated by PG&E, have been significantly overestimated. TURN provides three basic reasons for this position.
First, TURN calculates an AC adjustment factor to incorporate its assertion that AC loads will be decreasing over time as more efficient air conditioners are installed according to federal regulations. According to TURN, the movement from an average SEER84 rating of SEER 10 to SEER 13 at the end of 20 years means that the stock of CAC units will result in less demand per unit over time, thus a smaller starting point from which to undertake demand response. TURN argues that use of its SEER rating adjustment is more appropriate than PG&E's position of no AC adjustment.85
Second, TURN argues that PTR demand response calculated with the use of unadjusted CPP elasticities will overstate response from PTR rates.
From a theoretical perspective, TURN argues that a priori one would expect customers to consume less under a CPP rate than under a PTR rate. That is because under a CPP rate, the charge on each kWh consumed during the peak period on an event day is the OAT plus the CPP adder of 60¢/kWh. So if the OAT is 16¢, a customer would be charged 76¢ for each kWh consumed during the peak event (a "stick," accompanied by a "carrot" of tariff reductions on other kWh consumed). Under a PTR rate, the customer is charged the OAT on each kWh consumed during the event peak period (e.g., 16¢), but receives a credit of 60¢/kWh for each kWh saved compared to a reference level. TURN states that while the marginal incentive to save a kWh is the same between the CPP and PTR rates, the marginal price to consume a kWh is far higher under the CPP rate (76¢) versus the PTR rate (16¢). TURN interprets this to mean that the consequence of peak consumption under CPP rates is likely to be more attention-getting for the customer, and that expensive consumption will run into the customer's budget constraint. On the other hand, the customer under PTR rates faces no adverse consequence from continuing to consume, and that extra consumption at the lower OAT does not impact budget constraint."
TURN also argues that quantitative evidence supports the theoretical understanding that CPP customers will save more energy than under PTR rates. According to TURN, the only study that examines both rates, using the same incentive for CPP and PTR on the same days (same weather), is the Ontario study.86 In that study customers under PTR rates saved 30% less than CPP customers. TURN states that although the statistical results do not enable a conclusion that the CPP and PTR savings rates are statistically different from each other, the lower PTR value supports TURN's theoretical understanding and is evidence that must not be discarded lightly. For these reasons, TURN recommends that it would be reasonable to adjust the CPP elasticities downward by 30 percent for PTR purposes.
TURN also argues that evidence from customer surveys supports its position that PTR customers will save less than CPP (SmartRate) customers. In citing a recent PG&E study,87 TURN states the survey shows that 22% of customers were interested in signing up for CPP rates, and that they are "more involved in energy than the average customer -they are more motivated to conserve, they want more control, and they are more receptive to getting help from PG&E to reduce their energy use further...tend to be under 55 years old, higher educated, more affluent, with families, with higher than average energy bills..." Also, although 47% of customers said they would sign up for PTR (SmartRebate), they are "less interested in controlling their energy use, they are less likely to think they can reduce their energy use weekday afternoons without too much inconvenience, and they are less likely to want to think about or track their energy use. SmartRebate customers also differ demographically from those who say they would sign up for SmartRate. Both groups tend to be customers who are under 55 years old, but in nearly all other respects customers interested in SmartRebate are very much like the average of all customers. They do not stand out in any respect other than being somewhat more likely to be on the CARE rate." According to TURN, it is clear from the customer surveys that those signing up for the PTR rate will be far less interested than CPP customers in saving energy and thus will not produce the same savings that can be expected from CPP customers.
Also, TURN expects that participation in PTR will fall off over time, because (1) customers value financial savings, and the small savings available will not maintain participation in the long run; (2) a disadvantaged customer needs to reduce energy by more than 15% before even earning a rebate on at least one-third of the event days, which will defer many customers; and (3) default PTR customers are not committed to demand response.
TURN also disagrees with PG&E's assumption that its notification strategy will reach 50% of the residential customers regarding critical peak time events for PTR and CPP rates combined. TURN indicates that while PG&E expects to provide direct notification to customers of event days via devices such as in-home displays beginning in 2013, PG&E expects that market adoption of the in-home display will reach 3% of customers by 2013 and top out at 30% of customers in 2024. TURN argues that even at maximum penetration (30%) the in-home displays cannot be relied upon to assure 50% awareness for PTR/CPP rates in the near future.
TURN also states that the fact that PG&E intends to make 50% of its customers "aware" of critical peak events is not an assurance that 50% of its customers will behave as did customers who were enrolled in the SPP pilot. While TURN did not make an additional adjustment for this factor, it states that this is another source of overestimates in PG&E's projections, which the Commission should keep in mind in judging the merits of PG&E's demand response benefits.
Also, as a consequence of PG&E's 50% participation assumption, TURN understands that PG&E implicitly assumes 45% of its non-CAC customers will participate in PTR.88 TURN states that expecting these customers to participate in PTR for the next 20 years is not supportable because (1) non-CAC customers have small usage; (2) financial savings from demand response are small; and (3) non-CAC customers are unlikely to have in-home display devices. TURN states that PG&E has no basis for assuming demand response of 104 MW from non-CAC customers in 2012, up to 129 MW in 2027. Since SPP data show that roughly 26% of participants identified non-financial reasons for their participation, TURN expects that participation in PG&E's PTR program is like to be a maximum of 26% of non-CAC customers, rather than the 45% PG&E assumes (adjustment factor = 58%).
In summary, TURN expects a maximum of 142 MW from PTR in 2012 (55% of PG&E's 260 MW estimate), and 162 MW in 2025 (49% of PG&E's 328 MW estimate).
In response, with respect to TURN's assertion that increases in federally mandated SEER from 10 to 13 would increase the energy efficiency of CAC units while higher saturations of "more efficient" CAC units would reduce the peak demand response potential from future CAC installations and retrofits, PG&E states that TURN's argument ignores a well-established body of evidence that SEER is not a reliable predictor of energy performance in California or of demand reduction. PG&E states that the CEC report cited by TURN for the increase in SEER ratings is replete with statements about the inadequacy of SEER ratings in California. For instance, the CEC report states: 89
Current HVAC appliance performance testing is conducted to national standards. Standard ratings for the seasonal energy efficiency ratio (SEER) are conducted at a maximum temperature of 82º Fahrenheit and treat dehumidification as equal to sensible cooling. In the hot dry climates of California, outside air temperatures over 95° Fahrenheit with 35% relative humidity is common. The current standards provide inaccurate assessments of energy requirements during peak periods in California and the Southwest.
Peak energy use is further amplified by the natural tendency of designers and contractors to provide a larger capacity system than necessary, resulting in excessive and inefficiency cycling of the compressor. Increased cycling of a direct expansion air conditioning system reduces overall efficiency through cycle start-up losses which occur until the cold liquid refrigerant returns to the evaporator coil. The results of over sizing single-speed units include increased electric peak and, in some cases, increased energy consumption.
PG&E indicates that the bottom line of the CEC report cited by TURN is that:90
[T]he state should investigate a new efficiency metric for residential and nonresidential direct expansion, air cooled air conditioning system that appropriately rates performance in hot and dry California climate zones.
PG&E also states that Exhibit 218 that was introduced by TURN echoes the findings of Exhibit 25, wherein it states, "Neither SEER nor EER is a sufficiently reliable indicator of cooling energy performance (consumption or demand) for California."91
With respect to TURN's proposed 30% reduction in SPP elasticities, PG&E states that the standard error for both the CPP and PTR Ontario study results was 8%, and:
Thus, the difference between the two values is less than one standard deviation, which is much less than the two standard deviations required to demonstrate that the difference is statistically significant. Put another way, the empirical evidence from the Ontario pilot does not support the claim that the impacts estimated using the SPP demand models should be reduced by 30%-indeed, the empirical evidence shows that there is no statistically significant difference between the impacts expected from CPP and PTR incentives when estimated based on data from a side-by-side comparison of the two options for the same customer population.92
PG&E also points out that the Anaheim study produced PTR program impacts nearly identical to the estimated impacts using the demand models from the SPP (after controlling for air conditioning and climatic differences between the Anaheim and SPP samples), and the convergence of the Anaheim PTR results and the SPP model results corroborate the Ontario study's finding of no significant difference between PTR and CPP impacts.
With respect to TURN's argument that non-CAC customer usage is small and savings will be small, PG&E argues that, while the average PTR benefit for a non-CAC customer may be small, there are a range of customers both above and below the average with many distributions possible. PG&E indicates that if the average benefit were $1.50 per month, there could be scenarios where half the customers reduced load enough to get a $3.00 saving or where 25% of the customers respond sufficiently to get a $6.00 bill savings. Moreover, if the customers are in tiers 4 or 5, their savings could even be greater.
With respect to TURN's assumption that a customer must purchase an IHD to participate in PTR, PG&E indicates that it has budgeted funds to provide continued support of education and event notification, such as public service messages and press releases. Thus, according to PG&E, although IHDs are critical as an additional notification channel, a portion of PG&E's customers (particularly in high density urban areas like the San Francisco Bay Area) may learn about PTR events through other media. PG&E does agree that a large percentage of customers will participate for environmental or societal reasons, but does not agree that participation for non-CAC customers should be limited to only that group.
CCSF agrees with DRA that PTR implementation is not dependent on real time communication with customers. According to CCSF, using PG&E's website or the media to send out notices of a PTR event could be just as effective as PG&E providing notice through its customers' IHDs, and the added functionalities provided by the HAN are not an additional benefit of PG&E's proposed AMI upgrade.
The City also agrees with TURN, that there is no evidence to support PG&E's claim that its customers will respond to PTR rates in the same way they do to CPP rates.
With respect to DRA's position, as indicated previously in this decision, we are accepting PG&E's definition of "incremental" for purposes of determining Upgrade costs and benefits. Since PTR benefits result from PG&E's SmartMeter project and were not quantified in PG&E's original AMI proceeding, we will do so now as part of determination of the cost effectiveness of the Upgrade.
With respect to TURN's recommended adjustments, in the event that PTR benefits are considered, we agree, to an extent, that demand response related to PTR will likely be less than that estimated by PG&E.
PG&E has provided persuasive evidence to justify its position that SEER is not a reliable predictor of energy performance or of demand reduction in California. We interpret that to mean, for instance, if a customer upgrades from a unit with a SEER 10 rating to a SEER 13 rating, which reflects a 30% increase in the rated efficiency of the equipment, the customer will probably not realize a 30% reduction in demand or 30% energy savings. Demand reduction and energy savings will likely be lower. However, we do not interpret this to mean there will be no energy savings or reductions in demand at all. For example, in Exhibit 218, Figure 12 shows median savings, ranging from 6% to 33%, associated with upgrading from a lower SEER system to a higher SEER system under different upgrading scenarios, although the number of units achieving expected savings is low (from 8% to 29%). Therefore, even though the climate and other factors particular to California are not the same as that assumed for SEER purposes, it is reasonable to assume that as manufacturers attempt to make more efficient systems to comply with upgraded SEER levels, there will be some effect of demand reductions and energy savings in California. We will reduce TURN's proposed adjustment by 50% to reflect this effect.93
With respect to TURN's proposed 30% elasticity adjustment, we are convince by PG&E's arguments that there is no statistically significant difference between the impacts expected from CPP and PTR incentives when estimated based on data from a side-by-side comparison of the two options for the same customer population, and the Anaheim study produced PTR program impacts nearly identical to the estimated impacts using the demand models from the SPP. We will therefore not adopt TURN's recommended adjustment. This is consistent with our actions in SCE's AMI proceeding where a similar TURN proposal was rejected and where we stated:
Current evidence does not provide a definite picture of customer behavior under a PTR rate, since such rates are not currently in widespread use. However, based on existing evidence it is reasonable to conclude that the elasticity of customer electric demand under a PTR rate may be comparable to under a CPP rate. Similarly, though it is not possible to be certain how customers will react to a PTR rate on a long-term basis, it is reasonable to apply economic theory to this question and assume that long-run elasticities will not be lower than short-run elasticities. Over the long run, for example, customers may have access to more enabling technology allowing them to respond more easily to PTR rates and increase their resulting demand response. For these reasons, the elasticities used in the settlement agreement business case, which are based on elasticities calculated from CPP rates and are assumed to remain stable over time, are reasonable for the purposes of estimating future energy savings from PTR rates and their associated benefits.94
With respect to TURN's non-CAC customer participation adjustment, we understand TURN's concerns regarding limited savings. While PG&E demonstrates that a non-CAC customer might realize significant savings under the PTR program under certain scenarios, there is no evidence as to suggest what the expected scenario might be and what savings would result from such a scenario. We do agree that there will likely be a response beyond that of those who would participate for environmental or societal reasons and assume for purposes of this analysis that it is halfway between that estimated by TURN and that implicit in PG&E's forecast. This results in a non-CAC customer participation rate of 35.5%.
Based on the above discussion, we adopt PTR savings through 2030 in the amount of 5,714 MWs as opposed to PG&E's forecasted amount of 6,307 MWs. This results in a PVRR benefit of $262,941,000 as opposed to the PG&E's $290,222,000 estimated amount.
10.3. TURN's Demand Response Guarantee Proposal
In TURN's opinion, the implementation of a PTR rate is likely to undermine customer participation in the CPP rate which was approved in D.06-07-027, and there is a danger that the benefit stream upon which approval of the initial AMI project was based will not be fully realized. Also, TURN estimates demand response benefits that are 40%-49% of the MW that PG&E projects, reducing projected benefits by at least $222.5 million. For these reasons, TURN believes there is a significant probability that not only will the benefits of this application not be realized, but also the benefits approved in D.06-07-027 will be diminished. It is TURN's position that failure to fully realize the projected demand response in both projects - the initial AMI project and the Upgrade-- doubly harms ratepayers by not only saddling them with costs that are not accompanied by benefits, but also requiring ratepayers to purchase expensive power at peak times to replace the unrealized demand response. TURN also indicates that, because demand response and conservation benefits account for 85% of the Upgrade benefits, failure to achieve 100% of these amounts has a large impact on the benefit/cost ratio.
In light of these considerations, TURN recommends that, if the Commission proceeds with any part of PG&E's Upgrade application, PG&E should be required to adhere to the following guarantee:
Failure to achieve 65% of the MW savings approved in D.06-07-027, and 100% of the additional PTR and PCT MW projected in this application (see Table below) should result in penalty payments to ratepayers. The penalty should equal one-half of the annualized cost of a peaking powerplant adjusted for losses (and for reserves if applicable at the time) multiplied by the unachieved savings for each year of underachievement.
In summary, PG&E opposes TURN's penalty proposal as inappropriate in this case. First the time, effort, expertise and focus needed to address the complex issue of shareholder risks and rewards for demand response is beyond the scope of this proceeding. Second, TURN's penalty-only proposal is arbitrary and has no sound justification. And third, as the Commission did not adopt this type of mechanism in its original decision on PG&E's AMI application, it would be unreasonable to introduce a penalty mechanism now, two years later.
PG&E adds that forecasts of avoided costs, other costs, benefits, and the metrics for measuring them out into the future should be expected to change over time, with more experience. For instance, the Commission may institute new programs that take advantage of the upgraded elements of PG&E's SmartMeter system to obtain new benefits.95 PG&E points out that the Commission has extensive review and approval oversight for demand response, where it can take corrective steps that may be appropriate at the time. PG&E also notes that future increases in the economic value of the demand response could produce values exceeding those estimated in this case, even if the forecasted MWs are not achieved. So, under TURN's MW approach, PG&E could be penalized even though the value of the demand response achieved was higher than forecast in the case.
We will not adopt TURN's demand response guarantee proposal. First of all we have adjusted PG&E's PTR and Title 24 PCT program benefit estimates to what we feel are reasonable levels, in light of the record of this proceeding. Also, a similar issue was addressed recently in SCE's AMI proceeding, where TURN proposed that the Commission should also adopt a penalty mechanism under which SCE would be required to pay a penalty in the event that it failed to reach 65% of its forecast demand response. TURN recommended a penalty mechanism equal to one-half of the annualized cost of a peaking power plant adjusted for losses and multiplied by the unachieved savings. In resolving the issue, the Commission stated:
As discussed above, any forecast of costs and benefits that goes out far into the future is subject to great uncertainty. We approve the settlement agreement based on the best available current information, but many of the rates and programs assumed for the purposes of the business case have not been adopted by the Commission, and must ultimately be considered on their merits when specific proposals are made. Similarly, we have used the best available estimates for program participation in the business case analysis, but because CPP and PTR rates are not currently in widespread use for residential customers in California, these estimates, too, are subject to uncertainty. Future information on customer behavior in response to these or other dynamic rates may provide more accurate information on participation rates and demand elasticities, but we must analyze the settlement agreement based on the information available today. For these reasons, it is not reasonable to penalize SCE for failing to meet the forecasts made in the business case.
It is, however, reasonable and desirable to determine how closely the demand response, conservation, and load control forecasts, and forecasts of associated benefits, match the forecasts made here. The collection of data the actual demand response achieved with the AMI system will provide us with valuable information on customer behavior, and enable us to track progress towards state energy policy goals associated with AMI, DR, and related issues. For this reason, in addition to approving the settlement agreement, we require SCE to report to the Commission on the energy savings and associated financial benefits of all DR, load control, and conservation programs enabled by AMI, including PCT programs, Peak Time Rebate programs, and other dynamic rates for residential customers. SCE should work with Energy Division develop a reporting format for this information, and should file annual reports in April of each year in R.07-01-041 or a successor proceeding until April 2019. If no successor proceeding exists, SCE should send these reports to the Director of the Energy Division and serve the service list of the most recent Commission demand response rulemaking. To the extent possible, SCE shall base its estimates of energy savings on the Commission's adopted load impact protocols contained in D.08-04-050 or successor protocols adopted in the future.96
The reasons expressed by the Commission for rejecting TURN's penalty proposal in SCE's AMI proceeding are applicable here. We have reviewed the record in this proceeding and have adopted what we consider reasonable estimates based on that record. It would not be appropriate to penalize PG&E, if the adopted demand response does not materialize.
Similar to what was required for SCE in D.08-09-039, PG&E should report to the Commission on the energy savings and associated financial benefits of all DR, load control, energy efficiency, and conservation programs enabled by AMI, including PCT programs, Peak Time Rebate programs, and other dynamic rates for residential customers. If not already included, these requirements are supplemental to the PG&E's reporting requirements mandated by D.06-07-027. PG&E may request recovery for the cost of this reporting requirement in appropriate cases.97
10.4. PG&E`s Proposed Title 24 PCT Program for Residential Customers
In its December 12, 2007 application testimony PG&E indicated that new Title 24 building code air conditioning standards were expected in 2009. The new standards would require all new homes and retrofits requiring building permits for central air conditioning and heating to have Title 24 compliant PCTs installed. PG&E would then target residential customers with the new PCTs for participation in PG&E's SmartAC Program. PG&E would also create a program to encourage existing air conditioning customers to initiate early retrofit of their standard thermostat with Title 24 compliant PCTs. However, the CEC withdrew its Title 24 building code air conditioning standards recommendation shortly after PG&E filed the application. PG&E now assumes the standard will be implemented in 2012 and that PG&E will begin recruiting new construction and permitted replacement/retrofit customers in 2013. PG&E states that all of these customers will be seamlessly integrated into PG&E's existing SmartAC Program, although the temperature set points, event notifications, and the ability for customers to override events will be communicated through the HAN gateway.
Under PG&E's proposal, PG&E's existing SmartAC Program will continue to operate as designed including the option as an enabling technology for a pricing program. All eligible SmartAC customers will be able to enhance their participation in CPP or PTR with the enabling technology provided on the SmartAC Program, including those joining the program through the proposed Title 24 PCT program. PG&E will offer to adjust participating customer air conditioning on the event days.
The Title 24 PCT program assumes the SmartAC Program will continue, but IT costs associated with the implementation via the HAN gateway device and using internal customer tracking systems are included by PG&E in this proceeding. Additional assumptions by PG&E include:
· All new residential construction with AC would have a Title 24 compliant PCT installed (based on the Residential Appliance Saturation Study (RASS),98 75.5% of new homes are assumed to have AC);99
· 38,000 or 38% of the expected number of 100,000 major home remodels assumed to have AC (based on the RASS);
· Only 70% of heating, ventilation and air conditioning (HVAC) replacements or retrofits would be done with building permits, and that only the permitted retrofits would have Title 24 compliant PCTs installed;
· 25% of residential customers with a Title 24 PCT will enroll in the program based on a $25 incentive and the opportunity to lower peak time energy usage and save money on critical event days;
· The average number of AC units per customer is 1.08 based on recent SmartAC Program experience;
· Average of 0.75 kW per PCT consistent with PG&E's existing SmartAC Program impact estimates;100 and
· A 15-year life of the PCT.
In addition, for the early retrofit of existing air conditioning systems with Title 24 compliant PCTs, PG&E will target 30,000 customers a year with an enrollment cap of 250,000 customers. Since PG&E's current SmartAC Program is approved for up to 305 MW of demand response, the Title 24 PCT benefits claimed for Upgrade are only for demand response MW amounts above the 305 MW level.
PG&E's Upgrade demand response benefits include reductions of 3,738 MWs from 2013 through 2030 for demand response from Title 24 PCTs. Using an avoided capacity cost of $85 per MW, PG&E calculates PVRR benefits of $129,401,000.
DRA states that PG&E has already counted the participation of new customers in its SmartAC program and has thus excluded Title 24 PCT benefits from its cost effectiveness analysis of the Upgrade.
Also, DRA questions whether PG&E can "seamlessly integrate" the HAN functionality with its SmartAC program operation as it claims. DRA states that operating the SmartAC program through the HAN interface does not mean that PG&E can replace the 900 MHz paging system approved for its SmartAC program, and quotes the following from PG&E's Upgrade testimony:
Separate communications systems are likely to be necessary due to the possibility that customer-owned equipment installed under the current SmartAC program may not be able to communicate with the new HAN network.101
Consequently, DRA argues that PG&E may not be able to operate all AC units participating in its SmartAC program through the HAN interface.
DRA notes that, as approved in D.08-02-009, PG&E has a communication system to remotely control PCTs. To promote interoperability, the CEC also considered requiring the PCTs to incorporate "communication expansion ports," to allow for remote control of the PCTs via other communication systems, such as the 900 MHz paging system for which PG&E received ratepayer funding in D.08-02-009. According to DRA, even if the CEC were to revert to mandate Title 24 PCT in new construction, its focus on technological interoperability (which both DRA and PG&E have publicly supported) would likely persist. In DRA's opinion, the Upgrade would not add an incremental functionality to PG&E's existing demand-side management system, beyond what PG&E could already achieve with its functionality claims in the AC Cycling and the original AMI applications.
In response, regarding DRA's double counting argument, PG&E notes that DRA's witness acknowledged that the AC Cycling settlement provided for up to 400,000 devices to provide 305 MW of demand response, including additions to cover attrition to maintain 400,000 devices in the program.102 PG&E also indicates that its testimony also recognized that the A/C settlement was to install 305 MW of dispatchable demand response from 2007- 2011, with a cost/benefit analysis for the 15-year life of the program technologies. However, PG&E asserts that CAC cycling beyond the A/C settlement scope is needed to address increased demand from new construction over the Upgrade period. According to PG&E, its Upgrade cost/benefit analysis includes HAN facilitated CAC cycling for new Title 24 PCTs beyond the level needed to replace attrition associated with the 305 MW in the A/C settlement.
Regarding DRA claims that technological interoperability issues with Title 24 PCTs may interfere with PG&E's ability to operate AC units through the HAN interface, PG&E notes, as did DRA, that the CEC has considered requiring the PCTs to incorporate other communication systems. PG&E states that industry participants certainly are promoting HAN communication to CEC staff for this purpose, and the fact that the two southern California investor-owned electric utilities will have HAN systems, plus PG&E if the Commission approves this application, may move the market, making HAN communication a sensible element of Title 24 PCTs.
TURN states that the PCT devices should be attributed zero benefits in this application, because PCTs are not incremental to the hardware requested in this application. PG&E already has a SmartAC program involving PCTs that can achieve demand response without the necessity to approve this application.
Also, TURN asserts that PCT demand response will be significantly less than anticipated by PG&E for the following reasons:
· Although PG&E assumes that PCT program participants will save on average 0.75 kW per hour per event, data from PG&E's 2007 SmartAC program (which offers either a one-way communicating PCT or AC cycler) predicts only a 0.48 KW impact for PCTs.
· Based on data from a ramping strategy that sets back the thermostat by 4º at the beginning of the event period, evidence from DOE modeling shows that a residential thermostat's impact on savings goes from 0.42 kW/ton in the first hour (2:00 p.m.) down to 0.25 kW in the fourth hour (6:00 p.m.). There is a snapback or rebound effect after the event ceases and the AC unit attempts to recover to its normal temperature setting. The full impact of the demand response does not last for four hours, as would be required for most resources that comply with resource adequacy (RA) requirements.
PCTs measured in PG&E's 2007 SmartAC program also sometimes showed a reduction in savings in the last hour. As shown in Ex. 206, p. 5-36, Figure 5-3 shows lower per-unit average kW reduction in the last hour in three of the six scenarios examined (two ramping strategies, three days each).
· Evidence from marketing surveys as well as marketing efforts supports a conclusion that it will be difficult for PG&E to achieve 25 % participation of PCT owners to receive temperature setbacks under its PCT program.
TURN cites the 3.6% response rate from a marketing solicitation, stating that this result gives little confidence that PG&E would obtain 25% market penetration for its PCT program. TURN asserts that this is a long way from 25%.
TURN also cites Greenberg research as evidence that PG&E would have difficulty reaching 25% participation. That research shows that customers with newer systems were negative about direct load control, feeling their equipment installation was a significant enough contribution to the energy shortage. TURN argues that the fact that the PCT is installed does not address at all the customer's reluctance to have it activated and to participate with temperature setbacks in the PCT program.
· For the 30,000 customers per year expected to voluntarily purchase PCTs and enroll in PG&E's PCT program, TURN states that the retail cost of the PCT device could be a barrier to participation. TURN states that PG&E did not provide an estimate of the cost of a two-way communicating PCT, and TURN calculated an estimate of between $90 and $120.
Also, TURN cautions that, in the event that the CEC does mandate PCTs, the cost to the homeowner of such a mandate will need to be offset with the benefit, e.g., the savings due to demand reduction. According to TURN, under this scenario PG&E cannot also count the value of the same demand reduction, as that would be double counting one benefit against two sets of costs in two different proceedings. TURN further states that PG&E's own assumption of only 25% of PCT customers actually participating in the demand reduction program lowers the likelihood that such a PCT mandate could even be cost-effective at the CEC.
TURN points out that alternatively PG&E could assume that no Title 24 mandate occurs, and include in the Upgrade project both the cost of a PCT as well as the benefit of the PCT demand reduction. This is the approach taken by SCE in its recent AMI proceeding (A.07-07-026), where SCE included a $50 charge for a PCT (in case there is no Title 24 mandate) and also included the benefit of the PCT demand response. PG&E states that, in the Upgrade, PG&E has not included a cost for the PCT as SCE did, and thus inclusion of the PCT DR benefit is not legitimate.
TURN asserts that its evidence justifies the following recommendations:
· The "Title 24" MW should be zero, even if PCTs are mandated elsewhere. A device could only be mandated if it were considered cost effective by the mandating agency, in which case the "benefit" of demand reduction will double count what PG&E proposes here. Otherwise the same benefit will be used to justify two sets of costs in two different venues. This reduces PG&E's projection by 40 MW in 2015 and 154 MW in 2025.
· For voluntary PCTs (PG&E's "non-construction" category), TURN expects the MW to be reduced by 33%, based on recent Smart AC evidence. This reduces PG&E's projection by 11 MW in 2015 and 41 MW in 2025. The cost of the PCT device, purchased by the customer, would need to be included in the TRC test. The high cost of a PCT device, relative to what PG&E proposes as an incentive to join the program, also causes TURN to doubt PG&E's projection for participation, although TURN has not imposed a separate adjustment for that factor.
Thus, for the years through 2030, TURN's projections are roughly 28%-37% of the annual PCT MWs that PG&E projects.
In response, regarding TURN's statement that the PCTs are not incremental to the "hardware" requested in the Upgrade case adding "PG&E already has a SmartAC program involving PCTs that can achieve demand response," PG&E states that TURN's later statement is not true for the Title 24 PCTs, as discussed in PG&E's response to DRA. As to the first statement, PG&E argues that TURN misses the point by asserting that PCTs should somehow be incremental to Upgrade equipment. According to PG&E, what matters is the Upgrade equipment's functionality with Title 24 PCTs. PG&E anticipates that the additional HAN functionality will be used with PCTs in the future for operation of CAC cycling during events for all three California investor owned electric utilities; and it is HAN's functionality that facilitates demand response with Title 24 PCTs which supports inclusion of the PCT benefits in this case.
In response to TURN's assertion that PCT demand response will be significantly less than anticipated by PG&E, PG&E provided the following reasons for rejecting TURN's analysis:
· Regarding TURN's attack on PG&E's estimated 0.75 kW/hour savings per customer for the PCT program, PG&E indicates that the KEMA study referenced by TURN analyzed performance during the first summer of PG&E's A/C cycling program (2007) with 5,000 customers in the Stockton area. Differences between the demand reductions produced by switches versus PCTs were recorded, but those differences were primarily driven by how the program was operated, not by technology. PG&E witness Alexander reported that there were two ramping strategies with PCTs, both designed to overcome limitations of a single set point increase at the beginning of an event. Those strategies did not achieve the same load impacts as with switches. There are additional strategies that will be used in 2008. PG&E witness Alexander expects future ramping strategies and greater experience will lead to PCT load reductions comparable to switches. PG&E argues that it is not reasonable to discount potential PCT benefits based solely on the results of the limited operations of the startup program in a compact geographic area.
· With regard to TURN's questions of whether the demand response benefits from PCTs will last for four hours, PG&E states that TURN used a figure from PIER Buildings Program SCE Codes & Standards Program Workshop held early in 2006 to illustrate a steep drop in PCT impact near the end of the fourth hour. However, that table is the product of a DOE 2.2 model simulation, where the program is told to end by 6:00 p.m. Hence, according to PG&E, the model should be expected to produce a sharp drop in its simulated demand response by 6:00 p.m.
In response to TURN's statement regarding RA requirements, PG&E notes that demand response can count for RA if it is available for 48 hours per summer, or qualify as a two-hour resource if not more than 0.89% of the RA need. In effect PG&E is reserving the right for the PCT (and possibly other DR programs under consideration here) to provide a smaller value to ratepayers (only two hours rather than four hours per day). However PG&E states it has made no showing that the PCT program is the only two-hour resource that the company will consider, and that the 0.89% of capacity from two-hour resources is not already oversubscribed (in which case the RA value of two-hour PCT savings would be zero)
While TURN refers to Figure 5-3 in the KEMA report for the proposition that PCT demand response drops off, PG&E points out that what the KEMA report really shows is a positive relationship between the temperature and the demand reduction for PCTs, as well as the program in general, based on summer 2007 data. Moreover, according to PG&E, KEMA's analysis of the summer 2007 data found no statistical difference between the PCT drop-off and the switches. (Reporter's Transcript, p. 221, lines 5-18.)
· Regarding TURN's attack on PG&E's 25% participation assumption, PG&E states that the KEMA process evaluation cited by TURN was performed at the program's infancy, when participation had yet to reach 5,000. However, in less than a year, the program has grown to over 75,000 customers with the $25 incentive, and PG&E indicates that is well on its way to achieving the 25% market penetration target.
In addition, PG&E states that TURN's use of the Rate Option Positioning Research performed by Greenberg Brand Strategy in 2007 (Greenberg study) is inapplicable for Title 24 PCTs. The statement from the Greenberg study referenced by TURN reports that focus group participants with newer air conditioning systems were negative about changing equipment they had just installed. According to PG&E, this point is irrelevant for Title 24 PCTs required for new construction and permitted retrofits, because the PCTs would already be installed to comply with state building code standards. That code standard would neutralize the issue over time, and would help with several other customer concerns.
Regarding TURN's double counting argument related to how the CEC might conduct future analysis for new initiatives within its jurisdiction, PG&E states it is speculative and indicates that the CEC analysis TURN cites was done several years ago and includes assumptions of questionable relevance now. Also, PG&E states the CEC will have a number of input options that are not used in the Total Resource Cost (TRC) test at the Commission. For instance, the CEC might include customer bill savings and incentives from DR or rate programs in its analysis, although they are not part of a TRC analysis at this Commission. PG&E concludes that, since the CEC does things its own way, there is no way to know today what a future CEC analysis will depend upon.
The threshold issue is whether or not to include PCT benefits in the cost effective analysis for the Upgrade. PG&E has produced evidence from which it can be concluded that its cost effectiveness analysis includes HAN facilitated CAC cycling for new Title 24 PCTs beyond the level needed to replace attrition associated with the 305 MW in the A/C settlement. We do not see double counting as alleged by DRA.
Also, we are not convinced by TURN's double counting argument involving future CEC actions. TURN has not listed the costs that would or might be assumed in such CEC actions that would need to be compared to a benefit such as demand reduction, and we do not know what they would be. There is also no evidence as to what the magnitude of those costs might be. Therefore, we have no way of knowing whether or not any future CEC assumed costs would significantly affect the cost benefit analysis as it applies to the Upgrade. We can only conduct our analyses with the information available and take factors such as CEC actions into account when they are known and relevant. It would therefore not be appropriate to completely dismiss the use of Title 24 PCT benefits in the Upgrade cost effectiveness analysis, as proposed by TURN.
For these reasons, we will include the PCT benefits in the Upgrade cost effectiveness analysis. However, while we will consider Title 24 PCT benefits as proposed by PG&E, we do agree with TURN that PG&E's estimates of MW savings may be excessive.
First, there is no certainty that the Title 24 regulations will be implemented in 2012, if ever. While PG&E assumes that date, there is no real evidence to substantiate it. There apparently was significant opposition to the regulation to the extent that it was eventually withdrawn. Whether such opposition can be overcome either in the short term or the long term is uncertain in our minds. If new construction and permitted retrofits are excluded from the benefit analysis for any length of time beyond 2012, the benefits will be reduced significantly.103 PG&E projects some voluntary participants for this program. Whether the amount of voluntary participation will grow, if the Title 24 PCT regulations are not enacted, is uncertain.
There is also some uncertainty as to whether technological interoperability issues with Title 24 PCTs may interfere with PG&E's ability to operate AC units through the HAN interface.104
Regarding PG&E's estimated 0.75 kW/hour savings per customer for the PCT program, PG&E gives a reasonable explanation of why 0.48 KW/hour savings may be low but provides no convincing evidence to justify its assertion that different ramping strategies will necessarily result in 0.75 kW/hour savings.
Whether PG&E's 25% market penetration rate will be reached is debatable. PG&E states that participation has grown to over 75,000 customers with the $25 incentive, and indicates that is well on its way to achieving the 25% market penetration target, but does not indicate where it is now and how much further it needs to go to meet the target.
We accept PG&E's explanations related to PCT duration and RA credits, but TURN's proposed reduction in PCT demand response due to the cost of the PCT for voluntary participants has some merit. PG&E has produced no estimate of what a PCT device would cost, while TURN estimates costs to be in the range of $90 to $120, which is significantly higher than the $25 rebate.
Given the above discussion, it is reasonable to reduce PG&E's forecasted benefits for the Title 24 PCT program by some amount. However, the state of the evidentiary record does not facilitate the quantification of what that amount should be. Demand response benefits are difficult to quantify because they depend substantially on future customer behavior to changed circumstances. Parties can speculate on what that behavior might be based on limited studies or theories but what will actually happen is far from certain. For these reasons, we will instead split the difference between TURN's estimate of Title 24 PCT program benefits and that of PG&E. We calculate that amount to be a PVRR of $83,427,000 as opposed to PG&E's estimate of $129,401,000.
74 AB1X refers to Assembly Bill No. 1 from the 2001-2002 First Extraordinary Session as codified by Water Code section 80000 et seq. Water Code section 80110 protects the rates of residential customers for usage up to 130% of baseline quantities "until such time as the [Department of Water Resources] has recovered the costs of power it has procured for the electrical corporation's retail end use customers...."
75 In D.06-07-027, the Commission ruled that residential customers may waive their AB 1X protections to participate in voluntary tariffs that give customers an opportunity to lower their bills.
76 According to PG&E, an affirmative waiver of AB 1X protection for the PTR program would be unnecessary because (unlike with CPP) there is no potential for charges to increase for usage billed at Tier 1 or 2 rates; customers who do not earn a rebate simply continue to pay their normally applicable rate.
77 According to PG&E, this approach will reduce revenue accruing to the Utility Generation Balancing Account (UGBA) by the demand response component of PTR bill savings (total PTR rebates net of the free ridership adjustment), simply because the UGBA is the generation-related account to which revenues accrue residually. This may produce a modest mismatch between generation-related accounts, since PTR-related procurement savings would most likely be realized as reduced costs in the Energy Resource Recovery Account (ERRA). PG&E states that while this is a factor which PG&E and the Commission might wish to weigh when reviewing future UGBA and ERRA balances, it would not affect total generation rates or the division of costs between different groups of customers.
78 DRA's recommendation is detailed in Exhibit 108, Ex. 5, Ch. 5B.
79 See D.08-07-045, Conclusion of Law 23. D.08-07-045 addresses the dynamic pricing phase of PG&E's last Phase 2 GRC.
80 D.08-07-045 orders PG&E to "file an application proposing a default CPP rate for residential customers 30 days after any change in the law that changes the Assembly Bill 1X rate protections in a manner that could allow default or mandatory time-variant rates for residential customers. If the Commission approves a decision that interprets the Assembly Bill 1X rate protections in a manner that could allow default or mandatory time-variant rates for residential customers, then PG&E shall file an application proposing a default CPP rate for residential customers not later than 90 days after the Commission decision goes into effect and is no longer subject to rehearing or judicial review."
81 See Sections 7.7 and 10.2.4.
82 See D.08-02-034, p. 22.
83 See D.08-09-039, p. 38.
84 SEER is the Seasonal Energy Efficiency Rating, defined by the Air Conditioning and Refrigeration Institute. Higher SEER ratings are more energy efficient.
85 TURN states that while its witness, Ms. Schilberg, conceded upon cross-examination that the AC adjustment factor could involve a slightly smaller derate than appears in TURN Ex. 211, p. 16, the AC adjustment factor was erroneously omitted from its adjustments to the expected PCT MW. TURN states that it considers these two factors to be offsetting, and this decision assumes that TURN's total SEER related adjustment is reflected in its PTR adjustment.
86 IBM Global Business Services and eMeter Strategic Consulting for the Ontario Energy Board, "Ontario Energy Board Smart Price Pilot Final Report" July 2007.
87 Hiner & Partners, Inc., "Pacific Gas and Electric Company 2007 Rate Option Survey," August 2007.
88 Exhibit 211, p. 18.
89 See PG&E, Ex. 25, p. 24.
90 Id., p. 25.
91 Exhibit 218, p. 25.
92 PG&E, Exhibit 8, p. 9-3.
93 TURN assumed a 30% increase in efficiency when moving from SEER 10 to SEER 13. Based on the information in Exhibit 218, Figure 12, and the general concerns related to using SEER for such purposes, a 15% increase in efficiency appears reasonable.
94 D.08-09-039, p. 30.
95 PG&E points to the requirements for PG&E's February 2009 rate design window filing contained in D.08-07-045 that suggest that the Commission has more dynamic rate options in mind.
96 D.08-09-039, pp. 52-54.
97 If PG&E requests such recovery, it must fully justify the costs and the incremental nature of the costs.
98 California Statewide Residential Appliance Saturation Study Update to Air Conditioning UECs Using 2004 Billing Data Final Report, prepared for California Energy Commission (400-04-010), KEMA-XENERGY, May 2006.
99 New construction annual population estimates are calculated by applying climate zone growth rates and population counts consistent with those included in A.05-06-028, PG&E-4, Table 2-4 and 2-5, p. 2-10.
100 PG&E states that consistent with the SmartAC impact estimates is the assumption the 30% of residential customers will also participate in a dynamic pricing option, and therefore the average technology impact of 1.1 kW is expected to eliminate double counting of demand benefits with CPP or PTR.
101 PG&E, Exhibit 3, p. 4-4, footnote 2.
102 DRA, Lee, 5 RT 718-719, 723.
103 As TURN indicates this issue was not as critical in evaluating SCE's AMI proposal, because SCE included both the cost of a PCT as well as the benefit of the PCT in its PCT demand reduction analysis. PG&E does not provide for the cost of the PCT, although it does provide a $25 rebate for this program.
104 In its Comments on the Proposed Decision of ALJ Fukutome, DRA noted the recent CEC Draft Committee Report on Proposed Load Management Standards, dated November 2008. In that report, the CEC proposed that communication of DR events with DR enabling technology be communicated through a Radio Data System and via the internet. In reply comments, PG&E states that in comments posted on the CEC website, PG&E and other utilities have identified major problems with the draft technical standard, and the Draft Technical Report recognizes the importance of the utilities' AMI systems that meet the CPUC's minimum functionality requirements to meeting the CEC's goals.
