5. Rate Design Guidance
The third question that the strategic work plan needs to address is "how should the dynamic pricing tariffs be designed and integrated into PG&E's overall rate design?" In other words, when PG&E proposes rates pursuant to the timetable, what should the dynamic rates look like? This section answers these questions and provides rate design guidance for PG&E to apply when developing rates. This rate design guidance will also be applied by the Commission when considering PG&E's specific rate design proposals.
The following sections address different aspects of rate design, take into consideration comments from parties, and establish rate design guidance. The rate design guidance also appears in summary form as Attachment A to this decision.
5.1. All Dynamic Pricing Rates
The August 22, 2007 Ruling identified three objectives of rate design:
(1) to reflect the marginal cost of providing electric service so that consumers make economically efficient decisions,
(2) to flatten the load curve in order to reduce capital costs over time, and
(3) to reduce load in the face of short-term electricity supply shortfalls.
The ruling also identified several other important policy and rate design considerations including energy efficiency, greenhouse gas emission reduction, rate stability, rate simplicity, cost causation, and utility cost recovery.70
Based on prior comments and the workshops, the January 23, 2008 Ruling put forth the following draft rate design guidance and requested further comment:
· Rate design should promote economically efficient decision-making.
· Rates should reflect marginal cost.
· Prioritizing and balancing marginal cost with other objectives such as energy efficiency and baseline allowances should be addressed when designing specific rates.
· Rates should also seek to provide stability, simplicity, and customer choice.
Parties' Comments
No party disagreed with the objectives of rate design proposed in the January 23, 2008 Ruling.
BOMA identifies equity as one of two primary objectives that should guide the design of dynamic pricing, the other being economic efficiency. BOMA defines equity as "a condition in which all consumers face electric rates that accurately reflect the true cost of serving their load." In other words, an equitable rate eliminates cross-subsidies between customers. BOMA believes economic efficiency is achieved by setting rates at the marginal cost of electricity production and delivery, and the marginal cost of electricity production and delivery vary with time. BOMA concludes that RTP best achieves economic efficiency and equity. BOMA believes that other objectives such as load flattening and reducing load in the face of emergencies are subsidiary goals, but generally supported by RTP.71
Discussion
Promoting economically efficient decision-making is the primary policy objective that can be achieved through rate design. A rate that promotes economic efficiency is one that charges a customer based on the marginal cost of providing the customer one more or one less unit of energy-in other words, a rate based on marginal cost. The Commission has had a long standing policy of adopting marginal cost-based rates.72
Marginal cost-based rates will tend to address the other objectives identified in the August 22, 2007 Ruling-flatten the load curve to reduce capital costs over time and reduce load in the face of short-term electricity supply shortfalls. Marginal cost-based rates also encourage energy conservation, energy efficiency, and demand response. Furthermore, marginal cost-based rates can reduce greenhouse gas emissions by discouraging consumption during high cost periods when the least efficient, and highest greenhouse gas emitting power plants are operating.73 Finally, marginal cost-based rates improve reliability, lower overall costs, and maximize overall social welfare.
Parties identified several laws and other objectives related to residential rate design. For example, Public Utilities Code Section 739(c)(1) requires that each IOU establish rates that include baseline rates for residential customers, and requires that the baseline rates apply to the first or lowest block of an increasing block rate structure.74 Also, Public Utilities Code Section 739.7 requires that residential rates include an "inverted rate structure."75, 76
Baseline rates and an inverted block rate structure may not be consistent with the objective of promoting economically efficient decision-making. Advanced metering and dynamic pricing offer alternate approaches to rate design that could be more effective at lowering overall customer costs, promoting conservation, and reducing greenhouse gas emissions. Therefore, the Commission should consider seeking legislative changes to these sections to better align residential rate design with the State's other policy goals.
To the extent rates are required to satisfy legal requirements or secondary objectives, those other requirements and objectives should be addressed when designing specific rates. When addressing secondary objectives, any deviation from the primary objective of promoting economic efficiency should be minimized.
BOMA identified equity as a primary objective of rate design. Similarly, as part of the DRRC Rate Project, the DRRC's consultant, the Brattle Group, included equity among the four ratemaking objectives that it used to evaluate straw rate designs.77
We agree with BOMA that rates based on marginal cost will simultaneously achieve economic efficiency and equity by ensuring that customers' rates are commensurate with the costs they cause. Marginal cost-based rates should effectively eliminate cross subsidies between customers since a customer who is less expensive to serve would pay less, and vice-versa for a customer who is expensive to serve. Therefore, we conclude that equity is not a distinct objective of rate design.
We will also adopt the guidance that rates should seek to provide stability, simplicity, and customer choice. By "stability," we do not mean rates or bills should be the same month after month. Dynamic pricing by its nature changes from one time period to the next, as will the bills. However, we believe that the overall structure of dynamic pricing rates should be relatively stable over time. For example, utilities should seek to maintain a stable relationship between wholesale market conditions and dynamic rates so that customers can be confident that changes in their rates are tied to changes in wholesale markets.
Rates should provide simplicity from the standpoint of being easy for a customer to understand. Customers on dynamic pricing rates need to understand how their decisions to use more or less electricity during different times will impact their bills.
Rates should provide customers choice by offering several rate options or offering customers the ability to expose more or less of their consumption to dynamic pricing.
We conclude that, with minor modifications, the four rate design objectives proposed in the January 23, 2008 Ruling should be adopted. Accordingly, we will adopt the following rate design guidance:
· Rate design should promote economically efficient decision-making.
· To promote economically efficient decision-making, rates should be based on marginal cost.
· Other objectives, such as energy efficiency, and legal requirements, such as baseline allowances, should be addressed when designing specific rates, and any deviation from marginal cost should be minimized.
· Rates should also seek to provide stability, simplicity and customer choice.
5.1.2. Design of Rates Relative to Each Other and Handling Revenue Over- and Under-Collections
When multiple rates are offered to customers within a rate class, one design method is to set each rate such that a customer with a class-average load shape would pay the same under each rate. Rates designed as such are referred to as being revenue-neutral relative to each other. Parties differed as to whether non-time-variant, TOU, CPP, and RTP rates should be revenue-neutral relative to each other.
PG&E recommends establishing revenue-neutral tariff choices for each customer class. PG&E believes that if rates are established on a revenue-neutral basis and if the rates generally reflect avoidable procurement costs, then future year under- and over-collections should be limited.78 PG&E believes that revenue recovery issues should generally be addressed on a case-by-case basis as new rates are developed.79
SDG&E similarly advocates for basing all rates within a class on the same revenue requirement. SDG&E believes that basing rates on different revenue requirements will lead to customer migration from high cost rates to lower cost rates. SDG&E argues that over time rates should remain revenue neutral relative to one another.80
CLECA poses three questions that should be answered when implementing dynamic pricing to determine the appropriate way to handle revenue under- and over-collections within a rate class: (1) if a customer reduces its usage, especially at times of high system costs, does it see a reduction in its bill? (2) Do such reductions in a customer's bill reflect a reduction in costs for the utility? (3) How often should tariffs be adjusted for changes in load forecasts due to customer responses to tariffs?
CLECA answers the first two questions by arguing that, initially, CPP and RTP should be designed to be revenue-neutral relative to TOU. However, over time as customers migrate to different rates, the cost basis for each rate should be based on the cost to serve the customers on each rate. CLECA disagrees with the utilities that setting rates in this manner will result in any substantial migration between rates.81
EPUC stresses that differences between the revenues collected from customers on a dynamic pricing rate option and the costs to serve the customers on the rate option should be collected from or refunded to the customers on the rate option and not spread across other rates. Customers should not be penalized for not moving to a dynamic pricing option.82
Discussion
As PG&E suggested, the Commission's expectation is that dynamic pricing based on marginal cost will do a reasonably good job of aligning utility revenues and costs. As such, significant rate adjustments due to revenue over- and under-collections should be limited.
We generally agree with CLECA that the cost basis of a rate should be based on the cost to serve customers on the rate. We also agree with EPUC that mismatches between the revenues collected from customers on a rate and the cost to serve those customers should not be spread across other customers. Accordingly, as a general rate design principle, we believe that if customers on a particular rate reduce their usage in a manner that reduces a utility's costs then the customers on that rate should see a commensurate reduction in their bills.
We cannot conclude that establishing revenue-neutral rate options, as advocated by PG&E and SDG&E, is consistent with this principle. Instead, when PG&E proposes specific rates we will require PG&E to explain how the method in which it is setting rates relative to each other, and the method by which it intends to handle revenue over- and under- collections will ensure that if customers on a specific rate schedule take actions that reduce the utility's costs then the customers on the rate will see a commensurate bill reduction.
In summary we will adopt the following rate design principle:
· If customers on a particular rate schedule reduce their usage in a manner that reduces a utility's costs then the customers on that rate should see a commensurate reduction in their bills.
The Demand Response Research Center's (DRRC) rate design issues paper describes the concept of a hedging premium in the context of rate design.83 In a competitive retail market, if a retail provider offers a customer energy at a flat price then the retail provider assumes the risk that energy in the wholesale market might deviate from the flat price. The retail provider would charge its flat rate customer an extra premium to compensate for the price risk assumed by the retail provider. Alternatively, the retail provider could manage its risk by purchasing hedges or buying blocks of energy at a flat rate, presumably at a premium that would be passed on to the customer. The hedging premium has the effect of increasing flat rates relative to real time pricing.
Parties in this proceeding were asked whether the California utilities incur a hedging premium on behalf of their customers that are on non-time-variant and TOU rates. If so, then it could be argued that the utilities should be charging customers more to be on rates that are less time-variant and deviate the most from wholesale market conditions.
Parties' Comments
Several parties note that the utilities are very significantly hedged through resource adequacy requirements and long-term contracts. However, no party argues that the hedging premium concept can be easily translated to the California IOUs. At best, parties suggest that the issue deserves further consideration.84
Discussion
The hedging premium may have a strong basis in competitive markets; however, we conclude the concept cannot be translated to the regulatory environment in which PG&E and the other utilities currently operate. The utilities are significantly hedged through resource adequacy contracts and other forms of long-term contracts. Many of these contracts provide some price stability for the utilities through fixed prices and fixed heat rates. However, the Commission's resource adequacy and long-term procurement policies and the utilities' procurement practices do not currently take into account the structure of retail rates. Conversely, retail rates are not designed in coordination with the utilities' procurement practices.
Furthermore, since the utilities' sales and profits have been decoupled, the utilities are generally not at risk for deviations between retail rates and actual costs. If wholesale energy prices or the amount of electricity consumed deviates from the projections, the utilities can generally refund or collect the difference in a subsequent time period.
Because of the nature of long-term contracting and decoupling, there appears to be little cost-based justification to incorporate a hedging premium into rates at this time.
Distinct from the concept of a hedging premium is the idea that customers on a dynamic pricing rate should have the option to choose how much of their load is subject to a dynamic rate and how much is purchased at a fixed price. In other words, should customers be able to hedge some of their exposure to a CPP or RTP rate?
Parties' Comments
DRA is opposed to requiring that customers take service on dynamic pricing rates without having hedging options. DRA argues that a functioning market provides customers the choice of how much price certainty and reliability they want.85
CLECA, CMTA, and EPUC believe that customers should have the opportunity to hedge some of the price risk associated with dynamic pricing. These parties argue that the appropriate hedging products are generally not available in the marketplace, and if the hedging products are available, their price is unreasonable. CMTA and EPUC support the use of a two-part tariff, including a demand component and an energy component, in which only the energy component, or part of the energy component, is subject to dynamic pricing.86
KMEP proposes a CPP rate option that would allow customers to hedge their exposure by defining a baseline for flat load customers and only transitioning to the CPP rates when a customer's load deviates from the baseline.87
SDG&E supports offering customers the ability to hedge their exposure to price volatility. As an example, SDG&E points to its default CPP rate which includes a capacity reservation charge that allows customers to reserve capacity during CPP events that will not be subject to CPP rates.88
Discussion
We believe dynamic pricing rates should give customers, especially larger commercial, industrial, and agricultural customers, an opportunity to hedge some of their load. There is no reason dynamic pricing should be all-or-nothing. Some customers may prefer a "pure" version of a CPP or RTP rate in which all of their usage is subject to the critical peak or real time price, but others may prefer to only expose some of their usage to dynamic pricing. This is consistent with our principle that rates should offer customers choice.
SDG&E has offered a good model for CPP. D.08-02-034 approved default CPP for SDG&E's large C&I customers. As part of the CPP rate design, customers can "reserve" capacity for some or their entire load by predesignating an amount of load and committing to pay fixed monthly payments for that load. SDG&E refers to this as the capacity reservation charge. During a critical peak event, the load in excess of the reserved amount is charged at the critical peak price. We believe this is a promising approach to give customers an opportunity to hedge.
It is premature to recommend how hedging should work under RTP, whether through a two-part tariff or some other means. However, we do believe that future RTP rates should offer customers an opportunity to choose to hedge some of their usage.
Therefore, we will adopt the following rate design guidance:
· Dynamic pricing rates should include a capacity reservation charge, or a similar feature, that allows a customer to pay a fixed charge for a predetermined amount of its load and pay the dynamic price for consumption in excess of the reserved capacity.
5.1.5. Ability to Opt Out from Default Rates and Bill Protection
This section addresses whether rates should offer the possibility to opt out to another rate.
Dynamic pricing rates can also include a provision that protects customers' bills during an initial trial period, typically, the first year. If a rate offers bill protection, a customer's bill would generally be calculated under both the new dynamic rate and the prior rate during the year. If the customer pays more during the year under the new dynamic rate than the customer would have paid under the old rate, then the customer receives a refund for the difference at the end of the year. If the customer pays less under the new dynamic rate then there is no refund at the end of the year. The experience during the year could help a customer determine whether to stay on the new dynamic rate or opt out to another rate.
Parties' Comments
SDG&E supports providing customers bill protection during the first year. SDG&E's 2008 General Rate Case Phase 2 decision, D.08-02-034, adopted bill protection for the first 12 months.
BOMA states that offering bill protection during the first year on a dynamic pricing rate is problematic for tenant-occupied commercial buildings due to the time lag between the monthly payments during the trial year and the potential refund at the end of the year. First, BOMA explains that the timing mismatch could create cash flow problems for tenants if they pay high bills during the summer but do not get a refund until the end of the year. The refund can also be challenging for landlords who may need to track down tenants that have left the building.89
CLECA does not support requiring a customer to stay on a dynamic pricing rate for a full year with bill protection. According to CLECA, bill protection that only comes at the end of the year can create cash flow problems for customers.90
EPUC believes bill protection is important if large commercial and industrial customers are required to be on dynamic pricing for one year.91 However, EPUC notes that even with annual bill protection, customers will still focus on the monthly bill fluctuations that could occur under a CPP rate. It is also important to EPUC that customers have the ability to switch back to the TOU rate after the first year.92
According to PG&E, if there are a variable number of CPP events the first year bill protection will be misleading since the number of events during the first year could differ from the number of events in future years.93
Discussion
While it is our goal to encourage customers to participate in dynamic pricing, and we expect many customers will find opportunities to save money on dynamic pricing, we also want to provide customers choice. Therefore, customers should have an opportunity to opt out to other rates.
The default CPP rate adopted for SDG&E in D.08-02-034 provided for an initial 45-day opt-out period. If a customer does not opt out to a TOU rate during the first 45 days the customer will be required to remain on CPP for a full year. We believe this is a reasonable approach. In general, some restrictions on opting out are appropriate; however, we will not dictate a particular approach.
We continue to believe that bill protection is valuable to enable customers to become familiar and comfortable with a new rate. However, there may be customers that would rather not have bill protection. Thus, we conclude that utilities should offer, but not require, bill protection during the first year.
As general rate design guidance we conclude the following:
· Customers should have the opportunity to opt out of a default dynamic pricing rate to another time-variant rate.
· Utilities should offer optional bill protection to customers on default dynamic pricing rates.
5.1.6. Integration with the CAISO Operated Wholesale Energy Markets
In comments discussing CPP, parties recommended that the utilities coordinate with the CAISO. DRA believes the utility and CAISO should coordinate to determine when CPP events should be triggered. According to DRA, the CAISO generally has a broader perspective on the energy supply-demand balance, although the utility would be the entity that actually communicates with customers.94
TURN argues that if the utility triggers a CPP event, the utility should bid the associated load into the CAISO day-ahead market so that the CAISO knows the load reduction is there at some price.95
We agree with DRA that the utilities should coordinate their use of dynamic pricing with the CAISO, and we agree with TURN that the utilities should bid demand reductions resulting from dynamic pricing into the CAISO's day-ahead market. Dynamic pricing is intended to better align retail rates with wholesale market conditions; thus, the utilities should make sure that demand reductions that result from dynamic pricing are reflected in the day-ahead energy market. If retail customer responses to dynamic pricing are reflected in the wholesale market, then the market should function more efficiently and at times clear at a lower price. The CAISO can also avoid procuring unnecessary resources if the CAISO knows that demand will be lower due to dynamic pricing.
The utilities could submit price-responsive hourly schedules to the day-ahead market so that the CAISO knows that demand will change in response to wholesale prices. The details of how dynamic pricing and demand response should participate in the wholesale market are the subject of working groups established by the CAISO in conjunction with the CPUC and CEC. Also, the Commission is addressing the integration of demand response into the CAISO's MRTU market in R.07-01-041, so we will not address this issue in any detail in this decision.
However, given the Commission's desire to better align retail rates with the wholesale market, we will adopt following general rate design guidance:
· The utilities should bid demand reductions due to dynamic pricing into the CAISO's day-ahead market.
5.2. Critical Peak Pricing
CPP is a dynamic rate that includes a short-term price increase to a pre-determined level to reflect real-time system conditions. Although CPP is intended to reflect real-time system conditions, the parameters of the rate design are all set administratively and are indirectly tied to wholesale market conditions. Important parameters include the level of the critical peak price, the choice of trigger for a critical peak event, the number of events per year, and the length of events when they are triggered.
This section addresses each of the key CPP rate design parameters and provides rate design guidance for PG&E's future CPP rate design proposals. The discussion relies on comments filed by parties in response to questions and draft proposals posed in prior rulings and comments filed by parties following the CPP workshop held on March 7, 2008.
The critical peak price is the predefined dollar per kWh energy charge that a customer pays for energy used during the critical peak period.
Parties' Comments
Parties generally agree that the critical peak price should represent the marginal cost of capacity used to meet peak energy needs plus the marginal cost of energy during the critical peak period. Most parties also agree that the annualized cost of a new combustion turbine is an appropriate proxy for the marginal capacity cost. However, at the workshops and in comments several parties strongly recommend against litigating the marginal cost of capacity in this proceeding. For example, SDG&E states that although most parties agree that a new natural gas-fired combustion turbine should be used as a proxy for the generation marginal capacity cost, there is little consensus regarding whether or how energy profits should be netted against the capacity cost. Therefore, SDG&E recommends addressing the marginal capacity cost in each utility's separate rate design proceeding.96
BOMA, however, is not convinced that a new combustion turbine should be used to determine marginal generation capacity cost. BOMA recommends that the Commission investigate PG&E's actual capacity costs to determine if a combustion turbine is appropriate.97
DRA notes that cost studies typically use a combustion turbine as a proxy and allocate the entire combustion turbine cost to the critical peak hours. DRA suggests that analysis of actual utility cost data might show that utilities pay more for capacity than the combustion turbine proxy might indicate, and since a combustion turbine would be dispatched during non-CPP hours, a different cost allocation method could be appropriate.98
The CAISO is in the process of developing a scarcity pricing proposal that would apply during reserve shortage conditions. TURN suggests that the CAISO's scarcity pricing would be the most logical basis for a CPP rate because it would incorporate the reliability value that is not otherwise included in wholesale energy prices.99 DRA similarly notes that once the CAISO implements scarcity pricing, the unscaled scarcity price could be added to the pre-established CPP rate. Thereby the CPP price would be variable rather than static.100
At the workshops, parties discussed whether a centralized capacity market or bulletin board, if established in the future, would be useful for deriving CPP prices. PG&E is uncertain and recommends deferring consideration of such proposals.101
Discussion
There is general agreement that the critical peak price should represent the marginal cost of capacity used to meet peak energy needs plus the marginal cost of energy during the critical peak period. We adopt this principle as part of the rate design guidance.
We generally agree that the cost of a new combustion turbine is a reasonable proxy for the long-run marginal cost of capacity. However, BOMA suggested looking at PG&E's actual capacity costs, and TURN and DRA suggested looking to the CAISO's scarcity pricing in the future. A centralized capacity market or bulletin board could also be sources of capacity costs in the future. We do not want, however, to rule out the use of other sources of information to set the critical peak price. As such, we recommend the cost of a new combustion as a reasonable proxy for the marginal capacity cost; however, if PG&E uses the price of a combustion turbine to set the critical peak price, it should explain why it did not use alternate methods including actual costs, CAISO scarcity prices (once adopted by the Federal Energy Regulatory Commission (FERC) and implemented by the CAISO), and centralized capacity market or bulletin board prices (if implemented in the future). Other parties will also have the opportunity to propose specific methodologies in specific rate design proceedings.
Based on the forgoing discussion we adopt the following rate design guidance:
· The critical peak price should represent the marginal cost of capacity used to meet peak energy needs plus the marginal cost of energy during the critical peak period.
· The utility should explain what it used as the basis for the marginal cost of capacity in its CPP rate and why the annualized cost of a new combustion turbine is a reasonable proxy for determining the marginal cost of capacity; however, alternative bases include actual utility costs, CAISO scarcity prices (if adopted by the FERC and implemented by the CAISO), and centralized capacity market or bulletin board prices (if implemented).
PG&E's Existing CPP Rate for Large Customers
PG&E's existing voluntary CPP rate for large C&I and agricultural customers, Schedule E-CPP, is a supplemental tariff that is applied in addition to a customer's otherwise applicable TOU rate, so we will provide a summary of PG&E's TOU rates.
PG&E's TOU rates for large customers all include summer demand charges that are applied to a customer's maximum kilowatt demand during each summer month. The maximum kilowatt demand is determined by identifying the 15-minute interval during the month in which the customer's demand was at its highest. The TOU rates that are typically used by C&I customers with demand greater than 500 kW and the large agricultural TOU rates include two summer generation demand charges-one applied to the highest demand during the summer peak periods each month, and the other applied to the highest demand during the summer partial peak periods each month.
A customer on the E-CPP rate pays all of the charges under the customer's otherwise applicable TOU rate, and receives CPP charges and credits. The E-CPP charges consist of dollar per kilowatt-hour charges that apply to usage during the on-peak period on CPP days. 102 These charges are in addition to the TOU on-peak rates. The E-CPP credits consist of dollar per kilowatt-hour discounts that apply to energy use during on-peak and partial-peak TOU periods on summer non-CPP days.
The net effect of combining the TOU rate and the CPP rate is that the customer pays higher peak energy charges on CPP days, pays the full generation demand charge under the otherwise applicable TOU rate, and receives reduced peak and partial peak energy charges on non-CPP days.
SCE's and SDG&E's CPP Rate for Large Customers
SCE offers two CPP options for large customers. One offsets the higher CPP rate with lower energy rates during summer peak and partial peak periods during non-CPP days. The other options eliminates the generation demand charge.
SDG&E's CPP rate eliminates the generation demand charge. However, a customer can opt to pay a dollar per kilowatt capacity reservation charge for some of its demand.
PG&E's Existing CPP Rate for Small Commercial and Residential Customers
PG&E offers voluntary CPP rates to small commercial and residential customers who have received AMI meters- E-CSMART and E-RSMART, respectively. Like the large customer CPP rate, the small commercial and residential CPP rates are supplemental tariffs that are applied in addition to a customer's otherwise applicable rate. The otherwise applicable rate could be a TOU rate or a non-time-differentiated rate.
The design of the small commercial and residential CPP rates differs from the large customer CPP rate in several ways. First, the CPP period is shorter under the small commercial and residential CPP rate-four hours rather than six hours. Second, the CPP credit applies to all usage during the summer that is not during CPP events, rather than only applying to summer partial peak and peak usage. Third, customers receive an additional credit, referred to as a "participation credit," applied to all summer usage.103
Alternative CPP Rate Designs Analyzed
The January 23, 2008 Ruling directed PG&E to prepare an analysis of three different rate designs for large customers and present the results of the analysis at the March 7, 2008 workshop. The first rate design was the current tariff which is designed based on 12 CPP calls per summer, includes two-tiered CPP charges roughly equal to between $0.50 and $0.65 per kWh, and provides a roughly $0.03 per kWh credit on-peak usage during non-CPP days. The second and third rate designs were based on 15 CPP calls per summer and included a single-tiered CPP charge of $0.75 per kWh. In the second rate design 80% to 90% of the offsetting rate discount was applied to the on-peak generation demand charges with the balance applied to on-peak energy charges. In the third rate design all of the credits were applied to the demand charges.104 PG&E was asked to calculate the bill impact of the three rate designs on customers with typical load shapes. PG&E was further directed to calculate the bill impact assuming each customer dropped load during CPP events by 10%, 20%, and 30%.
Parties' Comments
In post-workshop comments, CLECA suggests that the Commission should further consider which charges should be most appropriately reduced in the CPP rate design (energy charges, demand charges, or both) and in which time periods (on-peak, partial peak, or off-peak). CLECA recommends that in addition to the rate proposals presented by PG&E, the Commission could consider a CPP rate similar to that discussed in a recent Brattle Group study of dynamic rates which was presented as part of the DRRC's Rates Project. The Brattle Group's CPP rate had no demand charges and reduced energy charges during non-CPP peak hours and partial peak hours to offset the increased revenues from the CPP periods.105
DRA points out the inconsistency in rate designs that fully reflect the cost of a combustion turbine in the CPP price but do not eliminate the coincident demand charges, which are also intended to recover the cost of capacity.106
At the March 7, 2008 CPP workshop and in subsequent comments, several parties noted that according to PG&E's analysis, CPP resulted in relatively modest annual bill decreases, even with significant demand reductions during CPP periods. However, CPP could result in significant month-to-month bill volatility if a large number of CPP events fall in one month but few events fall in another month.
According to PG&E, a customer's July bill could be 50% higher than the customer's June bill if most of the CPP events occur in July. Furthermore, PG&E warns that CPP is inherently unpredictable, so predictions of customer bill impacts will be unreliable. PG&E is also concerned that CPP complicates the utility's revenue requirement recovery since CPP could increase balancing account volatility.
PG&E recommends that if the Commission wants to modify the existing CPP rate, then PG&E would propose to implement the second rate design presented at the workshop which is similar to the rate PG&E had proposed in A.05-01-016 et al. as part of a settlement proposal.107
Discussion
CPP rates should include TOU pricing during non-CPP periods as a basic design element. PG&E's small commercial and residential CPP rates do not require that the customer enroll in a TOU rate, although that is an option the customer may choose. We believe that like the large customer CPP rate, the small commercial and residential CPP rates should build upon TOU rates. Therefore, we will require PG&E to propose revisions to its CPP rates and require that a CPP customer also enroll in TOU.
Since the critical peak price is intended to reflect the cost of capacity needed to meet the peak, we agree with DRA that also charging significant summer on-peak and partial-peak demand charges is duplicative. Therefore, we conclude that CPP rates should not also have summer generation demand charges. This is the approach taken by SDG&E and one of SCE's CPP rate options. This is slightly different from the rates that PG&E presented at the CPP workshop, which did not entirely eliminate the generation demand charges. If the generation demand charge is reduced to zero or the rate does not include a summer generation demand charge, then PG&E should apply any additional rate discount to all summer usage during non-CPP periods.
As PG&E notes, a CPP rate can result in additional month-to-month bill volatility if more CPP events are called in some summer months than in others. We believe this result is consistent with the purpose of CPP. As a form of dynamic pricing, CPP is intended to reflect market conditions that change from day to day. It would be a reasonable outcome if a customer pays a higher bill during a month during which market conditions are stressed and a large number of CPP events occur. CPP gives customers an opportunity to avoid high costs during high cost periods, unlike a non-time-variant or TOU rate that allocates high costs across other time periods.
Therefore, we adopt the following rate design guidance:
· Critical peak pricing rates should include a critical peak price during critical peak periods and time-of-use rates during non-critical periods.
· Since the critical peak price is intended to reflect the marginal cost of generation that is needed to meet peak period usage, CPP rates should not also have summer generation demand charges.
5.2.2. Critical Peak Events-How Many Times per Year and When Are Events Called
PG&E's large customer CPP rate is designed to be called 12 times per summer. PG&E's small commercial and residential CPP rates are designed to be called 15 times per summer. PG&E's decision to call CPP events is primarily based on a day-ahead temperature forecast. PG&E intends to call the design basis number of events each year, irrespective of system conditions, so PG&E adjusts the temperature threshold up and down as necessary. If there are few hot days PG&E will lower the temperature threshold, which means CPP events are called on cooler days. If there are many hot days PG&E will raise the temperature threshold. PG&E may also call events due to CAISO alerts or high forecasted wholesale prices.
SCE's large customer CPP rate is similar to PG&E's. The rate is designed assuming it will be called 12 times per summer. SCE will call events due to high system peak demand and/or low generation reserves, system constraints, high wholesale market prices, special alerts issued by CAISO, or high temperatures. Like PG&E, SCE will adjust the temperature threshold up or down to achieve the CPP program design basis of 12 CPP events per summer season.
SDG&E's large customer CPP rate takes a different approach. SDG&E's rate is designed assuming that it will be called nine times per summer. However, the minimum number of calls is zero and the maximum is 18. SDG&E's decision to call events will be based on forecasted temperature, system load, and extreme system conditions such as a CAISO alert. SDG&E will not adjust the triggers in order to call the events a predetermined number of times each year. SDG&E will only call events when necessary.
Parties' Comments
CLECA believes that it will be easier for customers to accept CPP events if they are tied to clear instances when electric supplies are tight, such as on hot days. If instead events are called by the utility to stabilize revenues and called on relatively cool days, customers are less likely to accept the CPP rates. Therefore, CLECA recommends providing some flexibility in the number of events called.
CLECA also points out that the supply-demand balance can be tight at times other than summer on-peak periods. Therefore, CLECA recommends allowing CPP events to be called during other times of day or year with the appropriate customer education.
CLECA suggests that additional analysis be performed to determine the level of revenue volatility associated with a divergence in the number of events called. Parties may then be able to agree on an acceptable level of volatility in a collaborative process.108
PG&E supports pre-determined and pre-approved criteria that could be based on forecasted demand, forecasted temperature, emergency situations, higher market prices, or other criteria. However, PG&E believes the utility should retain some discretion.
PG&E notes that calling a variable number of CPP events each year would result in a significant revenue under-collection during years when few events are called and significant revenue over-collections during years when an above-average number of events are called. PG&E recommends that the Commission consider utility revenue and customer bill impacts of using a variable number of CPP events. PG&E argues that it is not possible for the utility to collect the revenue requirement on an annual basis if there are a variable number of events each year.
PG&E believes restricting CPP events to summer weekday afternoons strikes a reasonable balance between giving customers an understanding of when events will be called and covering the periods when demand is most likely to be at peak levels and generation shortfalls are most likely to occur.109
SCE states that dynamic pricing events could be triggered by temperature, forecasted system load, or a wholesale market heat rate. SDG&E adds system emergencies such as fires to the list of potential triggers, but indicates that the trigger should be appropriate for the type of program.110
TURN argues CPP events should be called when needed, which could be on days other than summer weekdays. However, TURN notes that too many calls outside of summer weekdays could threaten customer acceptance. TURN suggests that existing revenue balancing accounts would allow for a variable number of events each year.111
Discussion
CPP is intended to reflect real-time system conditions, and system conditions vary from one year to the next. Therefore, we agree with the customer representatives that CPP should allow for a variable number of events each year, like SDG&E's CPP rate, rather than a fixed number of events, as is currently the case for PG&E and SCE. We agree with TURN that existing revenue balancing accounts should be sufficient to handle any year-to-year fluctuations.
If PG&E disagrees with this conclusion, then in PG&E's subsequent rate proposals the utility should provide a revenue analysis that shows the forecasted revenue over- and under-collection under plausible scenarios in which the number of events called varies from the design basis. PG&E should provide a comparison of the over- or under- collection due to a variable number of CPP calls to other common sources of over- and under- collections, such as changes in commodity prices and deviations in sales relative to forecast. PG&E should also compare the possible over- and under-collections to the revenue adjustments PG&E has requested and received in ERRA applications during the past three years.
We also agree with CLECA and TURN that CPP events should not be limited to summer weekday afternoons. While tight supply and demand conditions are most likely to occur on summer weekday afternoons, tight conditions or high wholesale energy prices can also occur on weekends and holidays, and potentially at other times of year. The increasing role of intermittent renewable resources like wind can also contribute to a tight supply-demand balance at any time of day, year-round. A study issued by the CAISO last year highlights how the addition of intermittent renewable resources can contribute to wholesale market volatility. The CAISO has identified demand response as a critical dependency that needs to be addressed to integrate renewables.112 Furthermore, transmission and generation outages and natural disasters affecting the electric system can occur at any time.
At the same time, we recognize that CPP should be easy to understand for customers. For now we conclude that an acceptable balance is to continue calling CPP events during afternoons during a defined hour range (e.g., 2:00 p.m. to 6:00 p.m.), but allow CPP events to be called any day of the week, year round. PG&E will need to appropriately educate customers that, although events are most likely to be called during non-holiday weekday afternoons, events could be called on other days depending on many circumstances. We believe it is appropriate to include more flexibility in the rate, especially given the increasing role of intermittent renewable generation sources in the system.
We adopt the following rate design guidance:
· The utilities should be able to call a variable number of events each year, and the rate should be designed based on the number of events that would be called during a typical year.
· The utilities should be able to call critical peak events any day of the week, year round.
As discussed in the prior section, the CPP rates offered by the California utilities are structured so that the CPP period occurs on summer weekday afternoons. The time of day and length of a CPP event is also generally predefined.
PG&E's current large customer CPP rate includes two critical peak periods: a moderate price period from noon to 3:00 p.m. followed by a high price period from 3:00 p.m. to 6:00 p.m. PG&E's small commercial CPP rate features a four-hour critical peak period from 2:00 p.m. to 6:00 p.m. The residential CPP rate includes a five-hour critical peak period from 2:00 p.m. to 7:00 p.m.
SCE's CPP rate has the same critical peak periods as PG&E's. SDG&E's large customer CPP rate includes a seven-hour critical peak period from 11:00 a.m. to 6:00 p.m.
Parties' Comments
PG&E has proposed switching the large customer critical peak period to a four-hour period from 2:00 p.m. to 6:00 p.m. to conform the rate to the small commercial CPP rate.
Several customer groups expressed concerns that the CPP period should not be too long. CLECA recommends relatively shorter CPP periods (four hours is better than seven hours) so that customers can use a wider variety of demand reduction strategies such as pre-cooling.113 114 CMTA states that a long CPP period could require some businesses to shut down for the day.115
TURN also expresses concern that demand reductions could erode if the critical peak period is too long.116
DRA recommends that the length of the CPP period should be based on the individual utility's load variations. Therefore, DRA posits that it is difficult to address the issue generically in this proceeding. DRA also suggests that in the future, with enabling technologies, variable length CPP periods could make sense.117
SDG&E justifies its seven hour CPP period by pointing to testimony it filed in A.05-01-017, which compared CPP period durations of four, five, six, and seven hours. SDG&E concluded that a seven hour period from 11:00 a.m. to 6:00 p.m. was superior to a shorter period because it includes the greatest number of high load hours, it is much less likely to shift the peak load outside of the CPP hours, and it will minimize customer confusion by aligning with the TOU on-peak period.118
Discussion
In D.05-04-053, the Commission directed the utilities to explore narrowing the current peak period to cover the hours of 2:00 p.m. to 6:00 p.m..119 PG&E's proposed new CPP rate includes a four-hour event period from 2:00 p.m. to 6:00 p.m.., which is a reasonable approach. However, as SDG&E points out, different CPP periods may be appropriate in different circumstances.
Ultimately setting the length of the critical peak period requires reasonable judgment, taking into account the historical and expected system conditions in a utility's service territory. It is possible that system conditions could change over time indicating a shorter or longer CPP period is reasonable. Therefore, we think flexibility is important, and thus, we will not adopt any general rate design guidance related to the length of the CPP period. The length of the CPP period should be determined in specific rate design proceedings.
5.3. Real-Time Pricing
As discussed earlier, RTP is the best rate to promote economic efficiency and equity between customers. RTP can also connect retail rates with California's greenhouse gas policies if wholesale energy prices reflect the cost of greenhouse gas emissions. For example, when wholesale energy prices are being set by inefficient generation sources with high greenhouse gas emissions, RTP could reflect the cost of greenhouse gas emissions and discourage retail customers from consuming polluting power. Conversely, if other time periods are dominated by non-emitting resources such as nuclear, water, and wind, RTP could signal to customers that the supply of power is clean.
Development of RTP rates for the California IOUs will be a milestone achievement. However, parties generally agreed that it is premature to address the details of RTP. Thus, the discussion of RTP in this decision is abbreviated.
The January 23, 2008 Ruling recommended that RTP should be based on the CAISO's day-ahead hourly market prices. The ruling also recommended that the prices should be aggregated across PG&E's service territory. As the market develops, the Commission could consider more granular pricing based on nodal prices.
Parties agreed with this approach. TURN additionally suggested that customers could be offered a voluntary RTP rate based on day-of prices since some limited number of customers may be willing to respond to day-of prices.120
DRA and PG&E emphasized uncertainties around how the CAISO's day-ahead prices could translate to rates in a way that aligns with PG&E's actual costs and collects the revenue requirement.
DRA believes that equating RTP directly with the day-ahead hourly market prices will result in rates that are too low because the rates would not account for the costs of forward contracting.121 Day-ahead hourly market prices may need to be scaled up or down for two purposes: first, to add capacity costs; and second, to reconcile the day-ahead hourly prices with the revenue requirement. DRA comments that reconciling the day-ahead hourly prices with the revenue requirement will be challenging since the day-ahead prices are not known in advance.122 PG&E is unclear how energy charges should be indexed to day-ahead energy prices and recommends holding an additional workshop.123
Developing the details of how to index the CAISO's day-ahead hourly price to the retail rate should wait until the MRTU day-ahead market is operating and can be assessed. The utilities, other parties, and the Commission will need to carefully consider how to reconcile RTP with the revenue requirement.
In this decision, we will adopt the following general guidance:
· The energy charge should be indexed to the CAISO's day-ahead hourly market prices.
· At least initially, RTP should be based on day-ahead hourly market prices that have been aggregated across PG&E's service territory. As the market develops, locational prices should be considered.
5.3.2. Do Energy Prices Reflect the Entire Cost of Generation?
Parties generally agree that in today's California market some generation costs are not reflected in wholesale energy prices. Some suggest that because resource adequacy requirements give generators an opportunity to sign contracts for capacity, generators do not need to cover all of their costs through the sale of energy. Parties also point to out-of-market purchases made by the CAISO. However, the amount of generation cost that is not reflected in energy prices is unclear. Several parties recommend that the Commission carefully examine this issue.124
BOMA supports investigating the extent to which generation marginal capacity costs are imbedded in wholesale energy prices by examining PG&E's capacity payments. BOMA recommends conducting the investigation in this proceeding.125 CLECA believes that the level of capacity costs not reflected in energy prices is "far from zero" for most generators. CLECA expects that unless California moves to an energy-only market, most generators will recover some of their costs in non-energy payments. According to CLECA, if the Commission decides to pursue a centralized capacity market, generators will receive a large amount of revenue through capacity payments. However, CLECA doubts there will ever be general agreement on how to estimate the level of capacity costs reflected in energy prices. CLECA believes this issue should continue to be litigated in the Phase 2 of utility general rate cases.126
We agree that this issue requires further consideration and believe that a proceeding considering a specific RTP proposal is the appropriate forum. Accordingly, we adopt the following guidance:
· The Commission should determine the degree to which the marginal cost of capacity is not incorporated into the CAISO's day-ahead hourly market prices.
70 August 22, 2007 Ruling, Attachment A, p. 1.
71 BOMA Post-Workshop Comments, December 11, 2007, pp. 2-5.
72 See D.82-12-113 (10 CPUC2d 512), D.83-12-065 (13 CPUC2d 619), D.83-12-068 (14 CPUC2d 15), and D.84-12-068 (16 CPUC2d 721).
73 In the future if rates include the marginal cost of greenhouse gas emissions, rate design can help the state achieve its greenhouse gas reduction goals.
74 Public Utilities Code Section 739(c) (1) states, "The commission shall require that every electrical and gas corporation file a schedule of rates and charges providing baseline rates. The baseline rates shall apply to the first or lowest block of an increasing block rate structure which shall be the baseline quantity. In establishing these rates, the commission shall avoid excessive rate increases for residential customers, and shall establish an appropriate gradual differential between the rates for the respective blocks of usage." Section 739 relates to the establishment of baseline quantities and baseline rates. For residential electric customers other than "all-electric residential customers," as defined, the baseline quantity means 50 to 60 percent of average residential consumption taking into account climatic and seasonal variations.
75 Public Utilities Code Section 739.7 states, in relevant part, "In establishing residential rates, the commission shall retain an appropriate inverted rate structure."
76 An "inverted rate structure" is a rate in which predetermined prices increase as a function of cumulative customer electricity usage within a predetermined time frame (usually monthly).
77 See The Brattle Group, "Illustrating the Impact of Dynamic Pricing Rates in California," January 22, 2008, presentation prepared for DRRC Rates Project webcast. The other three ratemaking objectives were economic efficiency, choice, and simplicity.
78 PG&E Opening Comments, October 5, 2007, Attachment, pp. 13-15.
79 PG&E Post-Workshop Comments, December 11, 2007, p. 6.
80 SDG&E Opening Comments, October 5, 2007, Attachment, p. 7.
81 CLECA Post-Workshop Comments, December 11, 2007, pp. 5-6; CLECA Comments, February 28, 2008, pp. 3-5.
82 EPUC Comments, February 28, 2008, p. 3.
83 The Brattle Group, "Rethinking Rate Design," Presentation at DRRC Dynamic Pricing Issues Workshop, September 7, 2007.
84 CLECA Comments, February 28, 2008, p. 6; CMTA Comments, February 28, 2008, pp. 3-4; PG&E Post-Workshop Comments, December 11, 2007, pp. 4-5; TURN Comments, February 28, 2008, p. 4.
85 DRA Post-Workshop Comments, December 11, 2007, pp. 10-11.
86 CMTA/EPUC Post-Workshop Comments, December 11, 2007, p. 6; CMTA Comments, February 28, 2008, p. 4.
87 KMEP CPP Comments, March 21, 2008, pp. 3-4.
88 SDG&E Post-Workshop Comments, December 11, 2007, pp. 5-6. SDG&E's CPP rate with a capacity reservation charge was approved in D.08-02-034.
89 BOMA Comments, February 28, 2008, p. 3.
90 CLECA Comments, February 28, 2008, p. 4.
91 EPUC Comments, February 28, 2008, p. 3.
92 EPUC CPP Comments, March 21, 2008, pp. 6-7.
93 PG&E Comments, February 28, 2008, pp. 21-22.
94 DRA Opening Comments, October 5, 2007, pp. 18-19.
95 TURN Opening Comments, October 5, 2007, p. 24.
96 SDG&E Comments, February 28, 2008, p. 2.
97 BOMA Comments, February 28, 2008, p. 5.
98 DRA Opening Comments, October 5, 2007, pp. 18, 25-26.
99 TURN Opening Comments, October 5, 2007, p. 30.
100 DRA Comments, February 28, 2008, p. 4.
101 PG&E Comments, February 28, 2008, p. 22.
102 PG&E's CPP energy charges are further broken down into a "moderate-price" charge that is added to the TOU on-peak energy charge from noon to 3:00 p.m. and a "high-price" charge that is added to the TOU on-peak energy charge from 3:00 p.m. to 6:00 p.m.
103 The participation credit under the residential E-RSMART only applies to usage in Tiers 3, 4, and 5.
104 PG&E CPP Comments, March 21, 2008, Attachment.
105 CLECA CPP Comments, March 21, 2008, p. 2.
106 DRA Opening Comments, October 5, 2007, pp. 26-27.
107 PG&E CPP Comments, March 21, 2008.
108 CLECA Opening Comments, October 5, 2007, p. 28; CLECA CPP Comments, March 21, 2008, pp. 2-3.
109 PG&E Comments, February 28, 2008, pp. 21-22, 25; PG&E Opening Comments, October 5, 2007, Attachment, p. 19.
110 SCE Opening Comments, October 5, 2007, p. 20; SDG&E Opening Comments, October 5, 2007, p. 8.
111 TURN Opening Comments, October 5, 2007, pp. 30-31.
112 CAISO, "Integration of Renewable Resources," November 2007; CAISO, "2008-2013 Integration of Renewable Resources Program High-Level Program Plan," http://www.caiso.com/1fac/1facbc35316e0.pdf.
113 "Pre-cooling" means running the air conditioning earlier in the day, prior to a critical peak period, in order avoid running air conditioning during a critical peak period while maintaining a comfortable temperature.
114 CLECA Comments, February 28, 2008, p. 3.
115 CMTA Opening Comments, October 5, 2007, p. 13.
116 TURN Opening Comments, October 5, 2007, p. 30.
117 DRA Opening Comments, October 5, 2007, p. 26.
118 SDG&E CPP Workshop Comments, March 21, 2008, pp. 2-3.
119 D.05-04-053, OP 7.
120 TURN Post-Workshop Comments, December 11, 2007, p. 8.
121 DRA Post-Workshop Comments, December 11, 2007, p. 6.
122 DRA Comments, February 28, 2008, p. 4.
123 PG&E Comments, February 28, 2008, p. 22.
124 For example, BOMA Post-Workshop Comments, December 11, 2007, pp. 5-6 and CMTA/EPUC Post Workshop Comments, p. 2.
125 BOMA Comments, February 28, 2008, pp. 4-5.
126 CLECA Comments, February 28, 2008, pp. 5-6.
