2. The History of Residential Rate Design in California
Several key statutes have guided the Commission in setting the current rate design policy for electricity customers.
2.1. The Warren-Miller Energy Lifeline Act of 1976
The Warren-Miller Energy Lifeline Act of 1976 required the Commission to designate a baseline quantity of gas and electricity necessary to supply a significant portion of the reasonable energy needs of the average residential customer at rates below average cost.1 In setting those quantities, the Commission was directed to take into account the difference in energy needs between all-electric residences and those with both gas and electric service and to take into account differences in energy use by climatic zone and season. Initial baseline quantities were set at 50 to 60 percent of the average residential customer's consumption in similar climatic zones. Additionally, the Commission was directed to provide higher energy allocations for residential customers with special medical needs (medical baseline) who are dependent upon life-support equipment. The goals of the Warren-Miller Act were two-fold: ensuring an equitable rate and encouraging electricity conservation. The result was a two or three-tier rate structure, with varying degrees of tier differentials that lasted until 2001.
2.2. Assembly Bill 1890 and Electricity Market Restructuring (1996)
In 1996, the Legislature passed Assembly Bill (AB) 1890 which governed the process of California's establishment of competitive markets, electricity restructuring and the introduction of wholesale electricity markets in California. AB 1890 froze retail rates for each investor-owned utility's (IOU's) customers until the electric utility recovered its stranded costs associated with above market cost obligations incurred by the utility in prior years.2 The legislation also allowed customers to take service from a third party Electric Service Provider, but required those customers to continue to pay their share of stranded costs. San Diego Gas & Electric (SDG&E) was the first utility to exit the rate freeze, which allowed SDG&E to pass through their electricity costs from the wholesale market. As the wholesale market prices spiked upwards during the electricity crisis, SDG&E's customers were the first to suffer high bills due to this
pass-through. The Legislature subsequently re-imposed a rate cap for SDG&E's customers and AB 1890 was later suspended, in part, by AB 1X (AB1X) and Commission actions to stem the electricity crisis.
2.3. Electricity Crisis and Assembly Bill 1X
After prices for electricity skyrocketed during 2000 and 2001, the Legislature enacted AB 1X. In response to the failing creditworthiness of Pacific Gas and Electric (PG&E) and Southern California Edison Company (SCE), AB 1X enabled the Department of Water Resources (DWR) to enter into long-term electricity contracts with generators to ensure that electrical service was maintained for PG&E and SCE customers. In addition, AB 1X directed that the Commission could not increase residential electricity rates on usage of up to
130 percent of baseline until DWR "has recovered the costs of power it has procured for" electricity customers.3 In response to this directive, the Commission adopted a five-tiered, increasing block rate structure for residential customers, with rates for Tiers 1 and 2 capped at 2001 levels and three tiers for usage above 130 percent of baseline that were uncapped.
2.4. Senate Bill 695
In 2009, the Legislature passed Senate Bill (SB) 695 which set the terms for future adjustments to the baseline calculation, the ability of the Commission to increase rates for Tiers 1 and 2, and the timeline for the ability of the Commission to order IOUs to transition residential customers onto time-variant rate
designs.4, 5 SB 695 allowed the Commission to increase rates for Tiers 1 and 2 "by the annual percentage change in the Consumer Price Index from the prior year plus 1 percent, but not less than 3 percent and not more than 5 percent per year."6 In addition, SB 695 set a schedule for when the Commission can default residential customers onto time-variant rates. Specifically, residential customers may, "in a manner consistent with the other provisions of this part,"7 be transitioned to:
· default time-variant pricing, with 1 year of bill protection, beginning in 2013;
· default time-variant pricing without bill protection, beginning in 2014; and
· Default real-time pricing in 2020.8
Finally, SB 695 preserves the ability of a customer to opt-out of a default
time-variant rate upon expiration of their bill protection period.
2.5. Commission Policies Impacting Rate Design
In addition to the policies and actions noted above on rate design, for the past decade the Commission and the State have developed policies with a focus towards two goals: 1) enable conservation and efficiency on the customer side and 2) increase the reliance on non-fossil based generation to reduce overall Greenhouse Gas Emissions.
The Commission has long supported utility investment to support energy efficiency and demand response programs to help reduce overall consumption, reduce or shift peak consumption, and help customers reduce total bills. Since 2001, the Commission, both on its own motion and at the direction of the Legislature, reinstituted a series of policies designed to promote energy efficiency and conservation that had been allowed to lapse under AB 1890. In the early 2000s, the Commission authorized utilities to greatly expand development and implementation of programs to encourage energy efficiency. In 2002, the Commission began authorizing utilities to develop demand response programs to curtail peak consumption. Also in 2002, the Commission began to develop policies that resulted in the deployment of Advanced Metering Infrastructure (AMI) throughout the service territories of PG&E, SCE and SDG&E. Fundamentally, these programs were predicated on reducing customer consumption in total and during peak hours. More recently, with the installation of AMI and availability of hourly usage data, the Commission directed the utilities to provide customers with greater access to their usage information, and allow customers to share their information with third parties who may offer services to reduce their overall bills.9
In addition to these customer demand-side policies, the Legislature passed SB 1078 and SB 107, which set a requirement for the utilities to procure 20 percent of their generation from renewable resources by 2010. The Legislature later expanded this requirement to 33 percent by 2020. These requirements resulted in a move away from traditional sources of electricity generation to more renewable sources, such as wind and solar. Additionally, the Commission and the Legislature have supported the increased usage of distributed solar by end-use customers through the California Solar Initiative and the development of Net Energy Metering (NEM) policies.
The state has made it a policy for utilities to have 33 percent of their generation mix come from renewable sources of electricity by 2020. Indeed, as part of this move to 33 percent, Governor Brown earlier this year called for
12,000 megawatts (MW) of distributed generation to be developed by 2020. Additionally, AB 32 provided that California must reduce greenhouse gas emissions to 1990 levels by 2020. All of these environmental goals have an impact on utility operations, utility costs, how the utility recovers those costs, and, ultimately, the rate itself. As the state moves to a cleaner resource mix, rates must be established that allow the utility to recover the costs related to these programs in an equitable manner.
Underpinning this increased investment in distributed generation, utilities are also beginning to invest in and install technologies to modernize the distribution grid. Pursuant to SB 17, the Commission was directed to set requirements for utility Smart Grid Deployment Plans by July 1, 2010.10 These "Smart Grid" investments will support the growth in distributed generation technologies, increased penetration of electric vehicles, and growth in third party offerings for demand response, energy efficiency and other energy management services by providing the utility with greater visibility into the distribution grid in real-time and near-real-time. These technologies will allow the utility to both better plan for future customer needs and what impacts are occurring on the distribution grid from customer investments in advanced technologies.
2.6. Existing Commission Positions on Residential Rate Design
For more than two decades, the Commission's two low income assistance programs, the Energy Savings Assistance Program (formerly known as Low Income Energy Efficiency or LIEE) and the CARE Program, provided and continue to provide significant electricity bill relief that go toward reducing the financial hardships of low income families across California. Additionally, as affirmed in the Public Utilities Code (Pub. Util. Code § 382(b)), this Commission is fully committed to ensuring that low-income customers are not jeopardized or overburdened by monthly energy expenditures. The examination as a result of this rulemaking will not change course from Pub. Util. Code § 382(b), but rather intends to ensure for the foreseeable future that rates are both equitable and affordable while meeting the Commission's rates objectives for the residential sector and more specifically for the low-income customer base.
In addition to our commitment to protect low-income customers, this Commission, beginning with the Energy Action Plan (EAP) in 2003,11 has increased its effort to transition customers onto time-variant and dynamic rates in an effort to reduce peak demand. The Energy Action Plan II (EAP II), adopted in October 2005, went further, noting that "[w]ith the implementation of
well-designed dynamic pricing tariffs and demand response programs for all customer classes, California can lower consumer costs and increase electricity system reliability" and called for making "dynamic pricing tariffs available for all customers."12 Additionally, the EAP II identified the need to "[e]ducate Californians about the time sensitivity of energy use and the ways to take advantage of dynamic pricing tariffs and other demand response programs," as well as to "create more transparency in consumer electricity rates, adopt rates based on clear cost-causation principles, and identify steps to reduce electricity costs."13 Finally, in 2008, the Commission approved an update to the EAP II, which noted "most consumers are currently on tariffs that bear no resemblance to the actual cost of providing their electricity" and that the existing tiered rate structure has "no time dimension to their prices that would help encourage reducing usage at peak times when electricity is the most expensive."14
In response to these policy directions, the Commission issued D.08-07-045 in 2008.15 D.08-07-045 adopted a Rate Design Guidance framework, as well as a timetable for offering time-variant and dynamic pricing rates to all customer classes in PG&E's service territory. The end result of this decision was the implementation of default CPP rates for PG&E's large and medium commercial and industrial customers, as well as a timetable for moving to RTP rates. The transition to time-variant rates for small commercial and residential customers was delayed pending additional investigation and, for residential customers, then-existing AB 1X statutory provisions. Importantly, D.08-07-045 adopted a set of guiding principles for the Commission and utilities to utilize in designing dynamic rates.16 These principles are:17
1. Rates should be based on marginal cost;
2. Rates should be based on cost-causation principles;
3. Rates should encourage conservation and reduce peak demand;
4. Rates should provide stability, simplicity and customer choice; and
5. Rates should encourage economically efficient
decision-making.
Even though the decision did not explicitly state that equity is a guiding principle, the decision did note "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.18
Since the adoption of D.08-07-045, all three electric utilities in California have transitioned large and medium commercial and industrial customers onto default CPP rates, with an opt-out to TOU available. The move to dynamic or time-variant rates for small commercial and residential customers, however, has taken a much slower path. The Commission approved a Peak Time Rebate (PTR) program for SCE and SDG&E as consistent with AB 1X and SB 695 limitations, since PTR does not raise electricity costs, but, rather, provides customers with a rebate for reducing load during "peak events." However, the Commission has not yet approved PTR as a default rate for PG&E. In addition, all three IOUs have voluntary TOU and CPP residential rates. The IOU CPP programs provide participating customers with an incentive to shift usage to non-peak hours, and charge higher rates during peak hours on a CPP event day. CPP event days are called 24 hours in advance, with customer notification provided through several communication channels. Customers can save money if they reduce consumption during peak hours on event days or shift consumption to lower priced hours of the day. Customers enrolled in CPP could also see their bills increase if they do not reduce consumption during the higher priced CPP hours.
1 See P.U. Code 739, et seq.
2 Decision (D.) 95-12-063 (as modified by D.96-01-009) required the IOUs to divest at least half of their fossil generation facilities. The IOUs retained their hydro and nuclear generation facilities.
3 AB 1X Sec. 80110. AB 1X also suspended Direct Access.
4 SB 695 also revised the manner in which rates for the California Alternate Rates for Energy (CARE) program are determined, and allowed a small percentage of industrial and commercial customers to take service from an Electricity Service Provider.
5 SB 695, codified at Pub. Util. Code § 745(a)(2), defines a time-variant rate as including
"time-of-use rates, critical peak pricing, and real-time pricing, but does not include programs that provide customers with discounts from standard tariff rates as an incentive to reduce consumption at certain times, including peak time rebates." Generally, time-variant rates refer to Time of Use (TOU) rates, due to their predictability of price and timing; whereas rates, such as Critical Peak Pricing (CPP) and Real Time Pricing (RTP), that may change on short notice are referred to as "dynamic" rates.
6 Pub. Util. Code § 739.9.
7 Pub. Util. Code § 745(d).
8 The bill protection schedule is based on the customer having at least one year of advanced meter data.
9 See D.11-07-056 (issued July 28, 2011).
10 D.10-06-047.
11 See Energy Action Plan, adopted May 8, 2003. The Energy Action Plan was approved by the Commission, the California Energy Commission and the Consumer Power and Conservation Financing Authority.
12 EAP II at 6-7.
13 EAP II at 7, 12. The EAP II was approved by the Commission and the California Energy Commission.
14 Energy Action Plan, 2008 Update at 11. The 2008 Update also noted that existing procurement and resource adequacy policies may be keeping wholesale peak prices artificially low and limiting price volatility which would encourage reducing peak consumption.
15 Application of PG&E Company To Revise Its Electric Marginal Costs, Revenue Allocation, and Rate Design, D.08-07-045 (issued July 31, 2008).
16 See D.08-07-045, Attachment A.
17 D.08-07-045 at 41 and 42.
18 D.08-07-045 at 46.
