7. Rate Design - Small and Medium Customers
7.1. Default Date for Small and Medium C&I Customers
PG&E's proposal to offer PDP by May 1, 2010 to all customers with appropriate interval meters and to impose PDP/TOU rates on a default basis, for specific customer classes, which would begin on either May 1, 2010 or February 1, 2011, is consistent with the timeline determined by the Commission in D.08-07-045.
DRA's primary recommendation is to default small and medium commercial customers with a 12-month advanced meter history to TOU rates beginning February 1, 2011, and to transition such customers to default PDP/TOU rates after they have been on TOU rates for one year.
However, if the Commission does not adopt DRA's primary recommendation, then DRA's secondary recommendation is to default small and medium C&I customers with a 12-month advanced meter history to PDP/TOU rates beginning February 1, 2012.
DRA states that delaying the implementation of full PDP rates by one year to February 1, 2012 for small and medium C&I customers will ease the transition for some 490,000 business customers, which make up approximately 85% of the non-residential sector. It is DRA's position that transitioning small and medium C&I customers to full PDP in February 2011 is undesirable due to the severity of the bill impacts on them, noting that, as PG&E's PDP rates were originally proposed, the 20% of small and medium C&I customers who are most impacted could experience a monthly bill increase of 25% to 42% relative to their previous flat rate during a hot year. DRA also points to the economic difficulties facing small businesses in California today including job losses, dropping sales, increasing costs and difficulties in obtaining small business loans.
DRA also states that the economic recession has had a significant impact on demand and a one-year delay in implementation of PDP for small and medium C&I customers should have little adverse effect on reducing energy demand. DRA also points out that deployment of SmartMeters has fallen behind schedule; it is possible that about half of PG&*E's customers will not have the advance meters by February 2011, and at worst a one-year delay for small and medium C&I customers will result in a loss in demand benefits from 25% of this customer segment.
With respect to SmartMeters, DRA notes that since this proceeding was submitted for decision, (1) public hearings convened by Senator Dean Florez focused on the price shock PG&E customers have experienced with their recent power bills and (2) the Commission has ordered an independent audit of PG&E's SmartMeter installations in Bakersfield, and the customer education and outreach PG&E is conducting about those installations.18
With respect to the development of customer notification equipment, DRA states that the one-year delay is desirable for small and medium commercial customers, given that there is something of a "chicken and egg" problem, since the requisite notification equipment may not be marketed unless a significant percentage of customers are on dynamic rates. Yet, according to DRA, such rates for such customers can be sufficiently onerous to lead to excessive opt-out rates without such equipment. DRA believes the best tradeoff is to delay the implementation of PDP rates for small and medium businesses for one year, noting that PG&E's own witnesses expect such equipment to be on the market in 2012.
PG&E states that, under DRA's primary proposal, customers would face two changes within one year: (1) mandatory TOU beginning in 2011 and (2) default PDP beginning in 2012, which would require two waves of messaging, the first one about TOU and a second one about PDP a year later. Moreover, if DRA's proposal were adopted, customers would face evaluating their business process first for TOU and then a year later, a second time for PDP.
PG&E believes that ways to be successful with a customer's energy consumption under TOU may or may not lead to ways that are successful with the CPP portion. PG&E also believes it is not appropriate to ask customers to go through and reevaluate their business processes to understand how to be successful on TOU and only one year later to come back and say the rules of the road have changed again and, now that they have gotten accustomed to TOU, they need to also get accustomed to CPP. It is PG&E's position that the Commission should implement the TOU and PDP changes together, and not separate them by a mere 12 months. Therefore, PG&E urges the Commission to reject DRA's proposal and adopt the February 1, 2011 implementation date for PDP combined with mandatory TOU, as reflected in PG&E's proposal and the schedule in D.08-07-045.
For the reasons cited by PG&E, we believe that defaulting small and medium C&I customers first to TOU rates and then one year later defaulting them to CPP and TOU rates is not appropriate. The proposed transition process may lead to customer confusion and frustration, resulting in reduced participation in the PDP program. Therefore, it will not be adopted.
However, after considering the evidence on this issue, we believe that deferring the default date will improve the success of PG&E's education and outreach efforts by providing time for greater collaboration between PG&E and affected customer groups and by allowing time for additional Commission oversight. Thus, we conclude it is reasonable to defer the default date of November 1, 2011. While it is three months earlier than recommended by DRA, the 2011 peak season will have ended by that time and the likelihood of peak days will be low until the 2012 peak season. This will provide additional time for customer outreach and education with respect to PDP effects and customers' options, before peak days are experienced. Since PDP events are very unlikely during the winter, beginning the default in November 2011 will provide small and medium C&I customers to gain experience with a TOU rate before the summer of 2012 when peak days are more likely. This will achieve many of the benefits of DRA's primary proposal (i.e., defaulting to TOU in 2011, then PDP in 2012), but over a shorter timeframe.
With respect to this issue, our primary concern is the need for customers to be fully informed about PDP and the default process and to be able to make optimal choices with respect to the process. Customer outreach and education is discussed later in this decision. In adopting and supplementing various aspects of PG&E's outreach and education proposals, as well as deferring the default date for small and medium C&I customers, we believe there is a much greater chance that the transition to PDP will be successful.
7.2. Options for Reducing Bill Volatility
For those residential, small and medium C&I and agricultural customers who are subject to the PDP tariffs, and who are not served under tariffs where a capacity reservation charge is an option (i.e., Schedules E-19, E-20 and AG-5C), PG&E proposes that customers instead be allowed to choose between different options for PDP event duration and limits on consecutive-day PDP operations. According to PG&E, these options will serve the same purpose of mitigating customer bill volatility as is to be served by capacity reservation subscriptions for larger customers. In particular, customers will be offered the following two options:
Limit on Consecutive PDP Operations
Customers choosing this option will never be subject to PDP prices on consecutive days. Instead, customers requesting service under this PDP option will be divided into two groups (of approximately equal size) and PDP prices will be in effect on alternating PDP event days for these customers. Because customers requesting service under this option will expect to be called upon for only one-half of the total number of PDP event days each summer, their offsetting PDP rate credits will also be reduced by one-half.
Choice of Event Duration
PG&E's standard PDP pricing period for all non-residential rate schedules will be the four-hour period between 2 p.m. and 6 p.m. However, non-residential customers will be offered the choice of paying somewhat lower per-kWh PDP prices (by a factor of one-third) if they request a six-hour PDP event period (noon to 6 p.m.) rather than the standard four-hour period. Residential customers will not have this option as the current SmartRate five-hour event duration (2 p.m. to 7 p.m.), which falls between the two options described above, is being retained for the class.
The proposed default assignment for all non-residential customers will be to service that is subject to no limit on consecutive operations and the standard four-hour PDP pricing period. The default assignment for residential customers will be no limit on consecutive day events, with a standard five-hour event duration (and no options for changing the standard residential PDP period).
PG&E states that if the Commission wants customers to respond to PDP prices, the customers need to consider actively how they can change their energy usage to respond to the new rates. According to PG&E, its two options would encourage the customers to think about which choice is best for them, which by necessity involves considering their business operations, energy demands, and what they can change.
Also, in rebuttal testimony to DRA's "soft cap" proposal, PG&E indicated that its Balanced Payment Plan (BPP) program is an existing service option which is available for all residential and small commercial customers. PG&E states that it will continue making the BPP available for small commercial customers accepting assignment to the default PDP tariffs, so this is an existing service option which will already exist and will afford protections similar to those that would be afforded by DRA's more complex system of monthly and increasing annual bill caps.
TURN supports PG&E's proposed mechanisms that allow customers to hedge the risk of bill volatility.
DRA asserts that PG&E's alternating PDP day and six-hour PDP window proposals add complexity, both from the customer perspective and from the utility perspective with respect to customer outreach, PDP event notification, and billing, adding that in deciding whether to endorse these proposals, the Commission must weigh the value provided by these proposals against the cost and complexity of implementing them.
With respect to the value provided, DRA argues that PG&E's proposals are inferior, compared to the other monthly bill volatility mitigation proposals on the record, specifically DRA's "soft cap" and PG&E's BPP proposals, and there is no evidence that PG&E's alternating day and six-hour window present sufficient value to the customer to offset their complexity.
Also, DRA states that there is no evidence on the record that PG&E surveyed its customers about alternating day or six-hour PDP window options for mitigating bill volatility or that PG&E made any effort to assess potential customer interest in having such options available.
In DRA's opinion, the Commission should rank the alternating PDP day and six-hour PDP window options last among the three monthly bill volatility options presented on the record.
With respect to the BPP, DRA states that it has the advantage over the other options in that it is already implemented and therefore there is no incremental cost except for possible costs of notifying PDP customers of their eligibility and explaining the potential pros and cons of accepting that option. On the other hand, DRA argues that a PDP customer electing BPP will experience a severely attenuated PDP price signal by PDP charges being spread over 12 months or payable up to six months after the summer season.
DRA recommends that PG&E offer a "soft cap" for summer monthly bills for A1-PDP and A6-PDP customers, based on a "monthly average energy rate limiter" of 110% of the average summer A1-TOU or A6-TOU rate, respectively. PG&E should then roll forward any unbilled PDP revenue to the following month's bill. Unbilled PDP revenue would continue to roll forward until headroom under the 110% cap permits collection. DRA asserts that this mechanism would dampen monthly bill volatility without any loss of PDP revenue and without imposing complex additional decision analysis on small and medium customers.
According to DRA, while its soft cap proposal causes some PDP signal attenuation, unlike the BPP any bill in a month with more than the average number of PDP events will show an immediate increase in the amount due and payable, and in most cases, PDP charges would be fully collected by the end of the summer season. Thus, DRA believes that its soft cap proposal is superior to PG&E's BPP for the purpose of mitigating monthly PDP customer bill volatility.
PG&E opposes DRA's monthly soft cap proposal arguing that DRA's 110% monthly limiter would be a major change adding significant costs and delay to the PDP project, and may even be beyond the capability of Customer Care and Billing (CC&B) Version 2.2. PG&E is also concerned that DRA's 110% monthly cap will add complexity to bills and confuse customers.
We will adopt PG&E's alternating day and six-hour window options to mitigate bill volatility for those customers that do not have a capacity reservation option. We prefer PG&E's proposal, because, similar to the capacity reservation charge, it provides customers with an incentive to choose or stay on PDP rates by offering an option to reduce their exposure to potential increases related to those rates. On the other hand, the "soft cap" and BPP are mechanisms that spread the effect of monthly rate increases over a longer timeframe. PG&E's proposal also does more to encourage customers to evaluate how they use electricity as well as what they can do to, and how likely they would, reduce or shift their usage. Certainly this is a more complex and potentially confusing exercise when compared to simply being subject to DRA's proposed "soft cap" or the current BPP. However, with appropriate and comprehensive customer education, we believe PG&E's proposal which enhances customer choice can be implemented successfully.
With respect to bill volatility, under PG&E's revised proposal, Schedule A-10 customers are the only ones that have a PDP default where 100% of peak time usage would be set at the $1.20/kWh charge. The E-20 and other large customer classes will only be subject to 50% of their peak time usage at the PDP rate because a 50% capacity reservation charge will be the default amount. The PDP rate for the A-1 customer is set at $.60/kWh, and the residential/small agricultural PDP rates are opt-in rates.
We will address this concern by adopting reduced PDP charges for Schedule A-10, similar to the adopted approach for Schedule A-1. Specifically, PG&E's proposed PDP charges and credits for Schedule A-10 will be reduced by 25%. This adjustment reduces the default peak-time charge for these customers to $0.90 per kWh. Also, we will adopt the alternate day and six-hour window options proposed by PG&E for the A-10 customers to provide other bill volatility mitigation options.
7.3. Additional Bill Stabilization/Protection
DRA recommends that PG&E be directed to offer a second and third year of modified annual bill stabilization to small commercial customers, with an increasing cap of 110% of the otherwise applicable TOU bill in the second year of PDP service, and 120% in the third year. According to DRA, special treatment is merited for small customers because they have the least resources to deal with rate design change and because most of these customers have never been on time-varying prices. DRA also proposes that further annual bill capping should be reevaluated in PG&E's 2014 GRC.
PG&E opposes DRA's proposal for additional bill stabilization/protection, indicating that DRA does not provide any additional testimony or documentation to support its proposal for second and third year bill stabilization, or to allow the Commission and other parties to evaluate whether this extra protection for small C&I customers is warranted. Also, when considering the effects of second and third year bill stabilization, along with the effects of the monthly energy limiter of 110%, PG&E anticipates that the combined effect of DRA's monthly and annual bill mitigation proposals would compound the difficulty for customers to understand their bills. PG&E states that this is a major change to its proposal that would be very costly and would adversely impact the project schedule. PG&E is also unsure whether its CC&B would support this structure prior to the Version 2.3 upgrade.
We will not extend the bill stabilization/protection beyond the first year. We make this determination with the understanding that there will be appropriate and comprehensive customer education with respect to understanding the PDP program and customer options.
We recognize that bill stabilization reduces the risk for participants to enter or remain in the program. However, extending bill stabilization beyond one year must be balanced against our determination that it is reasonable for non-participants to share in the risk of a new rate program if its purpose is to lower rates for all customers in the long term. However, the extent to which non-participants bear the participants' costs should be limited to what is necessary to effectively implement the PDP rate.
We will ensure that the vast majority of customers will have at least 12 months of historic usage available when deciding their PDP options or when being defaulted to a PDP rate. The first year of bill stabilization will protect customers who are on PDP rates by allowing them to experience the actual effects of such rates without facing financial harm over that period, if the PDP is disadvantageous when compared to the otherwise applicable TOU rate. We believe this is a sufficient duration for all PDP customers to understand that peak period usage when there are PDP events will be significantly more expensive than before.
This belief is especially true for customers who affirmatively choose PDP. We assume these customers have evaluated their situations in choosing PDP. A year of actual experience should be sufficient for such customers to decide whether or not their evaluation was correct and to adjust accordingly.
We feel somewhat less confident about customers, who are defaulted onto PDP rates, especially smaller and potentially less sophisticated customers with respect to rate matters. Such customers may not have evaluated their options before being subject to PDP rates. However, they also will have experienced a number of PDP events and the monthly rate effect of PDP rates with respect to their actual usage during the bill stabilization period. If, during the first year, it becomes obvious that they should opt out of PDP, they can do so and with bill stabilization not experience a long-term financial impact. We do not see what benefit a second and third year of bill stabilization will provide and are not convinced that the extension is necessary.
Again we must emphasize the importance of customer outreach and education. Especially for defaulted customers, it is extremely important that, as their first year on PDP progresses, customers become well aware of the PDP program, the details that affect their rates, their options to opt out or remain in the program and the requirements for switching rates in the future. As indicated in other parts of this decision, if customer outreach and education problems arise, it may be necessary to delay certain aspects of PDP implementation.
7.4. Up-Front Lump Sum Credit for Notification Information
For A1-PDP customers, PG&E now proposes a 1.096 cent per kWh PDP credit, applicable to all summer period energy usage. DRA proposes a one-time up-front lump sum PDP credit for small and medium C&I customers newly defaulting to A1-PDP rates in order to provide a more visible incentive to remain on PDP and to facilitate PG&E's collection of customer contact information for PDP event notification. Under this proposal, customers must be on a PDP rate by May 1, and would have to repay the credit if they opt out before October 31 of the same year. Also, the lump sum credit would be subject to true-up if a customer's actual usage is at variance with the usage assumed for purposes of setting the lump sum amount.
PG&E opposes this proposal, noting that this lump sum credit could interact in unanticipated ways with other elements of the rate and program design. In addition, PG&E states that the provision of a customer's credits in a lump sum, up-front credit means that, in later months, customers will only see the high PDP charges in the monthly bill amounts due, without the offsetting effect of the credits for the month, which could give customers an inaccurate perception of PDP charges. Moreover, PG&E indicates that DRA's recommendation would not solve the problem of maintaining accurate customer contact information, which tends to change over time. Lastly, PG&E asserts that DRA's lump sum proposal would have substantial impacts on cost and scheduling.
There may well be impacts on costs and scheduling associated with DRA's proposal. However, the reason that we will not adopt it is because of the potential for customer confusion as to what are the real effects of being on PDP. As PG&E indicates, by taking the energy usage credit up front, customers will only see the high PDP charges in the monthly bill amounts due, without the offsetting effect of the credits for the month. Artificially high monthly bills may be confusing to customers who are trying to determine whether to remain on PDP or to opt out of the program as they experience the effects of the program. We feel it is more important to ensure that customers understand how their usage affects their rates rather than to incent a customer to stay on PDP for a full season by offering the up-front credit as proposed by DRA.
As to facilitating the collection of customer contact information, there is value in that. However, it is not clear that proactive efforts by PG&E to obtain such information will be insufficient or lacking in some manner. Success in obtaining the information should be monitored and maximized as PDP is implemented. At this time, we do not feel the potential benefit of additional customer contact information by implementing DRA's proposal outweighs the downside of potential inaccurate perceptions of the effects of PDP.
7.5. Multi-Year Amortization
DRA proposes that revenue shortfalls resulting from annual bill stabilization should be amortized over multiple years, for specific rate classes, if recovery in one year would cause rates to rise by more than 1%. DRA states that generation-related revenues are already significantly volatile, prior to the widespread adoption of PDP. A history of generation-related over- and under-collections shows that since 2004, under-collections of 1%, 6%, and 8% have occurred, along with over-collections of 1% and 2%.
PG&E opposes DRA's recommendation. PG&E states that DRA did not provide any analysis to support its recommendation, while PG&E's analysis shows that it is very unlikely that the 1% threshold would be triggered. According to PG&E, in a summer of 12 or fewer PDP events, customer bill projections provided in their work papers show that even if 100% of the customers in each rate class were simultaneously subjected to first-year bill protection, the 1% threshold would not be reached. In addition, in scenarios with larger bill protection shortfalls (summers with larger numbers of PDP events), the shortfalls would occur only in concert with significant PDP revenue over-collections as a consequence of the large number of PDP calls -- which are likely to involve a net decrease to rates.
We will not implement DRA's proposal. PG&E has provided evidence that it is unlikely that the 1% threshold will be triggered. More importantly, the Commission already has the latitude to impose multiple-year amortizations when it feels it is necessary to do so, when looking at all rate changes that are happening concurrently, as well as considering what has happened in the near past and what may happen in the near future. A 1% or 2% increase in rates, when viewed in isolation, may not require multiple-year amortizations. If the increase becomes much larger due to other increases, the Commission can, and in the past has, extended the amortization period. We will leave it up to future Commission actions to decide if and when multi-year amortizations are appropriate when looking at all rate changes in the timeframe that those changes will happen, rather than now imposing amortization requirements for one narrow aspect of potential rate increases.
18 DRA's motion for official notice of these facts has been granted. See Section 39.
