Glossary

AB 1890: Assembly Bill 1890 which was signed into law on September 23, 1996 as Chapter 854 of the Statutes of 1996. AB 1890 provides the legislative guidance for restructuring of the electric industry in California.

Aggregator: any marketer, broker, public agency, city, county, or special district, that combines the loads of multiple end-use customers in facilitating the sale and purchase of electric energy, transmission, and other services on behalf of these customers.

Broker: an entity that arranges the sale and purchase of electric energy, transmission,

and other services between buyers and sellers, but does not take title to any of the power sold.

CEP: the customer education program.

Competitive Transition Charge (CTC): a nonbypassable charge on each customer of the distribution utility, including those who are served under contracts with nonutility suppliers, for recovery of the utility's transition costs.

Consumers: the end-users of electricity, who may be served either by the utility distribution company or by a non-utility, retail electric service provider.

Customer Education Program (CEP): the educational effort required under Public Utilities Code Section 392, which requires electric corporations, in conjunction with the CPUC, to devise and implement an education program that informs customers of the changes to the electric industry.

Direct Access Transaction: a contract between any one or more electrical generators, marketers, or brokers of electric power and one or more retail customers providing for the purchase and sale of electric power or any ancillary services.

Electric Service Provider: an entity which provides electric service to a retail or end-use customer, but which does not fall within the definition of an electrical corporation under Section 218.

Generators: those entities which will design, construct, own, operate, and maintain generation assets to supply energy and ancillary services to the competitive market.

Independent System Operator (ISO): The ISO is responsible for the operation and control of the statewide transmission grid.

Marketer: any entity that buys electric energy, transmission, and other services from traditional utilities and other suppliers, and then resells those services at wholesale or to an end-use customer.

Power Exchange (PX): the entity that will establish a competitive spot market for electric power through day and hour ahead auction of generation and demand bids.

Public Goods Charge (PGC): a nonbypassable surcharge imposed on all retail sales to fund public goods research, development and demonstration, and energy efficiency activities, and possibly to support low income assistance programs.

Retailers: an electric service provider who enters into a direct access transaction with an end-use customer, i.e., aggregators, brokers, and marketers.

Scheduling Coordinators (SCs): entities certified by the Federal Energy Regulatory Commission that act as a go-between with the ISO on behalf of generators, supply aggregators (wholesale marketers), retailers, and customers to schedule the distribution of electricity.

Supply Aggregators: also known as wholesale marketers. These entities act on behalf of generators to arrange and implement commercial transactions in the competitive generation supply market.

Small Commercial Customer: a customer that has a maximum peak demand of less than 20 kilowatts.

Virtual direct access: also known as the hourly PX rate option. This rate option allows customers to purchase electricity on a rate schedule that reflects their usage in real time or time of use increments based on the PX price.

Utility Distribution Companies (UDCs): the entities which will continue to provide regulated services for the distribution of electricity to customers and serve customers who do not choose direct access.

NOTES

(1) For a detailed procedural history of this proceeding, see pages 19 and 24, and Appendix B of D.95-12-063, as modified by D.96-01-009.

(2) Assembly Bill 1890, as enacted (Stats. 1996, ch. 854.), added Section 330 to the Public Utilities Code. Subsection (k) of that code section reiterates the importance of the separation of these three functions. Subsection (k) provides: "In order to achieve meaningful wholesale and retail competition in the electric generation market, it is essential to do all of the following: (1) Separate monopoly utility transmission functions from competitive generation functions, through development of independent, third-party control of transmission access and pricing. (2) Permit all customers to choose from among competing suppliers of electric power. (3) Provide customers and suppliers with open, nondiscriminatory, and comparable access to transmission and distribution services."

(3) Unless otherwise noted, all "section" references are to the Public Utilities Code, as amended by AB 1890.

(4) CellNet's reply comments to the August 30, 1996 DAWG Report was filed with the Docket Office.

(5) A schedule coordinator who interacts directly with end use customers as an aggregator, broker, or marketer would also be considered a retailer.

(6) Retailers and the UDCs will compete against each other to serve end-use consumers. In addition some retailers may also have a wholesale business. For example a marketer could sell power to other retailers, to utilities in the wholesale market and also to end-use consumers in the retail market.

(7) Section 365(b)(1) provides in part that direct access transactions shall commence simultaneously with the start of the ISO and PX. This "simultaneous commencement shall occur as soon as practicable, but no later than January 1, 1998." Should the ISO and PX be up and running before January 1, 1998, then direct access should also be permitted.

(8) We recognize that the terms and conditions of direct access may evolve as more definitive decisions regarding certain aspects of direct access are issued. A process to address the issues associated with the pro forma tariffs shall be established in an assigned Commissioners' ruling or in an ALJ ruling.

(9) This meeting could be held in conjunction with the workshop on the retail information management plan (RIMP), which is discussed later in this decision.

(10) In implementing Section 365(b)(2), the Legislature clearly expressed a preference for any customer with at least one-half of its electrical load supplied by a renewable resource provider with respect to any phase-in of direct access. In implementing full direct access, this preference should be preserved, and such requests should go to the front of any queue in processing direct access requests.

(11) We encourage the ISO to develop specific plans for various contingencies if it thinks such advance plans are needed in order to allow it to react quickly should such a contingency arise. Should such contingency plans be developed by the ISO, the Commission recommends that the ISO inform the Commission of these contingency plans in advance of such an emergency so that the Commission can react quickly if needed. No contingency plan that limits a customer's participation in direct access will be implemented without this Commission's express approval as a result of the ISO declaring an emergency.

(12) According to Cellnet's comments to the ALJ's proposed decision, there are also approximately an additional two million electric meters in California which are served by the municipal utilities.

(13) The ALJ's proposed decision had originally recommended that customers with a maximum demand equal to or greater than 50 kW be required to have a meter capable of hourly metering in order to participate in direct access. Several of the parties' comments to the ALJ's proposed decision recommended that this cut-off be lowered to 20 kW to correlate with AB 1890's definition of a small commercial customer, to more closely reflect the current tariff schedules of customer classes, and to lessen the potential for cost shifting that could occur if customers whose maximum demand was 20 kW to 50 kW were able to use load profiles. For those reasons, we have reduced the cutoff point to 20 kW. We will also consider whether load profiles for certain customers whose maximum demand is equal to or greater than 20 kW, but less than 50 kW should be permitted. The possibility of those kinds of exceptions should be addressed in the load profiling workshop discussed later in this decision.

(14) Our reference to the term "hourly metering" or "hourly interval meter" is intended to include existing meters that can be retrofitted to record usage on an hourly basis, hourly meters that can be read monthly or daily, hourly meters capable of being read remotely, hourly meters with two-way communications capabilities, and other metering technologies that might develop.

(15) The issue of master meters and direct access facilities will be addressed in a subsequent decision.

(16) We note that this does not prevent a retailer or other direct access provider from picking up all or part of this cost.

(17) A customer whose account has a maximum demand of less than 20 kW may choose to install an hourly meter to take advantage of direct access. In order to participate in virtual direct access, now referred to as the "hourly PX rate option," such customers shall be required to have an hourly meter. The hourly PX rate option allows such customers to purchase electricity on a rate schedule that is reflective of their usage in real time or time of use increments based on the PX price.

(18) One of the pending issues in the consolidated ratesetting applications, A.96-12-009, A.96-12-001, and A.96-12-019, commonly referred to as the unbundling proceeding, is whether the rate freeze prohibits any actual bill savings from occurring.

(19) The Preferred Policy Decision allowed these three customer groups to voluntarily install such meters if they elect to participate in direct access, or avail themselves of the virtual direct access billing option. (Preferred Policy Decision, p. 78.)

(20) Unless otherwise noted, the same limited service requirement shall apply to all the other workshop reports and comments to the workshop reports that have been ordered in this decision.

(21) As stated in footnote 13, we will also consider whether load profiles for certain customers whose maximum demand is equal to or greater than 20 kW, but less than 50 kW should be permitted.

(22) No evidentiary hearing will be held unless the party requesting such a hearing can demonstrate that a material issue of fact needs to be resolved by the Commission.

(23) We agree with TURN's comments to the ALJ's proposed decision that depending on how the "positive written declaration" requirement is worded, such a declaration could serve as the "document fully explaining the nature and effect of the change in service" described in Section 366(d)(3) for small commercial customers, or such a declaration can be used in conjunction with Section 366(e)(4) for residential customers.

(24) There is a need to ensure that aggregators cooperate with the UDCs and the scheduling coordinators since the aggregators and the UDCs will be sharing their loads on common transmission and distribution facilities.

(25) As noted below, a workshop will be held on the CEC's suggestion that a retail information management plan be adopted. Parties could address these kinds of issues at that workshop, or they can endeavor to resolve these issues earlier.

(26) In its comments to the ALJ's proposed decision, the Merced Irrigation District raised the question as to whether the procedures set forth in Section 366(d) and (e) apply to it if a small commercial or residential customer of PG&E elects to take electrical service from it. Those subdivisions do apply in such instances.

(27) Section 366(d)(1) is unclear whether the independent third-party verification was intended to refer to the independent third-party verification company referred to in Section 366(e). We assume that it did, and therefore the verification required under Section 366(d)(1) shall follow the procedures set forth in subdivisions (e)(1), (e)(2) and (e)(3) of Section 366.

(28) The responsibility for service connection and disconnection may change if metering services are unbundled.

(29) AB 1890 specifically exempts certain kinds of transactions from the payment of any transition costs. For example, transition costs "shall not be recoverable for new customer load or incremental load of an existing customer where the load is being met through a direct transaction and the transaction does not otherwise require the use of transmission or distribution facilities owned by the utility." (Section 369.) Another exemption is provided for in Section 374, which exempts certain kinds of transactions with irrigation districts from the transition costs.

(30) The requirement that marketers inform customers of the written confirmation requirement terminates on January 1, 2002. (Section 370.)

(31) The direct access implementation plans of the UDCs could be integrated into the RIMP.

(32) EPUC/CAC also contend that AB 1890 does not provide the Commission with any authority to hear or resolve such complaints.

(33) The term "small commercial customer" is defined in Section 331(h) as "a customer that has a maximum peak demand of less than 20 kilowatts."

(34) The UDC is exempt from the registration procedures set forth in Section 394. (Section 394(a).)

(35) We will continue to monitor the development of the market for services such as energy efficiency and load management, and similar types of services, and the relationship between the providers of such services and the electric service providers. The Commission may need to revisit this issue as the market for such services matures.

(36) The Commission currently charges an applicant fees ranging from $75 to $1000 depending on the type of authority the applicant is seeking.

(37) This registration requirement also applies to schedule coordinators acting as an aggregator, broker, marketer, or other entity offering electrical service to residential or small commercial end use customers.

(38) The Commission's web site address is: www.cpuc.ca.gov.

(39) As part of our consumer protection rules, we favor a requirement that registrants be required to list their registration number on any advertising or marketing information.

(40) The failure to register under Section 394 could also trigger the exercise of these provisions.

(41) Section 395 provides as follows:

"(a) In addition to any other right to revoke an offer, residential and small commercial customers of electrical service, as defined in subdivision (h) of Section 331, have the right to cancel a contract for electric service until midnight of the third business day after the day on which the buyer signs an agreement or offer to purchase.

"(b) Cancellation occurs when the buyer gives written notice of cancellation to the seller at the address specified in the agreement or offer.

"(c) Notice of cancellation, if given by mail, is effective when deposited in the mail properly addressed with postage prepaid.

"(d) Notice of cancellation given by the buyer need not take the particular form as provided with the contract or offer to purchase and, however expressed, is effective if it indicates the intention of the buyer not to be bound by the contract."

(42) This bill formatting requirement is in addition to any other bill format that the unbundling proceeding may adopt.

(43) See discussion regarding "Other Direct Access Implementation Costs."

(44) See decision text for resolution of the motion of CLECA/CMA for leave to late file their reply comments to the August 30, 1996 DAWG Report.

(45) See decision text for resolution of Cellnet's opening comments to the 8/30/96 DAWG Report.