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Sunday, July 29, 2012

EV Rate Design

California SB 626 requires the CPUC, in consultation with the CEC, CARB, utilities, and the motor vehicle industry,  to develop infrastructure sufficient to overcome any barriers to the widespread deployment and use of plug-in and electric vehicles, and to adopt rules by July 1, 2011, on  infrastructure and policy upgrades necessary for the widespread use of plug-in hybrid and electric vehicles.

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Back to Electric Vehicle Index
1. Background

2. Acronyms/Definitions
3. Business Case
4. Benefits
5. Risks/Issues
6. Next Steps
7. Companies/Organizations
8. Links


The Grid Can Handle PEVs . . . But There Are Impacts Source: EPRI

1.Background
  • Electric transportation can reduce greenhouse gas emissions, improve local air quality, and reduce on oil, but consumers will not adopt electric vehicles without adequate charging infrastructure. There needs to be regulatory clarity to encourage the state's entrepreneurs and investors to develop charging solutions that will satisfy consumer needs and work harmoniously with the electric grid.

  • It is clear that electric vehicle charging could represent a new and substantial increase in load. In addition, if electric vehicle charging occurs during peak periods, electric vehicle charging could lead to greater use of lower efficiency and higher greenhouse gas emission peaking generating units. Electricity rates can provide electric vehicle owners a financial incentive to charge at some times rather than others, e.g., charge when the economic and environmental impacts on the grid are lowest.

  • The benefits of off-peak Electric Vehicle charging are manifold and accrue to the Electric Vehicle owners and non-Electric Vehicle owners alike. Off-peak charging places less strain on the distribution system, avoiding adverse impacts to the electric grid and reducing the need for costly infrastructure upgrades. Concentrating Electric Vehicle charging in off-peak periods will also dampen increases in energy procurement costs resulting from the addition of this new load: not only is energy more expensive during peak periods, but significant levels of on-peak charging could actually increase incremental procurement costs.

  • At the November 18, 2009 CPUC prehearing conference and in comments, parties requested the Commission address issues related to the provision of electric vehicle charging services by entities other than the electrical corporations currently regulated by the Commission as public utilities. Parties described the resolution of these issues as “critical” to bringing private investment to California for electric vehicle charging infrastructure and requested the Commission address these issues as soon as possible.

  • EV Rates Questions - What types of time variant rates should be offered to electric vehicle owners? What characteristics should electric vehicle rate designs have? How should residential electric vehicle rates be designed given the inverted-tier rate structure? For residential customers, should the utility offer whole house time-variant rates for electric vehicle owners, rates that only apply to electric vehicles, or both? What types of rates should apply to stand-alone commercial and public electric vehicle charging? What types of rates should apply when an electric customer offers electric vehicle charging services and has other electricity uses?

  • EV Metering Policy Questions - Metering could occur through the main meter in the residence, an on-car arrangement, through a separate revenue-grade meter serving a dedicated electric vehicle load or through a sub-meter. Separate metering could be important if the Commission implements special electric vehicle rates programs, Smart Grid integration, and other values to be gained through time differentiated tracking. Electric utilities will also need to consider the metering rules contained in the CARB’s Low Carbon Fuel Standard.

    Various meter ownership arrangements are also possible. The meter could be owned by the utility, the vehicle owners, or a third party.

  • Utility Cost Recovery Questions - Should utilities be permitted to make expenditures in residential, commercial and public charging infrastructure? How should a utility recover expenditures on charging infrastructure? Should utility costs be recovered directly from the users of the infrastructure or from the wider body of ratepayers? How should a utility recover costs of distribution system upgrades attributable to electric vehicles? Should utilities seek recovery of expenditures related to electric vehicles through general rate cases or are special applications necessary and appropriate?

2. Acronyms/Definitions
  1. Demand Charge - Electric power use is metered in two ways: on maximum kilowatt use during a given time period (i.e., kW demand typically measured in 15-minute or 30-minute intervals) and on total cumulative consumption in kilowatt hours (kWh). A customer's electric rate is set using a complex process of tracking cost of services and often seeking regulatory approvals.

    Ten 100-watt light bulbs burning for 1 hour consume 1,000 watt-hours or 1 kWh. Note that in both examples, the consumption is 1 kWh, however, look how differently the second situation impacts the utility from a demand perspective. The serving utility must now be prepared to provide ten times as much 'capacity' in response to the "demand" of the 10 light bulbs operating all at once.

    The general theory is that demand charges reflect the utilities' fixed costs of providing a given level of power availability to the customer, and energy charges reflect the variable portion of those costs as the customer actually uses that power availability. In the past, residential energy tariffs did not include a demand charge because most homes have a pretty similar demand profile and the meters capable of measuring both demand and consumption were too expensive to justify having one on every home. Now that smart meters that can record the power use during either a 15- or 30-minute time window, demand charges for residential use are a possibility.

    The peak demand used for billing purposes in any month can be:
    1. Time of Day: Dependent on the time of day (i.e., on-peak {usually during the day} and off-peak {usually at night time periods) and/or the day of the week (e.g., Monday through Friday and separately for weekends): The metering system tracks the highest usage anytime during the month under the appropriate time windows. These pricing schedules are generally referred to as Time of Use (TOU) rates.

    2. Seasonally Differentiated: For example, the demand charge might be higher during the summer than during the winter, or vice versa.

    3. Declining Blocks: This is where the demand charge up to a given level is at one price with the price declining above that level. For example, the demand charge might be $10 per kW up to 10,000 kW demand, and drop to $6 per kW for demands in excess of 10,000 kW.

    4. Interruptible Blocks: The demand charge depends upon whether the customer can reduce electrical demand to a given level if it is notified in advance by the utility. The price reduction often varies with the time of notice (i.e., the discount is higher if shorter notice is given). Some utilities also offer direct load control for air conditioning and water heating equipment, the utility itself can cycle this equipment on and off for brief periods.

    5. Ratchet: Certain rate designs incorporate minimum billing demands based upon historical peak demands. For example, if the peak demand last summer was 500 kW and the rate design has a 50% ratchet, the minimum billing demand would be 250kW (500 kW times 50%) for the following eleven months, regardless of whether the actual demands were lower.

    Some stakeholders have suggested that demand charges should be included in Electric Vehicle residential rates as an additional incentive to offpeak charging and to recover costs of upgrades to the distribution system needed to accommodate Electric Vehicle charging.

    Demand charges are not currently a component of residential rates. Instead, in the residential setting, capacity costs are recovered through volumetric charges. In the context of residential Electric Vehicle rates, a demand charge could be included as a rate component so that Electric Vehicle customers who place higher costs on the electric system by, for example, charging on-peak or at higher voltages, are assessed rates based on the maximum demand they impose on the distribution circuit.

    Some parties, including SCE, DRA, NRDC and Green Power Institute, stated that residential demand charges may not be necessary since time–of-use rates can accomplish capacity cost recovery. SCE also noted that costs associated with a particular customer class could be more easily recovered through a simple customer charge. Nevertheless, some of these same parties acknowledged that demand charges are a more precise tool for recovering demand-related costs.

    In contrast, SDG&E stated that increasing the time-of-use differentials could lead to the potential under recovery of the costs to serve a growing Electric Vehicle customer group. SDG&E suggests this argues for the need to introduce fixed and demand charge components to the Electric Vehicle rate structure. The CPUC was persuaded that adding demand charges to residential Electric Vehicle rates would be too great a change to residential rates at this time. Instead, we direct each utility to re-evaluate the feasibility and benefits of an Electric Vehicle residential demand charge in its next review of Electric Vehicle rates for 2013.

  2. Electric Vehicle Service Provider Rates in Residential Settings - An electric vehicle service providers might operate in a residential location. For example, an electric vehicle service provider may provide all the equipment required to charge an Electric Vehicle at a home together with a charging service, in which the electric vehicle service provider separately charges customers for the electricity used to charge their vehicle. In this case the electric vehicle service provider, not the homeowner, would be the utility’s customer.

    In July 2011, the CPUC found that in order to preserve equitable, cost of service treatment and maintain a level playing field between utilities and electric vehicle service providers, existing residential Electric Vehicle rates should apply to electric vehicle service providers operating in the residential setting. Electric vehicle service providers should only be eligible for residential rates designed to serve Electric Vehicle load and, therefore, would not be eligible for non-time-of-use general service rates in the residential context.


  3. Inter-Utility Electric Vehicle Residential Rates - In the August 20, 2009 OIR, the CPUC asked parties whether special arrangements were necessary for a residential customer to pay for electricity when charging an Electric Vehicle in another utility’s service territory. For example, should the utilities establish a single billing procedure to link all Electric Vehicle electric usage, regardless of the service territory within which the Electric Vehicle charging occurs, to a customer’s home utility.  In July 2011 the CPUC found  that it is premature for the Commission to direct the utilities to implement inter-utility billing and left open the possibility that further development of this concept may be useful in the future.

  4.  SB 626 (Kehoe) Electrical Infrastructure Plug-in Hybrid and Electric Vehicles - This law passed in 2009 requires the CPUC, in consultation with the CEC, CARB, utilities, and the motor vehicle industry, to to develop infrastructure sufficient to overcome any barriers to the widespread deployment and use of plug-in and electric vehicles, and to adopt rules by July 1, 2011, on specified matters, including infrastructure upgrades necessary for the widespread use of plug-in hybrid and electric vehicles.

  5. LEV - Low Emission Vehicle -

  6. MDU - Multi Dwelling Unit - In the MDU setting, the Electric Vehicle owner may not be the utility’s electric customer. Multiple Electric Vehicle owners may use the same charging
    equipment. Submetering at MDUs and workplaces requires additional evaluation to determine what protocols and policies are needed to support these options.

  7. PEV - Plug-in Electric Vehicle -

  8. NEV - Neighborhood Electric Vehicle - The U.S. Department of Transportation classifies low-speed electric vehicles as a NEV. Although federal regulations certify NEVs as “street legal,” NEVs are not required to have air bags and cannot travel on highways or freeways. NEVs are therefore restricted to roads with a 35 mile per hour speed limit or less.

  9. Whole House Rate - A residential single meter Electric Vehicle rate, while specifically designed for Electric Vehicle charging, is applied to a residence’s entire electricity usage. SCE’s and PG&E’s single meter Electric Vehicle rates are tiered, while SDG&E’s are not. All of the utilities’ single meter rates are optional (opt-in), meaning a residential customer must make a proactive voluntary decision to go onto the Electric Vehicle rate. The challenge of single meter Electric Vehicle rate design  is to structure a simpler, cost-based, time-of-use rate that avoids the disincentives for Electric Vehicle use associated with tiered rates but still recovers the incremental cost to serve Electric Vehicles.

    NRDC and the EVSP Coalition note that the existing single meter Electric Vehicle rates effectively place the customer into the upper tiers of the rate structure due to the increased electric usage resulting from the customer’s Electric Vehicle load. As a result, such rates subject Electric Vehicle load to what these parties describe as high vehicle mileage costs. While removing the tiers from the single meter rate would address this issue, NRDC also expressed concern that switching Electric Vehicle charging from a tiered single meter rate to a non-tiered single meter rate could eliminate the conservation signals provided by the tiers.
Residential Metering Options -
Service Planning / Installation Perspective Source: PG&E
Residential Metering Options -
Billing Perspective Source: PG&E

3. Business Case
  • The number of utilities offering EV tariffs has increased from eight a year before to 22 in July 2012, but that still represents just 6% of utilities nationwide, according to a new report from Northeast Group. And though a number of the utilities offering EV tariffs are located where you might expect – in California and Michigan – they actually crisscross the country, from Alaska to Georgia.

    Of the 22 utilities in 11 states that are offering EV tariffs, the report indicates:
    • Most have taken two main forms -- time-of-use (TOU) and flat rate plan
    • They are typically one-half the cost of standard electricity tariffs to recharge an EV

  • Each California IOU currently offers a residential PEV Time of Use (TOU) tariff. Each PEV TOU tariff is either for bundled household load and vehicle load, or segregated vehicle load. A vehicle load rate requires separate metering.
  • In June 2010, the CPUC approved new temporary experimental rates for plug-in electric vehicles for San Diego Gas and Electric Company (SDG&E) customers as part of the utility's Pricing and Technology Study.
    • The Study will be performed by SDG&E, in collaboration with ECOtality, Inc. and Nissan. The experimental rate schedules will begin January 1, 2011, and will remain in effect until November 30, 2012 (or until the completion of the Study). ECOtality was the recipient of a U.S. Department of Energy stimulus grant to fund the deployment of electric vehicles and charging systems in five U.S. cities, including San Diego. "The Study will help the state better understand the impacts of different rate structures on how and when customers charge electric vehicles," said CPUC President Michael R. Peevey. "This information is critically important as we contemplate a future with widespread electric vehicle usage, given the additional electricity demand these vehicles create and the associated impacts on the grid.

    The Study “will examine the complexity of the behavioral relationships that are manifest as price elasticities, which measure the sensitivity of PEV charging to the on-peak/off-peak time-of use (“TOU”) price differential, the overall electricity price level, prices of substitutes, customer demographics, and other relevant factors.” The Study’s working hypothesis is that greater variations in time-varying pricing, together with the use of accommodative vehicle technology, will shift more charging activity to off-peak periods. For the purposes of this Study, “technology” refers to the communication and control devices that will facilitate convenient and economic “smart charging” behavior.
    Through the ECOtality project, the first 1,000 purchasers of Nissan LEAF electric vehicles in San Diego will receive free home charging equipment. Each Nissan car owner will also become a participant in SDG&E's Pricing and Technology Study. The objective of the Study is to benefit California's understanding of how electric vehicles interact with the electric grid. The Study's working hypothesis is that greater variations in time-varying pricing, together with the use of accommodative vehicle technology, will shift more charging activity to off-peak periods. The project will also provide approximately 1,500 additional Level 2 Public/Commercial Chargers and 50 Fast Chargers. The California Energy Commission (CEC) awarded $8 million to Ecotality as matching funding for this project, which will likely result in additional Public/Commercial charging infrastructure being deployed to the San Diego region.
  • In July 2010, after reviewing legal briefings on the matter in an open regulatory process, the CPUC concluded in a Phase 1 Decision that providers of electric vehicle charging services should not be regulated as public utilities.  The CPUC found that the provision of electric vehicle charging services does not make an entity a public utility and that electric vehicle service providers are, with certain exceptions, end-use customers of a regulated utility.  The CPUC also identified sources of broad regulatory authority (such as the authority to set rates) to address the potential impacts of PEVs on the grid, and to ensure the state meets its greenhouse gas emission reduction goals.  (Press Release)

    The July 2010 Decision notes that legislative codification of the summary conclusion, namely that providers of electric vehicle charging services should not be regulated as public utilities, would remove additional barriers to widespread deployment and use of PEVs by providing statutory surety. 
  •  On March 15, 2011, the CPUC issued a Proposed Decision of President Michael R. Peevey  addressing “Phase 2” issues in the proceeding, establishing policies to overcome barriers to PEV deployment, and complying with SB 626.  The Proposed Decision addresses:
    • PEV Rates, including cost allocation issues
    • PEV Metering Arrangements
    • Utility Notification Policies
    • Utility Customer Education and Outreach programs
    • Utility Demand Response Programs for PEVs.
  • In July 2011, the California Public Utilities Commission (CPUC) released its Phase 2 Decision establishing policies to overcome barriers to electric vehicle deployment.  The decision complies with Public Utilities Code Section 740.2 ( Senate Bill 626 Kehoh) by:
    • Directing electric utilities to collaborate with automakers and other stakeholders to develop an assessment report to be filed in this proceeding to address a notification processes through which utilities can identify where Electric Vehicles charging will likely occur on their electric systems and plan accordingly. To ensure this notification system develops in a timely fashion, the utilities must jointly file the assessment report in this proceeding within 150 days of the effective date of this decision.

      In connection with this proposal, SCE, PG&E, and SDG&E requested Commission approval of initial funding to support the evaluation of the data clearinghouse. This request was denied, however, utilities are not precluded from seeking recovery of reasonable costs of any utility notification systems in future rate cases.

      NRDC expressed support for a notification process. CFC requested Commission scrutiny of data-related privacy issues. DRA urged the Commission to reject funding on the basis that ratepayers should not bear the cost of the initial evaluation for the utilities’ Electric Vehicle data collection.

      In some instances, an Electric Vehicle buyer might voluntarily inform the utility of the physical location of charging. Electric Vehicle buyers are motivated to contact utilities to, for example, obtain service under an Electric Vehicle electric rate schedule. Electric Vehicle buyers have little motivation, however, to contact a utility for the purpose of notifying utilities of the location of the Electric Vehicle charging. In addition, no formal standardized notification program exists so that a utility can identify all Electric Vehicles being introduced into their service territories.

    • Affirming that, with certain exceptions, the electric utilities’ existing residential Electric Vehicle rates are sufficient for early Electric Vehicle market development, and, similarly, that existing commercial and industrial rates are sufficient in the early Electric Vehicle market for non-residential customers. The decision also sets out a process to reexamine Electric Vehicle rates in 2013. By then the Commission will have a better understanding of customer charging behavior and more Electric Vehicle load profile data to inform future rate design.

    • Because a single meter Electric Vehicle rate motivates a customer to better manage the peak impacts of the entire household’s electricity usage, not just the energy used for Electric Vehicle charging, we will not prohibit single meter Electric Vehicle residential rates. The CPUC hopes that when we revisit rates for Electric Vehicles in 2013, inexpensive submetering technology will be readily available, obviating the need for such rates. As this outcome is not certain, the CPUC encourages SCE to continue exploring the feasibility of a non-tiered single meter rate, and directs PG&E to do likewise.

    • Considering opportunities to migrate toward new and lower cost metering technologies for Electric Vehicle charging and sets out a process to develop an Electric Vehicle metering protocol to accommodate increased Electric Vehicle metering options, such as submetering.

    • Determining that until June 30, 2013, the costs of any distribution or service facility upgrades necessary to accommodate basic residential electric vehicle charging will be treated as shared cost.
    • Requiring utilities to perform load research to inform future CPUC policy.
    • Addressing utility ownership of electric vehicle service equipment
4. Benefits
  • Load Leveling - Assuming that approximately 76% of drivers charge during a normally low-demand “off-peak” period, additional PEV load can flatten the daily load curve and improve grid load factors. A flattened load shape results in more efficient utilization of power plants and transmission / distribution assets, which lowers average electricity costs.
  • One idea raised by Brett Williams of UC Berkeley's Transportation Sustainability Research Center entails tracking and treating electrons for "fuel services" differently than electricity for powering other stuff.

    Electric utilities in California are "de-coupled" -- i.e., not incentivized by how much electricity they sell. What if they were "coupled" on the electricity they sold for fuel services or if e-fuel was treated differently? The utilities would have a stake in the penetration and performance of EVs and V2G.
    Williams of the TSRC suggested that this might make sense because in the near-term there will be a need to track these EV electrons for carbon credits or so a tax can be applied to make up for lost revenue from gasoline road taxes.


5. Risks/Issues
  • Geographic Rate Confusion - Another potential PEV tariff issue is the disparate and potentially confusing range of PEV rate options offered by different utilities to electricity customers/EV drivers. PEV rates differ amongst the IOUs and municipal utilities. The rate difference may be particularly problematic for residential electricity customers/EV drivers that charge at home in one utility service territory, and charge at work or another residential location in another utility service territory. As an example, a residential electricity customer/PEV driver may have a primary charging location in a small utility whose service territory is embedded in a larger IOU service territory.

  • High Residential Inclined Block or Tiered Rates - Tiered rates increase as a customer’s cumulative usage increases during a billing period and are intended to promote energy conservation.  Electric Vehicle charging is incremental to existing household load, and, therefore, if included with other household load via a single meter, may push the customer into the highest rate tiers. Because tiered rates climb steeply, the bill impact for the Electric Vehicle purchasers could be significant. Exposing the Electric Vehicle owners to tiered rates may raise charging costs enough to discourage prospective Electric Vehicle purchasers. For Electric Vehicle owners, tiered residential rates may also discourage overnight charging of Electric Vehicles at home, perversely encouraging on-peak charging at the workplace or other non-residential settings.

  • Cost of Second Residential Meter - A dedicated second meter that can help reduce monthly utility bills. But it may involve a small upfront utility fee and potentially thousands of dollars in installation costs. To be eligible for IOU PEV rates for segregated PEV load, the customer’s service requires an advanced meter that can communicate sub loads to the utility and a second hardware device to communicate PEV sub load to the advanced meter. The CPUC has authorized the installation cost of an advanced meter for every customer by 2012-2013 pursuant to the Advanced Meter Infrastructure proceeding. The cost of the second device would be born by the customer, as it is located on the “customer side” of the meter. Utilities are working toward standardizing the cost and technical aspects of the second device.

  • Submeter Ownership - Customer ownership of meters allows customers to respond to technology changes and to directly incur the costs and, likewise, receive the benefits of adopting innovations in metering. The effect of competition for meters could produce cost savings for customers. Disadvantages to customer owned meters include the potential for lack of standardization of metering functionality, the need to have a governmental agency verify meter performance, and elimination of the opportunities to reduce costs through utility economies of scale.

    In their July 2011 decision, the CPUC found that Electric Vehicle submeters should be treated consistent with the treatment of any other equipment located on the customer side of the meter. The primary meter will remain under the ownership of the utility. A submeter would measure Electric Vehicle load and be used by the utility in its billing calculations. This arrangement will provide utilities with control over the total billing level and limit opportunities for fraud or meter tampering. Most likely, incidences of fraud would be limited to tampering with the submeter’s calculation of the Electric Vehicle subload, which does not impact the utility calculation of the total load at the primary meter.

    Parties generally agreed that a need exists for an Electric Vehicle submeter protocol to determine rules for customer-owned meters.

  • Should utilities be permitted to own electric vehicle service equipment? - Utility ownership of this equipment could provide safety advantages, reduce customer cost, and support utility notification of location where vehicles will be charged. However, utilities can not recover costs related to electric vehicle service equipment from ratepayers. The CPUC did not find convincing evidence that utility ownership of electric vehicle service equipment will result in safety advantages over electric vehicle service equipment owned by customers or other entities. Municipal governments already have permitting requirements that review project installations for their safety merits. Additionally, national standards on electric vehicle service equipment couplers and other equipment features ensure manufacturers’ adherence to safety standards. They also found speculative the assertion that utility ownership of electric vehicle service equipment will reduce customer costs.

  • Utility Cost Recovery Policy for Residential Upgrades and Extensions - Utilities anticipate the need to make infrastructure upgrades to accommodate the added load from residential Electric Vehicle charging. For example, if a residential customer installs electric vehicle service equipment, the utility may determine that the distribution transformer, a service panel, or other equipment needs to be upgraded to facilitate vehicle charging. There is a great deal of variability depending on whether residential customers will respond to incentives to charge off-peak. A preliminary PG&E analysis suggests “distribution upgrade costs to accommodate charging for residential circuits may be as much as five to twenty times greater on-peak as compared to off-peak.

    According to California's Rule 15, an upgrade to equipment serving multiple customers is generally considered a utility expense and the associated cost is borne by the general body of ratepayers.

    The cost allocation of upgrades to equipment serving a single customer, which is governed by Tariff Rule 16, is more complex. For equipment upgrades due to increased electricity usage designated as “new and permanent load,” the customer is provided an “allowance” to off-set the costs of the upgrade. The allowance is a fixed dollar amount for all residential customers within a utility service territory. Generally, any upgrade costs up to the dollar amount of the allowance are paid for by the general body of ratepayers and any costs in excess of the allowance are paid for by the specific customer served by the equipment.

    While TURN argues that a PEV does not fit the definition of permanent load, the CPUC decided that from a broader policy perspective, it makes sense to treat PEV as permanent load.

    In some instances, the costs of residential upgrades to enable Electric Vehicle changing will exceed the allowances provided under Rules 15 and 16. The CPUC decided in July 2011 that between the effective date of this decision and June 30, 2013, service facility upgrade costs to enable basic (in most cases to encompass Level 1 and 2 charging for at least one vehicle) Electric Vehicle charging that exceed the residential allowance will be treated as common facility costs rather than being paid for by the individual Electric Vehicle charging customer.

  • Quick Charging Facilities Cost to Grid - These DC charging facilities, are designed to charge an electric vehicle battery to 80 percent capacity in approximately 30 minutes by drawing as much as 50 to 250 kilowatts. As a result, quick charging facilities place a considerably higher kilowatt demand on the electric system than even the fastest Level 1 or Level 2 charging. While the impact of quick charging on Electric Vehicle adoption is projected to be positive, its impact on peak demand and distribution infrastructure is uncertain.

    It is expected that quick charging will most commonly be available at non-residential sites or electric vehicle service provider charging spots and will function similarly to a gasoline filling station. The CPUC found the tariffs now available in the commercial and industrial context are characterized by a number of design features and eligibility requirements that serve to ensure that electric vehicle service providers bear the costs appropriate to their impacts on the electric system. These include all or some combination of time-of-use rates, demand charges, and/or eligibility criteria that limit the capacity under a given tariff to a pre-defined maximum.

  • PEV Tariff Scope - Should PEV rates apply to small battery capacity low-speed PEVs and electric motorcycles? The PG&E electric schedule E-9 tariff currently excludes “low-speed electric vehicles and electrically powered motorcycles as defined by the California motor vehicle code.” While NEVs are not intended to replace highway VMT, they are an important means of reducing short trips under three miles, which comprise nearly half of all trips. The U.S. DOE states that NEVs are “very efficient in terms of initial capital costs, fuel costs, and overall operating expenses.” The CARB ZEV mandate provides credits for NEVs used. The ARRA also makes NEVs eligible for consumer tax credits, and the AQIP program funds NEV purchase incentives. Moreover, the 2005 NEC Article 625.2 incorporates NEVs into the definition of electric vehicles. Therefore, to the extent that the PEV rate incents increased PHEV, BEV, and NEV usage, it would seem illogical to exclude NEVs from rate applicability.

  • Highway Tax Replacement - The California and Federal Departments of Transportation rely on highway tax and sales tax from gasoline for highway construction and maintenance. California tax, federal tax, and sales tax amounts to $0.735/gallon. This tax equates to $0.02/kWh on BTU basis or $0.08/kWh per mile basis, which is currently not assessed on PEV rates. In the long term, a policy to levy an equal tax on all alternative fuels, including biofuels or hydrogen, may be needed to avoid significant loss of transportation network funding. Alternatively, such a tax may be implicitly achieved via the cap-and-trade pricing mechanism, once transportation fuels are including in the cap. At that point, all fuels, including petroleum and alternative fuels, will effectively be internalizing the cost of CO2e from well-to-wheels. Alternative fuel taxes, if they apply to electricity fuel and other alternatives, may require California Legislative or other coordinated state agency action.

  • Carbon Market Rules - AB 32 cap-and-trade emissions allowance allocation policy that does not address the anticipated transfer of emissions from the transportation to the electricity sector associated with transportation fuel “switching” from petroleum to electricity.

    Electricity utilities may face a disincentive to support electrification if penalized for emissions due to load supplied to electric vehicles. Assuming allowances are allocated on a sectoral basis, failure to make available additional allowances to the electricity sector due to electrification to the electricity sector risks overburdening ratepayers with the cost of transportation sector emissions. Provided that electrification occurs at a significant scale, regulators should consider a policy to shift allowances from the transportation sector to the electricity sector, while not changing the total cap on the pool of allowances.

6. Next Steps
  • Additional research is needed to inform policies for the next stages of Electric Vehicle market development. Presently, many uncertainties surround the evolving market for Electric Vehicles and charging services. Among these uncertainties are the extent to which consumers will charge vehicles off-peak versus on-peak and consumer response to various time-of-use rate designs and metering arrangements. It is also unclear whether consumers in the residential context will react to time-of-use rates differently compared to consumers in the MDU context.

    Two studies that will yield instructive results are Ecotality’s Electric Vehicle Project and Coulomb’s ChargePoint America.

  • The CPUC ordered that the following Electric Vehicle load research be completed by January 1, 2013 so it can inform the Electric Vehicle rate design recommendations submitted with PG&E’s 2014 General Rate Case (rate design phase) and SCE’s and SDG&E’s rate design window applications in 2013.
    • Track and quantify all new load and associated upgrade costs in a manner that allows Electric Vehicle load and related costs to be broken out and specifically identified. This information shall be collected and stored in an accessible format useful to the CPUC.
    • Evaluate how metering arrangements and rate design impact Electric Vehicle charging behavior. 
    • To the extent relevant, determine whether participation in demand response programs impacts Electric Vehicle  charging behavior. 
    • Determine how charging arrangements, including metering options and alternative rate schedules impact  charging behavior at MDU. 
    • Evaluate whether distribution costs are increased by different charging levels, i.e., Level 1, Level 2, and quick charging, in public locations. 
    • Separately track costs associated with Electric Vehiclerelated residential service facility upgrade costs and treated as “common facility costs” between the effective date of this decision and June 30, 2013, and propose a policy and procedural mechanism to address these residential upgrade costs going forward.
7. Companies/Organizations
  1. CARB - California Air Resources Board - Responsible for implementing California's SB32 Plan to reduce GHG. Within California, the electricity sector accounts for only 25% of economy wide emissions, yet the sector is responsible for reducing 40% of emissions to meet 2020
    goals, according to CARB’s Scoping Plan. The Plan recognizes that the transportation sector must be responsible for reducing its share of the economy wide emissions and not expect other sectors, such as electricity, to make up the difference.

  2. California Department of Food and Agriculture - Will play a key role in any submeter process as the regulator of non-utility measurement devices used in commercial transactions.

  3. CEC - California Energy Commission -  Responsible for California Energy Codes It could update Title 24 to provide mandatory, minimal (20-30A @ 240V) EV home infrastructure requirements including upgraded service entrance (i.e. 200A-320A service) for new home construction and incentivize further charging (50-70A@240V).or update Title 24 for MDUs to allow for minimum EV infrastructure installation for new construction.

  4. CPUC - California Public Utilities Commission - Regulates privately owned electric, natural gas, telecommunications, water, railroad, rail transit, and passenger transportation companies. In response to Senate Bill 626 (Senator Christine Kehoe, 2009), and to make sure the electric utilities the CPUC regulates are prepared for the projected statewide market growth of plug-in electric vehicles s (PEVs), the CPUC initiated an Alternative Fueled Vehicle Rulemaking Proceeding in August 2009.

  5. DRA – Division of Rate Payer Advocates, San Francisco, CA – Public Advocate in California An independent consumer advocacy division of the California Public Utilities Commission (CPUC), Part of the California PUC Our statutory mission is to obtain the lowest possible rate for service consistent with reliable and safe service levels. In fulfilling this goal, DRA also advocates for customer and environmental protections.

  6. ECOtality - San Francisco - (NASDAQ: ECTY) Through the ECOtality project, the first 1,000 purchasers of Nissan LEAF electric vehicles in San Diego will receive free home charging equipment. Each Nissan car owner will also become a participant in SDG&E's Pricing and Technology Study. The objective of the Study is to benefit California's understanding of how electric vehicles interact with the electric grid. The Study's working hypothesis is that greater variations in time-varying pricing, together with the use of accommodative vehicle technology, will shift more charging activity to off-peak periods.

  7. NRDC - Natural Resources Defense Council

  8. EV Service Provider Coalition, consisting of Better Place, Coulomb Technologies, Inc. (Coulomb), and Ecotality/eTec, submitted a joint pleading in CPUC EV Rate Proceeding. They claim that the Commission has no jurisdiction over electric vehicle charging service providers that offer electricity as a form of transportation fuel. This coalition supports the analysis in the Scoping Memo and states that over-reaching jurisdiction will stifle competition, innovation and investment in the industry. They suggest the Commission adopt tariff rules to facilitate the provision of electric vehicle services in a manner that is as convenient and seamless as possible.

  9. TURN - The Utility Reform Network, San Francisco CA - Utility watchdog that stand up for consumer rights, affordable rates and a more livable California. For more than 30 years they have challenged California’s powerful energy and telephone companies, saving consumers and small businesses millions, and demanding reliable service and environmentally sound policies. Opposes special deals for EV Owners.


8. Links
  1. Alternative Fueled Vehicle Proceeding - CPUC
    1. July 6, 2011 (Revision 2): President Michael Peevey's Proposed Decision on Phase 2 matters establishing policies to overcome barriers to electric vehicle deployment and complying with Public Utilities Code Section 740.2
    2. July 29, 2010: CPUC Addresses Regulatory Authority to Create Vibrant Market for Electric Vehicle Charging
      Full Decision
    3. California Public Utilities Commission- "Light-Duty Vehicle Electrification In California" May 2009. - A comprehensive white paper created to spot trends, issues, opportunities, and barriers. The CPUC objectives were to ensure that fair and reasonable rates for EVs would be offered, to protect the reliability of the grid, to promote innovation for EV products and services by keeping the various "playing fields" level and open, and to make sure that other critical issues also are being addressed. The CPUC is essentially leading the process of establishing "the rules of the game" for EVs, and since this has never been done before, the results will likely serve as the template for other states and countries going forward
  2. CPUC Resolution E-4334. San Diego Gas & Electric (“SDG&E”) requested approval to establish three new temporary experimental residential rate schedules for plug-in electric vehicle (“PEV”) charging

Saturday, July 28, 2012

Smart Grid Investment Recovery

Will the utility industry make the investments in smart grid based largely on avoided costs alone, and will they do it a timely manner or over many years?


Navigate this Report
Back to Stimulus & Regulation Index
1. Background

2. Acronyms/Definitions
3. Business Case
4. Benefits
5. CPUC Criteria for Demand Response Investment
6. Risks/Issues
7. Success Criteria
8. Companies/Organizations
9. Case Studies 
10. Links

SCE Smart Meter Business Case - 20 Year Cost/Benefit

1.Background
  • Smart grid investments often require large upfront costs relative to their benefits. However, future benefits may come at small incremental costs. Utilities and regulators may need to look at full system life cycle costs and benefits in order to fully justify added investments. Some of the benefits may come in the form of societal benefits which will need to be clearly understood and evaluated. Payback periods may be longer than stakeholders would like. The service providers, regulators, and ultimately ratepayers are going to have to believe it before such substantial investments are made.

  • Public Utility Commissions (PUCs) analyze and determine if proposed utility infrastructure investments, like the deployment of Smart Grid technologies, are prudent investments. Investments are often evaluated based upon actual and realizable benefits, and while future benefits may be considered, they must be evaluated appropriately. The state-by-state PUC approval process could create a patchwork approach, as different Smart Grid improvements could be adopted by neighboring states or even utilities within one state.

  • The Federal Energy Regulatory Commission (FERC) is seeking to provide an interim rate policy under which jurisdictional public utilities may seek to cover costs of Smart Grid deployments before standards are adopted through a rulemaking. It recognizes that a key issue for utilities in deciding whether to invest in Smart Grid technologies may involve the potential for stranded costs associated with legacy systems that are replaced by smart grid equipment.

  • On March 19, 2009, FERC proposed a rate policy for the interim period until interoperability standards are adopted. Smart grid investments that demonstrate system security and compliance with Commission-approved Reliability Standards, the ability to be upgraded, and other specified criteria will be eligible for timely rate recovery and other rate treatments. This rate policy will encourage development of smart grid systems.

  • State utility commissions need to develop interim rate policies to accommodate costs of smart grid deployments in areas where the states have traditional jurisdiction.

  • Generally, before state commissions approve a utility’s AMI deployment plan, the utility must first demonstrate a positive cost-benefit business case for its proposed AMI implementation. For many utilities, a positive business case requires including projected savings from demand response. A large fraction of AMI costs (ranging from 50 percent to 90 percent) can be justified by a reduction in traditional utility costs of operations or improved services, such as avoided meter-reading costs, faster outage detection, improved customer service, and better management of customer connections and disconnections. Projected benefits from the demand response enabled by the AMI system may be included to bridge the cost-benefit gap based on what is recoverable from AMI-operational savings alone.

  • Unanswered consumer questions remain:
    • Why do we need to pursue the consumer side (smart meters) before Smart Grid upgrades are made to the distribution system?
    • Why can’t many of the benefits that Smart Grid provides be done with existing technologies, e.g., existing demand response technologies?
    • All consumers will pay for Smart Grid investments, but only some will (can) take the initiative to achieve the full set of benefits. Is that fair?
    • Will consumers have to purchase additional devices to participate with the Smart Grid and enjoy its benefits, e.g., home area networks, in-home displays?
    • Will Smart Grid technologies increase the risk of cyber security breaches resulting in a less secure grid and the leaking of private consumer data?

  • Smart-grid technology offers a wide range of possibilities, so deployments will vary depending on each utility’s business needs, existing infrastructure and regulatory environment. Some utilities may seek to use the technology to maximize energy efficiency, while others may focus on the integration of renewable energy sources.
In this table, the Smart Grid costs are allocated to classes by energy (which are often what a regulatory body would mandate in the case of a regulated utility) and then calculated in several ways: (1) total Smart Grid cost divided by the number of customers for each class (a one-time payment proxy); (2) total cost per customer per year by class for 10 years for a 10-year amortization of the Smart Grid cost (in nominal, not present value, terms); and (3) the monthly equivalent of the annual amortized cost. Finally, for the last value, the EPRI team calculated the corresponding percentage increase in the average customer monthly bill. -- Source: EPRI

2. Acronyms/Definitions
  1. Capital Assets – Included in the rate base when they are used and useful. They earn a return, which is set in a Cost of Capital Case and are depreciated. These items are reviewed in general rate cases, although large additions may warrant a separate filing Expensed items are recovered without a return.

  2. Deregulation - This term means “competition is authorized.” But the term is hopelessly ambiguous because:
    • "Authorized" competition is not "effective" competition
    • Authorized competition, after a century of monopoly, still requires “regulation” for licensing, fraud prevention, access to bottleneck facilities, prevention of affiliate abuse, and assurance of last resort service.
    • The term literally could mean either "elimination" of regulation or "reduction" of regulation (e.g., the term "decelerate" means reduce speed, not eliminate all motion)
    • If effected incorrectly, the result of “deregulation” is still "regulation," except that it is regulation of the market by the incumbent to protect its position, rather than regulation of the incumbent by the commission to protect consumers.
    • Proponents of "deregulation" intend the prefix "de " to replace a negative (regulation) with a positive (elimination of regulation). But the phrase cannily avoids accountability; for if they labeled their goal "effective competition" rather than "deregulation" they'd have to show evidence in place of rhetoric. The converse applies as well: critics of "deregulation" imply that "regulation" creates benefits, but they do not always identify (and guarantee) those benefits. In short, the bipolarity of the term "deregulation" makes discussions more stick figured than sophisticated.

  3. ERRA - Energy Resource Recovery Account – Set through annual CPUC proceedings to determine fuel and purchased power costs on a forecast basis. The revenue requirement is spread over forecast sales. Revenues are recovered through balancing accounts with future adjustments for revenue over-or under-recovery, which can be due to errors in forecasting costs or sales, including response to DR events. Utilities may make trigger filings if actual revenues differ from forecast by more than 5%. There are annual ex post reviews of past ERRA cases.

  4. EUI - Energy Use Intensity - A measure of total energy use normalized for floor area. It is used to compare the energy use of different buildings. Whole-building energy use is measured in kBtu (1000 British thermal units) per square foot, per year, to standardize units between fuels. Electricity use is often expressed as annual kWh per sqft per year.

  5. Intervenors - Most state public utility commission proceedings allow others with an interest to “intervene” in order to present their point of view or question the proposal. Neighbors, communities, environmental groups and other utilities are typical intervenors in proceedings. In most states, these groups do not have access to funding from the state or the utility applicant and must raise their own funds to pay legal and expert costs. Some states, like California, do offer intervenor funding.

  6. Performance Based Cost Recovery Model - Regulators in both Oklahoma and Ohio have approved performance-based smart grid cost recovery approaches. IOUs forfeit some or all of their returns if anticipated O&M savings are not achieved. At the same time, they get the opportunity for returns above the authorized rate if actual O&M savings are higher than anticipated. There are many other potential performance metrics that could be considered, including distribution line losses, demand response per customer, and reliability.

    Capital investment does not (by itself) make a grid smart. The value comes from the manner in which utilities make use of smart grid data and capabilities. Therefore, performance-based cost recovery would better motivate IOUs to pursue the difficult and critical organizational, operational and regulatory changes required to maximize smart grid value than the traditional capital investment incentive approach.

  7. Public Advocate - Forty-two states fund a public advocate office that represents the public in cases before the state utility regulators. In many states, the public advocate can hire experts and can bill those costs to the utility applicant, generally subject to review by the utility commission. Public advocates usually have people on their staff who are experts on utility regulation and participate in reviews of utility plans, with a particular focus on the rate impact of new investments. Consumer advocates also intervene in cases before the Federal Energy Regulatory Commission.

  8. PVRR - Present Value of Revenue Requirement - Derived by subtracting the operating and capital revenue requirements from the market value of generation, assuming that the unit end of life is extended in one year increments. Calculated by subtracting fuel, O&M, environmental emissions cost, and on-going and CAI capital revenue requirement cost from revenue similar to a merchant plant valuation.

  9. Rate Case - The revenue requirement for utility-owned generation in California, excluding fuel, is reviewed in general rate cases every three years. This includes rate base and O&M. The revenue requirement for utility metering and billing systems is reviewed in general rate cases. There have been separate cases to approve AMI expenditures. There have been separate cases to approve utility EE and DR expenditures, in three-year cycles

  10. Regulatory Concepts
    • Prudency of investments: This can be broken down into decisional prudence i.e., was the decision to invest in smart grid reasonable given information known at the time and operational prudence i.e., did the utility build and deploy the investments in a timely and reasonable manner.
    • Used and useful: Investments must be useful for the purpose it was intended once recovery of costs begin.
    • Equity in allocation of costs and risks refers to the amount of risk (and in turn, cost) each side to the bargain must bear. Typically utility investments are undertaken as a need is identified and the cost to address that need is minimized.
    • Single Issue Ratemaking: Utilities are generally required to “net” all costs and benefits of operation at the time rates are set to avoid cherry picking individual cost increases that may be offset by other cost decreases.
    • Regulatory lag: This is the key incentive under traditional regulation for utilities to maintain efficient operation. Regulatory lag comes in two forms. The administrative lag refers to the time required to set rates. The economic lag refers to the time between rate setting procedures

  11. Stranded Asset - An asset that is worth less on the market than it is on a balance sheet because it has become obsolete in advance of complete depreciation, such as electric utility meters that are replaced by newer meters before the existing ones would normally have been retired.

3. Business Case
  • Given our nation’s population growth and the exponential increase in the number of power-hungry digital components in our digital economy, additional infrastructure must be built – smart or not. According to The Brattle Group, investment totaling approximately $1.5 trillion will be required between 2010 and 2030 to pay for this infrastructure. The Smart Grid holds the potential to be the most affordable alternative to “building out” by building less, and saving more energy. It will clearly require investments that are not typical for utilities.
  • The utility industry has historically been regulated for prior investment, the transformation to regulation for value delivery promises to stimulate substantial progress and alignment around the Smart Grid vision and implementation. However, regulators will continue to require a showing that the value of the investments to consumers ultimately exceeds the costs.
  • Smart grid development must compare incremental costs directly with incremental functionalities and avoid the double-counting of benefits.
  • Ratepayer investment in Advanced Metering Infrastructure should be matched by private sector investments to develop in-home HAN technology. Customer preference of data access frequency should not result in additional AMI system hardware costs to ratepayers.
  • Market competition for HAN-enabled home energy management solutions may provide lower-cost strategies than utility programs. The smart grid should support a sustainable and competitive market for independent demand-side management products and services.
PG&E Upgrade Business Case - Benefits are only 4.3% higher than costs even including softer benefits like demand response and conservation

4. Benefits
  • Avoided Cost of New Generation - the most recent Department of Energy combustion plant cost of $670/kW.
  • Avoided Cost of New Transmission - $125/kW from Rand Study
  • Avoided Cost of New Distribution - $250 /kW from Rand Study While $250/kW is likely to be a reasonable average cost of distribution across the U.S. (though the cost estimates are now somewhat low since the data were developed a decade ago), distribution costs vary widely across utilities. For instance, the distribution cost for Con Edison from the original study is more than $1,500/kW.
  • Customer Benefits
    • More Energy Use Information
    • Pricing plans that give customers more choices based on lifestyle and convenience
    • Enabling the "Connected Home” Customers will be able to program smart appliances and devices to respond to their energy use preferences based on cost, comfort and convenience.
    • Peak Energy Alerts
    • Convenience When You Move with remote service turn-ons
    • Keeping the Lights On - Information provided by the new "smart" meters will inform smart grid operators when an outage occurs and how extensive it is, enabling a faster response for quicker service restoration.
  • Environmental Benefits
    • Reducing Peak Electricity Demand
    • Sustained Conservation
    • Clean Technology

5. Criteria for CPUC Demand Response Investment
The following list includes factors that have been considered in evaluating the programs:
  1. Cost Effectiveness: The cost effectiveness analysis contained in these applications is based on a Consensus Framework proposed by most of the parties in R.07-01-041. This framework is not as broad as the subsequent protocols proposed by Commission staff, which required a sensitivity analysis of many inputs rather than a single benefit/cost ratio for each program and test. However, it does provide a useful estimate for examining the cost effectiveness of programs.
  2. Track record of performance for continuation of existing programs: This includes, but may not be limited to, actual load drop (especially compared to enrolled load and estimated load drop), target groups and types of participants, actual cost, how often it was called, actual load drop rate, actual load pick-up rate, and other factors as appropriate.
  3. Projected future performance: Expected performance in the future including, but is not necessarily limited to, estimated participation (customers and enrolled load) and estimated load drop at peak times.
  4. Cost.
  5. Flexibility or Versatility: Whether a program can be called under a variety of circumstances, or only in very rare or specialized situations. For example, does the program have multiple triggers? Can it be called on a price responsive basis for simple day to day resource dispatch, as well as for contingency matters such as emergencies? Can it be called in non-summer months to respond to generator outages?
  6. Adaptability to changes in the structure of the electricity market: Ability of a program to adapt to the Market Redesign and Technology Upgrade (MRTU) and the new CAISO markets. For example, is a program likely to be able to supply some of the operational characteristics of Proxy Demand Resource or participating load? What interaction or shared dispatch and control could CAISO have with the program?
  7. Locational value: Whether the program can be called by location. For example, can the program be activated (“called”) by specific location if necessary, particularly in transmission and distribution congestion areas? Does the program help to alleviate a particular geographic challenge? Does it count towards locational resource adequacy or more specific local needs?
  8. Integration with advanced metering infrastructure, Smart Grid, and emerging technology: What enabling technologies are required for the program? Would this enabling technology become obsolete or redundant once AMI is installed at the participant customers site? Will the program increase the operational capability of AMI? How might the program contribute to a Smart Grid?
  9. Consistency of offerings throughout the state: Are equivalent programs available in or appropriate for other parts of the state? Is the program consistent enough across utilities that commercial customers with multiple facilities can participate easily?
  10. Simplicity/Understandability: Can customers understand how the program operates and what is expected of them?
  11. Customer acceptance and participation: Are participating customers likely to recognize that the program had been called? Is participation likely to cause customer hardship? Can the customer override an event – if so what does the utility expect will be the rate of customer override?
  12. Environmental benefits: Does the program have any particular environmental benefits that other programs do not have? Does the program help with firming intermittent renewable energy?
  13. Contribution to existing Commission or state policies and goals:
    Is the program consistent with statewide goals or policies? For example, will the program simply shift usage from peak to another time or does the program also reduce overall usage? Is it integrated with other demand-side programs? Does it result in significant greenhouse gas (GHG) reductions?

6. Risks/Issues
  • Cost – is among the most significant challenges facing development of a smart grid, with estimates for just the electric utility advanced metering capability ranging up to $27 billion along with the regulations that allow recovery of such investments.

  • Stranded Assets - Regulators are struggling with approving IT investment that will be obsolete long before the 20-40 years utilities traditionally expect. Strong interoperability standards are necessary to ease upgrading and minimize "stranded assets." For detals see my blog article Standards for Standards.

  • Comprehensive Meter Program Costs - $500 for each residential and small commercial customer, $5,000 for medium commercial customers (between 20 and 200 peak kW) and $20,000 for large commercial customers. These costs include utility costs of developing the infrastructure required to support real time pricing, load control and other programs along with equipment and installation costs.

  • Avoided Cost Recovery - Under the current regulatory environment, the utilities' avoided costs would not normally be a problem if they had to incur them without investing in smart grid. This is because any new generation and transmission investment to handle growth in peak demand and total energy consumption is historically always recovered by customer rate increases approved by regulators. So, there may be a lack of incentive for utility companies to make smart grid investments on a huge scale.

  • Financial Incentives - Regulatory reform may be necessary to provide more immediate financial incentives for utilities to invest in smart grid, otherwise smart grid may be deployed over an excruciatingly very long time to get implemented to every customer. Adding extra charges to customers' bills to explicitly pay for smart grid as envisioned by many as a way to fund it won’t be very palatable with customers if those charges become excessive relative to an average utility bill. There would be huge political opposition to massive charges added to everyone’s bills.

    The traditional modes of motivating an IOU to invest capital in its distribution system – providing a fair rate of return on shareholders’ equity – do not necessarily motivate an IOU to maximize the value of smart grid investments.

    For the past century or so, investor-owned utilities (IOUs) have been authorized by their regulators to earn a rate of return on equity sufficient to attract investors and fund capital investments. This arrangement assumes that infrastructure investment is useful for customers. In distribution, this has traditionally held true and is fairly black and white: Capital investment is needed when loads and customer counts grow; when switches and transformers fail; and when billing software becomes obsolete.

    In fact, the value of investing into the distribution business has long been considered a given; as long as improvements are needed, are fairly procured, and are appropriately commissioned, the new assets are deemed ‘used and useful’ and are allowed into an IOU’s rate base for cost recovery.

    Smart grid assets are altogether different in two ways. First, the decision to invest is optional and not generally related to immediate needs. Second, the value delivered is highly variable and almost wholly dependent on the actions a utility takes during design, implementation and optimization phases of deployment.

  • Poor business cases in isolation, high initial investment when integrated. In the metering and distribution automation environments, basic Smart Grid functions tend to have poor business cases by themselves.

    • Examples of such functions are simple automatic meter reading, or feeder fault location and auto-restoration. While nobody can deny their intrinsic value, these functions typically do not provide enough return on investment to justify building the communications networks needed to deploy them over a wide area.

    • If utilities are to argue for cost recovery project by project rather than by single integrated plan, some beneficial aspects of deployment of a smarter grid could be lost. Integrated plans are being proposed and considered. In California, smart meters only became economic when the commission considered non-utility benefits – benefits to consumers from lower bills.

    • Many early adopters of Smart Grid philosophy have discovered that when several Smart Grid applications are deployed together, the integrated business case becomes viable. For instance, when basic meter reading is combined with meter-aided outage management, theft detection, and prepayment and/or real-time-pricing, it is easier to justify an AMI deployment. Similarly, when fault location is combined with phasor measurement and real-time state estimation, the business case for transmission or distribution automation becomes clearer.
    • Nevertheless, these more advanced features require bigger up-front investment. The higher initial investment of integrating advanced Smart Grid applications may present a challenge to many utilities.

  • Lack of Support from Consumer Groups - Watchdog Groups such as TURN and DRA do not support SmartGrid rate proposals from California three major ISO’s.

  • Benefit Quantification - The value of Smart Grid technologies has been difficult to quantify in a simple cost-benefit analysis due to the multi-tiered benefits they provide to the utility, the consumer, and society. Comparative financial metrics are difficult to achieve because each utility incorporating Smart Grid technologies has put a unique level of investment in a variety of technologies.

  • First Adopter Risk - the rewards—financial, operational, experiential, and otherwise—for first adopters are not generally recognized by other electric industry stakeholders.

  • Long Payback Period - Utilities must grapple with making Smart Grid investments, knowing that significant utility and consumer benefits may not occur for several years. A Smart Grid is a complex, comprehensive, and integrated monitoring and operating system; it will provide publicly observable benefits only after considerable investments have been made in upgrading the infrastructure of the nation’s utilities and the monitoring and control devices in the homes and businesses of consumers. Investing in equipment and personnel training, for which there are few short-term benefits, creates operating costs that may be difficult to justify without policy direction and support from government agencies.

  • Patchwork of Regulation - Utilities are regulated at the state level which means 50 different and often conflicting sets of rules that apply to an even more diverse industry made up of 1,200 state regulated utilities plus 2,000 municipal utilities with their own regulations. Federal regulatory oversight is limited to the interstate transmission of electricity and a few federal utilities such as the TVA and Bonneville Power Administration.

  • No Bid Contracts - The current paradigm allows IOUs to contract single third party vendors. This structure impedes competition and innovation in customer-focused smart grid products for in-home energy management.

  • Microgrids - Have to rethink cost attribution based on usage with microgrids. A level playing field between utilities and third parties will promote California’s goal on Energy Efficiency Market Transformation.

  • Entrepreneurial Culture- Regulated utilities have traditionally been reactive, with no need or incentive to be proactive on a national level. Well aligned for utility operations, they are not necessarily well positioned for integrated strategic initiatives like the Smart Grid.Currently, regulated utilities and their flat-rate customers have no risk or reward signal. Regulation makes it difficult for them to raise rates and recover costs, and makes them reluctant to change.

    Since the technology and value propositions are emerging, utility companies may be reluctant to expend the significant amount of capital required to move toward a smart grid, especially because expected cost-recovery timelines are only theoretical and have no precedent.

  • Cross-Subsidation - The US Government Accountability Office (GAO) is asking the FERC to consider cross-subsidization – passing on to consumers the cost of transactions between utility companies and their affiliates. By reading about multi-state regulatory requirements, GAO concerns get multiplied as cross- subsidization complexity increases by involving several states regulators in one utility application.

7. Success Criteria
  • Public Utility Commissions and regulatory staffs of the utility companies sit down with their bosses and agree to put the social benefits of upgrading the infrastructure into their business case.
  • Performance based state utility regulation
  • For a smarter grid to benefit society, it must reduce utilities’ capital and/or operating expenses today – or reduce costs in the future.

8. Companies/Organizations
  • DRA – Division of Rate Payer Advocates, San Francisco, CA – Public Advocate in California An independent consumer advocacy division of the California Public Utilities Commission (CPUC), Part of the California PUC Our statutory mission is to obtain the lowest possible rate for service consistent with reliable and safe service levels. In fulfilling this goal, DRA also advocates for customer and environmental protections.
  • TURN - The Utility Reform Network, San Francisco CA - Utility watchdog that stand up for consumer rights, affordable rates and a more livable California. For more than 30 years they have challenged California’s powerful energy and telephone companies, saving consumers and small businesses millions, and demanding reliable service and environmentally sound policies.
9. Case Studies 
  1. Maryland Public Service Commission

    • On June 21, 2010, the Maryland Public Service Commission rejected BG&E’s bid’s to install smart meters to 1.2 million customers across its service territory and institute mandatory TOU pricing in summer months, the PSC said in an order issued yesterday. Financial risk to the utility’s customers is just too big, the regulators said.
    • The PSC found the business case for BG&E’s smart grid proposal “untenable” but invited the utility to submit an alternative proposal that addresses the commission’s concerns.
    • BG&E estimated the plan would cost $482 million during the initial deployment period and an additional $353 million over the expected life of the program. The timing of BG&E’s proposal was motivated by DOE awarding BG&E a grant of $200 million for smart grid investments.
    • Along with system-wide AMI deployment, BG&E’s application included a request to establish a tracker surcharge to recover the costs of the smart grid plan from electric and gas customers. The PSC said in its order “The proposed project is … classic utility infrastructure investment that should be recovered through distribution rates, not in a supplemental surcharge that begins long before customers could realize any benefits from the project. Just as we have declined other companies’ efforts to move a broader range of expenses out of rate base and rate cases, we decline here to depart from the core principle that utilities recover the cost of infrastructure investments through distribution rates.” The PSC said the surcharge would “virtually guarantee” the utility recovers from its customers the costs associated with the proposal and a profit for its investors. “In other words, with the proposed tracker in place, the proposal is a ‘no-lose proposition’ for the company and its investors,”
    • Concerning the TOU proposal, the PSC said BG&E’s application contained no detailed customer education plan, included no commitment to installing in-home displays and provided for “grossly inadequate messaging … to trigger the behavior changes contemplated under the proposal.” Some of the utility’s most vulnerable customers -- including low-income people, elderly folks and those with medical needs requiring electricity are less likely to realize the benefits of TOU pricing than average customers because they cannot shift use to off-peak hours.
    • The PSC concluded the nature and magnitude of the uncertainties underlying the utility’s business case raise serious doubts about whether the proposal was a cost-effective means of reducing consumption and peak demand of power in Maryland.
    • BGE countered that while it designed 100% of the project’s benefits to flow through to customers, the PSC still suggested that shareholders should bear the risk of the project. That would be “a heads-I-win, tails-you-lose request, and that is a non-starter for us,”
    • GE Energy Services argues the Maryland PSC and other state commissions must be prepared to allow utilities to earn a return on their investments in smart grid through a surcharge or another rate mechanism. Otherwise, utilities will opt to build costly new generation and transmission lines to meet demand growth in lieu of deploying smart grid technology.
    • The National Energy Marketers Association agrees with the conclusion that mandatory TOU at this early stage of a consumer’s understanding of the pricingstructure could be fraught with problems.
    • GridWise says that Regulators should not reject a comprehensive smart grid project simply over concerns about a particular rate structure.

  2. Michigan Appeals Court restricts DTE Energy Smart Grid Increase
    • On April 13, 2012, the Michigan Court of Appeals on Thursday overturned a state Public Service Commission (PSC) decision to allow DTE Energy a $37 million rate increase to pay for smart meters.
    • The court said DTE hadn't provided enough evidence to justify the rate increase. "We will not rubber stamp a decision permitting such a substantial expenditure – a cost to be borne by the citizens of this state – that is not properly supported," said the written opinion of the three-judge appeals court panel.
    • The court also told the PSC to investigate the benefits and possible burdens of smart meters. The court said "At best, the actual evidence presented by Detroit Edison to support the rate increase was aspirational testimony describing the (smart meter) program in optimistic, but speculative terms."
    • DTE states that the Michigan Court of Appeals ruling raised procedural questions about the documentation of costs associated with an advanced meter pilot program in 2008. The Court of Appeals did not reject the costs or say they were improper, but rather sent the issue back to the Michigan Public Service Commission (MPSC) for additional review. The MPSC is currently doing a thorough analysis of advanced meters, and DTE anticipates that the program will be seen as a great investment that is bringing numerous benefits to their customers.
    • The court ruling affects a $217.4 million increase for all customers the PSC approved for the utility in 2010.
    • The MPSC said in January that it would investigate the use of smart meters by DTE and other utilities in the state.

  3. Illinois Performance Metrics

    In October 2011, the Illinois Legislature overrode Gov. Pat Quinn’s veto of the legislation that critics say guarantees ComEd and Ameren utilities yearly rate-hike increases for each of the next 10 years.ComEd, which will invest $2.6 billion to upgrade its electric system in the next decade, contends that it is now the nation’s first utility to have its profits tied to performance, and that it will be penalized if it fails to live up to its agreements to operate an efficient and reliable power system.

    As part of its plan, ComEd will install 10 “smart” electric substations over the next five to 10 years to better predict, find and resolve power outages.

    ComEd and Ameren must do the following in the next 10 years:
    • Improve outages by 20 percent and the duration of outages by 15 percent.
    • Reduce Northeastern region frequency of outages by 20 percent. This area includes the north and northwest suburbs, which were devastated by storms this past summer.
    • Improve the total number of customers who exceed the service reliability targets by 75 percent.
    • Cut the number of annual estimated electric bills by 90 percent.
    • Reduce consumption on inactive meters, a cost borne by all customers, by 90 percent, and reduce by 50 percent electricity theft.

    10. Links
    1. Electricity Smart Metering Business Drivers A PDF White Paper by Atos Origin. A good non-commercial assessment. Presents a dedicated method to assess the financial returns of particular smart metering projects. November 2009
    2. CPUC - Decison Adopting Demand Response Activities and Budgets for 2009 through 2011 (pdf) - Date of Issuance 8/24/2009 - The total adopted budget for all three utilities’ demand response programs for 2009-2011 is $349,509,463. This decision adopts a budget of $188,806,349 for SCE, of which approximately $38.8 million will support the aggregator contracts adopted in this decision. The total adopted budget for PG&E is $109,060,072, and the total adopted budget for SDG&E is $51,643,042.
    3. Utility analysis by Jackson Associates shows that nearly all utilities will save enough in avoided costs with a comprehensive smart grid deployment to at least cover smart grid development and deployment costs; however, many utilities barely break even. For example, about 10% of utilities achieve benefit/cost ratios less than 1.2 and should be considered at risk of incurring costs that are greater than benefits given uncertainties concerning actual deployment costs. More than one-third reflect benefit cost ratios less than 1.5. Customer-detailed analysis shows, however, that all utilities can significantly improve returns on smart grid investments by targeting individual market segments with specific technologies.
    4. 2009 Federal Stimulus Project "Recovery Act - State Electricity Regulators Assistance." Total - $46 million - The primary purpose of this initiative is to assist the state Public Utility Commissions (PUCs) by providing funding to increase staff to facilitate timely consideration through appropriate regulatory processes of ARRA electricity-related activities and investments. More specifically, this initiative should:
      1. help state PUCs better manage the increase in dockets and other regulatory actions expected to result from ARRA electricity-related activities
      2. facilitate timely consideration by PUCs of ARRA electricity-related investments
      3. create jobs.
    5. FERC Smart Grid Policy - March 19, 2009
    6. PUC - Decision on PG&E’s Proposed Upgrade to the Smart Meter Program
    7. Summary of the DRA/SCE Settlement Agreement and TURN/SCE Stipulations Discussion of Remaining Contested Issues
    8. Cost Recovery Mechanisms for Smart Grid Investment Carl Peterson Center for Business and Regulation University of Illinois Springfield
    9. Smart Grid Cost Recovery: Make the Consumer Care Katherine Tweed Greentech Media September 20, 2100

    Thursday, July 19, 2012

    Retail Electricity Markets

    Experience in the introduction of retail competition has been mixed


    Navigate this Report
    Back to Markets & Pricing Index
    1. Background

    2. Acronyms/Definitions
    3. Business Case
    4. Benefits
    5. Risks/Issues
    6. Success Criteria
    7. Case Studies
    8. Companies
    9. Links





    1.Background
    • The rollback of regulations protecting "monopolistic industries" from competition has been one of the main legislative stories of the past 20 years. The trucking, railroad, airline, bus, banking, natural gas, and telecommunications industries have all been--to one degree or another--introduced to the world of economic competition.
    • Within the general deregulating movement in the early 90s and the widely spread faith in markets as the optimal socio-economic organizational pattern, it hence appeared natural to start thinking about commoditizing electricity, just as any other major standardized good. The rationale at that time was that any electricity consumer should be able to choose among a large set of energy providers, and competition between them would naturally increase the affordability and dependability of the service.
    • In the past, one utility provided the all components of your energy service: generation, transmission, distribution and retail. Legislatures and the public utility commissions (PUC) of many states have created competition for electricity and natural gas supply. This allows consumers to choose their energy supplier, while the delivery of the energy is still regulated and is the responsibility of the local utility company.
    • In different deregulation processes the institutions and market designs were often very different but many of the underlying concepts were the same.
      • Separate the potentially competitive functions of generation and retail from the natural monopoly functions of transmission and distribution;
      • Establish a wholesale electricity market and a retail electricity market. The role of the wholesale market is to allow trading between generators, retailers and other financial intermediaries both for short-term delivery of electricity (see spot price) and for future delivery periods (see forward price).


    2. Acronyms/Definitions
    1. Aggregator - A company joining two or more customers, other than municipalities and political subdivision corporations, into a single purchasing unit to negotiate the purchase of electricity from retail electric providers. Aggregators may not sell or take title to electricity. Retail electric providers are not aggregators.

    2. Bundled Transaction/Unbundled Electricity Service - In a bundled transaction, retail consumers pay one price that includes transmission, distribution, and generation. In unbundled electricity service, states have restructured, and consumers are billed for separate transmission, distribution, and generation charges. On March 4, 2002, the U.S. Supreme Court ruled in favor of FERC and held that FERC has jurisdiction over transmission, including unbundled retail transactions.

    3. Electric Market Stakeholders
      1. REMC -Rural Electric Membership Cooperative/Corporation - A term commonly used in the name of an electric co-op such as the South Central Indiana REMC.
      2. IPP – Independent Power Producer – Produce and sell electricity on the wholesale market at market-based rates, and do not have franchised service territories. Most are designated as exempt wholesale generators, which relieves them of many of the regulatory requirements applicable to traditional utilities subject to FERC regulation. Allowed fair access to transmission system by FERC Orders 888 and 889
      3. IOU - Investor Owned Utility
      4. Municipally owned utilities
      5. REP - Retail Electric Providers
      6. Industrial consumers
      7. Large commercial consumer

    4. Energy Switch Services - A kind of company that has come to exist since the EU began deregulating the gas and electricity markets, to open them to international competition, in 1996. Pricing structures and special offers are often complicated enough that it's not obvious which supplier and tariff will be best value for a consumer. This has provided an opportunity for specialist price comparison services. These are chiefly offered by companies who will manage a change to a different supplier and tariff, as well as advising on the best one. These companies primarily operate over the Web, although some also offer an ancillary telephone service.

    5. Green Pricing Program  - Utilities offer their customers a choice of purchasing ;electricity generated from renewable energy sources at a price premium. Often sourced through Renewable Energy Certificates (REC) purchases. A REC represents the environmental, social, and other positive attributes of power generated by renewable resources. These attributes may be sold separately from the underlying commodity electricity.

      This table from the Department of Energy summarizes utility green pricing programs by state.

      An hourlong webinar that originally aired in February 2011,on growing utility green pricing programs, including marketing and messaging to consumers, case studies from successful programs, purchasing trends, and overcoming hurdles to supply from Center for Resource Solutions

    6. ISO - Independent System Operator (Also known as RTO-Regional Transmission Organization when service area spans states) - The formation of Independent System Operators and Regional Transmission Organizations ISOs/RTOs) began in the mid-1990s to support the introduction of competition in wholesale power markets. At present, two-thirds of the population of the United States and more than onehalf of the Canadian population are served by transmission systems and organized wholesale electricity markets run by ISOs or RTOs. These ISOs/RTOs ensure that the wholesale power markets in their regions operate efficiently, treat all market participants fairly, provide all transmission customers with open access to use of the regional electric transmission system, and support the reliability of the bulk power system. Currently, 10 ISOs/RTOs operate in the United States and Canada.

      The cost of setting up and operating an ISO is substantial (on the scale of an American state, several millions of dollars for setting up and between $100M and $200M every year to operate the ISO).

    7. POLR - Provider of Last Resort -

    8. PPA - Power Purchase Agreements - Contracts between two parties, one who generates electricity for the purpose of sale (the seller) and one who is looking to purchase electricity (the buyer). There are various forms of Power Purchase Agreements; these are differentiated by the source of energy harnessed (solar, wind, etc.). Financing for the project is delineated in the contract, which also specifies relevant dates of the project coming into effect, when the project will begin commercial operation, and a termination date for which the contract may be renewed or abandoned. All sales of electricity are metered to provide both seller and buyer with the most accurate information about the amount of electricity generated and bought.

    9. REC - Renewable Energy Certificate you purchase a Green Plan, Kinetic will purchase renewable energy certificates (sometimes referred to as "RECs") sold by eco-friendly electricity generation sources like wind power facilities, solar plants and bio-generation sites to match 100% of your energy usage.

    10. REP - Retail Electric Provider - As a result deregulation, most Texas power customers (those served by a company not owned by a municipality or a utility cooperative) can choose their electricity service from a variety of REP's which includes the incumbent utility

    11. SMD - Standard Market Design - On July 31, 2002, the US Federal Energy Regulatory Commission (FERC) issued a Notice of Proposed Rulemaking on standard market design (SMD) that would help states to set up efficient markets.

    12. Sunset Advisory Commission - Created in 1977, by the Texas Legislature to identify and eliminate waste, duplication, and inefficiency in government agencies. The 12-member Commission is a legislative body that reviews the policies and programs of more than 150 government agencies every 12 years.

    3. Business Case
    • The gradual resurgence of electric power retailing is going to alter the course of the smart grid. More and more, utilities will have to think of the smart grid as a platform. Not just a platform for delivering electrons, but also a platform for delivering "apps for electricity" – innovative bundles that combine electricity with other things.
    • Reasonable reliability at reasonable prices will not be enough. Consumers will gradually begin to clamor for a better value proposition. And to pressure utilities to give them access to the choices and options that will be available already in places such as Texas and the UK.
    • In a deregulated marketplace, the price of electricity fluctuates by the season, the weather, and by the time of day. Prices are governed by the amount of available generating capacity and the amount of demand. But consumers are charged just a flat fee for their use of electricity that does not vary with the cost of electricity that they are using. The technology for charging consumers varying prices based upon the time that they use electricity has not yet been developed and is several years away. Thus consumers are not encouraged to use electricity in an economically prudent way. Many economists believe that until there is a way for the demand for electricity to respond to changes in price, retail electricity deregulation will not be successful.
    • Someday demand will be so elastic that competition could work efficiently, and engineers will no longer need to worry about reliability.  Enormous amounts of intellectual energy have been poured into designing markets that can work in real time when the demand side of the market is not priced in real time.
      4. Benefits
      • Competitive marketplace among energy suppliers
      • Flexibility to create an energy strategy that suits your individual needs
      • Freedom to choose suppliers, products, prices and terms
      • Reliability-transmission and distribution regulated and guaranteed by the PUC
      • Price protection from market volatility and rising costs-budget certainty
      • Potential savings, including tax savings in some markets
      • Pricing Flexibility and Creativity
        • Low introductory promotional rates
        • 12 month Fixed Rate Plan
        • 3 month Fixed Rate Plan
        • Small Business 24 Month Fixed Rate Plan
        • Green, Month-to-Month Intro Rate
      • Improved Customer Service
        • Fewer Complaints
        • Lower Telephone Hold Times
        • Better Trained Agents
        • On-line Chat
      • Value Added Services
        • Air conditioning maintenance
        • Rewards programs

      5. Risks/Issues
      • Higher Consumer Prices - The states that deregulated retail prices had higher prices before deregulation began, perhaps that was their motivation.  However, the gap hasn't narrowed. In 1997, the states in the deregulated category had average rates that were 3.1 cents per kWh above rates in the regulated states (9.1 vs. 6.0). Unfortunately, the retail choice experience – complete with the combined effect of divestiture of utility generating assets, and exposure of retail consumers to wholesale rates set in RTO markets – has resulted in an even larger gap in 2009, with deregulated states paying, on average, rates that are 4.4 cents per kWh above rates in regulated states (13.0 vs. 8.6).

        Source: Energy Information Administration, Forms EIA-861 and EIA-826
        Deregulated states include: CA,CT,DC,DE,IL,MA,MD,ME,MI,MT,NH,NJ,NY,RI

      • Price Volitility - Because of the non-storability of electricity, supply and demand are very inelastic and prices are very volatile.

      • Lack of Demand Response - In addition to inelasticity, very low price-responsiveness of the demand-side gives suppliers natural market power. During peak-use hours, a supplier can indeed become pivotal, or essential, in meeting the demand, in which case he can ask for artificially high prices (which will raise the price for all the electricity sold at that point in space and time if the network operates in a single auction system as in the US Standard Market Design). Conversely a market share as low as 6% is sufficient for a seller to push prices higher by physically withholding its supply . This kind of artificial scarcity is known to be the cause of the 2001 winter disruption in California

      • Market Manipulation - After a 2007 independent auditing study, the Texas state PUC found TXU has abused the market by manipulating supply at peak periods during the Summer of 2005, raising energy costs $57 million adding $18 million in profits during that short term. The Dallas-based TXU Corp.’s market manipulation case was settled for $15 million and without an admission of wrongdoing by the company.
      • Oligarchy - Instead of improved competition, some countries that have implemented deregulation have witnessed a quick reintegration, which led to new non state-controlled electricity oligarchies that could easily extract surplus from consumers
      • Market Cooperation - Because electricity is hard to store, a great deal of coordination is necessary to meet customer demand. It takes time and money to stop and start units, so there has to be a degree of signaling between companies on when they need to move power, or make it.
      • Market Oversight - Of 30 Texas cases dealing with power market abuse in 2009, 29 were settled without the company admitting wrongdoing, the report noted. Without forcing restitution of some type, consumers have no recourse to recover damages from higher prices, the Sunset Commission said.The Sunset Commission found the Texas PUC Lacks Regulatory ToolsNeeded to Provide Effective Oversight and Prevent Harm to the Public.

        Since 1995, the Legislature has enacted laws restructuring electric and telecommunications industries from traditional rate regulated monopoly markets to markets open to competition. In these restructured markets, PUC relies on licensing-related functions to achieve oversight instead of focusing on rate regulation. These functions include granting businesses operating authority, resolving consumer complaints, and taking enforcement actions against violators. PUC still lacks a degree of regulatory authority necessary for effective oversight in these restructured markets. The agency lacks strong enforcement authority in limited areas to ensure that penalties serve
        as an effective deterrent and to immediately halt actions that are of eminent danger to the public.
        PUC’s limited oversight of certain telecommunications entities also suffers because the agency’s list of some regulated entities is inaccurate. This inaccuracy occurs primarily because no renewal process exists to ensure timely tracking and updates of the active status of these organizations.

        The Sunset Commission recommends the following changes in statute
        • Increase PUC’s administrative penalty authority from $25,000 to $100,000 per violation per day for electric industry participants’ violations of Electric Reliability Council of Texas’ (ERCOT’s) reliability protocols or PUC’s wholesale reliability rules.
        • Authorize PUC to issue emergency cease-and-desist orders to electric industry participants
        • Require PUC to provide for the renewal of registrations for Competitive Local Exchange Carriers and Interexchange Carriers
        • PUC should publish additional complaint and enforcement data related to the electric industry on its website
      • Externalities not included in Retail Price - In case of congestion, the power plants used to meet excess demand are often coal fired and have detrimental effects on the environment. The environmental cost is indeed not factored in electricity market prices which encourages producers to use cheap and dirty energy sources.
      • Reliability - One of the main ways that deregulated electricity markets could lower prices in the long term is the unavoidable reduction of monopolistic overcapacity by the market. This reduction in reserves and the higher risk of disruption associated with it is potentially so harmful that even fierce electricity liberals admit that it’s impossible to give the same breathing space to sellers as in another market.
      • Cost of Capital - The end of a state-controlled guaranteed rate of return for utilities combined with higher volatility of fuel prices has increased risk and hence the cost of capital, which causes insufficient generation and transmission investment and eventually congestion and higher prices
      6. Success Criteria
      • Freedom to engage in long-term contracts
      • Retail price flexibility
      • Competition at both the wholesale and retail levels
      • Effective cooperation between federal and state regulators to fix a variety of market imperfections and resulting market performance problems.

      7. Case Studies
      • Texas - In January of 2002, the Texas state legislature passed Senate Bill 7, opening up most of the state’s residential market to competition (the exceptions being large municipalities like Austin and San Antonio, and areas served by rural cooperatives, of which Texas has a large number). In the ensuing nine years, the market has developed in a vigorous manner, with customers able to choose today from more than 50 Retail Electric Providers (REPs) and more than 250 different electric plans, varying by term length (from month-to-month to as long as five-years), fuel type (varying mixes of fossil and renewable), and customer service type (traditional vs. on-line). There exists as well a lively debate as to whether competition has achieved its goals as set forth in the original legislation, i.e. a) greater breadth of available consumer products (little doubt on this score) and, b) reduced electricity prices (considerable debate on this one).
      • United Kingdom - The United Kingdom opened the electricity market by stages, from 30% in 1990 to 100% by 1998.

        The 1989 Electricity Act created a system of independent regulation, headed by the Director General of Electricity Supply (DGES) covering England, Scotland and Wales. The regulator’s principal roles are to ensure that competition develops smoothly and effectively and where competition is inappropriate, to protect customers. In 1999, the regulatory offices for electricity and gas (OFFER and OFGAS) were merged to form the Office of Gas and Electricity Markets (OFGEM). Northern Ireland has its own regulatory body, the Office for the regulation of Electricity and Gas (OFREG).

        The process of electricity deregulation has followed different paths in England and Wales, Scotland and Northern Ireland.

        The electrical industry in England and Wales has four principal components; generation, transmission, distribution and supply. Generation and supply are open to competition and price is not regulated. Transmission and distribution, which are natural monopolies, are subject to price regulation. The National Grid Company, the transmission network operator in England and Wales, has a central role in the industry. It has a statutory duty to develop and to maintain an efficient, coordinated and economic transmission system and to facilitate competition in supply and generation. Distribution remains a monopoly business and under the Utilities Act 2000 it has become a separately licensable activity. Nine distribution companies operate 12 authorised distribution areas.
      8. Companies
      1. Genability - San Francisco Startup - there are about 3,000 utilities in the U.S. with tens of thousands of electric rates devised for various classes of residential and commercial customers. And those rates fluctuate – about 3,500 rate updates occur every month, By assembling the electric rates, developing data-crunching tools, and offering the data to customers via a website, Genability is taking on a task that many solar service providers would rather avoid.

      2. Tradition Energy - One of the world’s largest energy procurement advisors to commercial, industrial and governmental organizations. Represented in 27 countries, Tradition employs over 2,500 people globally. Tradition is the interdealer broking arm of Compagnie Financière Tradition (CFT) and is listed on the Swiss stock exchange.
      3. Notable REP's in Texas include include: Glacial Energy, Kinetic Energy, Reliant Energy, Dynowatt, Texas Power, Ambit Energy , Bounce Energy, MXenergy, Direct Energy, Stream Energy, First Texas Energy Corporation, Gexa Energy, Cirro Energy, StarTex Power and TechStream Energy.
      9. Links
      1. http://www.cato.org/pubs/handbook/hb105-40.html

      2. Powertochoose.org - The official Electric Choice Website of the Public Utility Commission of Texas. Here you can learn about electric competition in Texas and shop for electricity provider

      3. Texas Sunset Commission - Final Report to the 82nd State Legislature pgs 113-118 February 2011

      4. http://www.energypolicyblog.com/2010/06/06/discussion-on-the-deregulation-of-electricity-markets/

      5. EcoPinion: Resurgence for Retail Electricity Choice and Competition? - EcoAlign, March 2011  After conducting 1,000 online surveys in March 2011, the EcoAlign consultancy found "overwhelming support for the concept of competition in the retail purchase of electricity."

      6. Revealing the Values of the New Energy Consumer Accenture, April 2011 Accenture surveyed more than 10,000 consumers around the world. It concluded that "price is the pivotal factor... but price alone will not drive adoption