Staff Seeks Authorty to File Comments in Resp to FERC's Notice Req Comments on Wholesale & Ret Comp Docket#AD05-17 issued 11/18/05
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STATE OF CALIFORNIA ARNOLD SCHWARZENEGGER, Governor

PUBLIC UTILITIES COMMISSION

505 VAN NESS AVENUE

SAN FRANCISCO, CA 94102-3298

January 5, 2006

Magalie Roman Salas

Office of the Secretary

Docket Room

Federal Energy Regulatory Commission

888 First Street, N.E., Room 1A, East

Washington, D.C. 20002

Re: Electric Energy Market Competition Task Force Docket No. AD05-17-000.

Dear Ms. Salas:

Enclosed for filing in the above-docketed case, please find an electronic filing of a document entitled "COMMENTS BY THE CALIFORNIA PUBLIC UTILITIES COMMISSION."

Thank you for your cooperation in this matter.

Sincerely,

/s/ Regina M. DeAngelis

Regina M. DeAngelis

Staff Counsel

RMD:mpg

UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION

Electric Energy Market Competition Task Force

    Docket No. AD05-17-000

COMMENTS BY THE CALIFORNIA PUBLIC UTILITIES COMMISSION

The California Public Utilities Commission ("CPUC") appreciates the opportunity to provide comments to the Federal Energy Regulatory Commission ("FERC" or "Commission") in response to its October 13, 2005 Notice Requesting Comments on Wholesale and Retail Electricity Competition in the above-referenced proceeding. According to Section 1815 of the Energy Policy Act of 2005, this Notice initiates the Electric Energy Market Competition Task Force's ("Task Force") study of competition in wholesale and retail markets for electric energy. In an effort to more fully apprise the Commission of pertinent issues unique to California, the CPUC is filing these comments past the due date. Because the Commission and the Task Force are at the early stages of preparing the study on wholesale and retail electric markets, this late filing will presumably not disrupt this proceeding, cause any prejudice to parties, or place any additional burdens on any other participants in this proceeding. Accordingly, the CPUC respectfully requests that its late-filed comments be accepted as part of the record in this proceeding. Furthermore, when the Task Force issues its draft study, the CPUC looks forward to the opportunity of providing additional comments.

COMMUNICATIONS

The names, titles, and mailing addresses of the persons to whom correspondence and communications concerning the above-captioned proceeding should be addressed are:

Regina M. DeAngelis, Staff Counsel

Public Utilities Commission of the
State of California
505 Van Ness Avenue, Room 4107
San Francisco, California 94102
(415) 355-5530

e-mail: rmd@cpuc.ca.gov


Bishu Chatterjee

Public Utilities Commission of the
State of California
505 Van Ness Avenue, 4th Floor
San Francisco, California 94102
(415) 703-1247

e-mail: bbc@cpuc.ca.gov

COMMENTS

Section 1815 of the Energy Policy Act of 2005 requires the Task Force to conduct a study of competition in wholesale and retail markets for electric energy. FERC's October 13, 2005 Notice seeks comments on several issues of wholesale and retail competition. In the comments herein, the CPUC responds to some of the "Overview Questions" set forth in the Notice:

Functional competition in wholesale electricity market should provide buyers and sellers with a level playing field, incentives to lower customer costs, more customer choice, improved market efficiency via lower heat rate in generation, and increased reliance on renewables. Another critical element of a competitive wholesale market is incentives to create a competitive long-term procurement process1 for utilities which results in adequate generation, reliability, and new investment.2 A wholesale competitive market should also function to curtail market power through clearly outlined market power mitigation rules.

Another important element for successful competition in the wholesale electricity market is the efficient functioning of the transmission network. The building of additions3 and upgrades to the transmission network along with complementary generation siting are far more important under a competitive regime than under traditional regulation. This is because transmission owners under competition need to support an increased number of transactions that originate from utility-owned as well as from non-utility-owned generators. Moreover, transmission owners must respond to these transactions on a non-discriminatory basis. In such circumstances, it is crucial that the regulatory framework sends the correct signals to transmission owners to properly maintain and upgrade their infrastructure that is, in turn, relied upon by the entire community of generators.

In California, most of the electricity load (about 46,000 MW peak reached in September 2004)4 is managed under the California Independent System Operator ("CAISO") control area on a non-discriminatory basis. While the major transmission owners, namely Pacific Gas & Electric Company ("PG&E"), Southern California Edison ("SCE") Company and San Diego Gas & Electric Company ("SDG&E"), do not operate the grid, they are directly regulated by the CPUC and regularly participate in the CAISO's processes. By virtue of their participation in the CAISO-controlled grid, these companies lack the ability to discriminate against non-utility users on those portions of the CAISO-controlled grid that they own.

It is important to point out, however, that the CAISO does not control all the California grid operations. Approximately 20% of California's power is provided by governmental entities that are not regulated by the CPUC, including one very large entity, the Los Angeles Department of Water and Power ("LADWP") and several other significantly large entities, such as the Sacramento Municipal Utility District ("SMUD") and the Western Area Power Administration ("WAPA"). These entities either never participated in the CAISO, such as LADWP, or once did belong to the CAISO but have subsequently withdrawn to form their own control areas, such as SMUD and WAPA. In California, the impact of such non-participation in the CAISO grid increases system costs per customer for the rest of the CAISO participating load. Accordingly, the problems associated with discrimination and inefficiency that prompted FERC to issue Open Access Transmission Order No. 888 may still exist in connection with these entities that do not participate in the CAISO.

Lastly, in order for wholesale competition to be effective the Task Force should also look at the interdependency between the electricity and gas markets. Anomalies in the gas market directly affect the operation costs of electricity generation, can place upward pressure on generation offer bids, and impact the efficiency and functionality of the wholesale electricity market.

The critical elements for retail competition are customer choice, lower prices, and market transparency. Consumer protection from market abuse is also crucial for a successful retail market. The successful implementation of a retail market for electricity is very much complemented by the successful implementation of a wholesale electricity market. Furthermore, a competitive retail market cannot be sustained if the wholesale market exhibits anti-competitive features such as local market power, for example, in areas with load and generation pockets, and market manipulation by market participants.

Due to the California energy crisis of 2000-2001, the pace of retail competition in the form of "Direct Access"5 was put on hold by the CPUC. However, progress in other areas related to retail competition has continued. At the same time, the CAISO has been focusing on the development of an efficient market and competition in the wholesale markets by adopting locational marginal pricing scheduled to start in April 2007, and additional local market power mitigation tools. The CPUC continues to be supportive of a fully competitive retail market along with a fully functional wholesale market for electricity. The CPUC's efforts to facilitate a smooth transition to increased retail competition are illustrated by several rulemakings that directly and indirectly encourage retail competition. These rulemakings are described in more detail below.

When California restructured its electricity market, customers were given the opportunity to either subscribe to "bundled service" from their regulated electric utility or obtain "Direct Access" or DA service from an electric service provider ("ESP"). In connection with the California energy crisis, the CPUC suspended the right of customers to enter into new contracts for Direct Access on September 20, 2001 by Decision No. 01-09-060. Direct Access usage today accounts for 12% of power delivered to California customers. This share is expected to remain stable during the period of time that the right to enter into new direct contracts is suspended in California.

Recently, the CPUC issued a decision on phase two implementation issues in the Community Choice Aggregation ("CCA") rulemaking. This rulemaking was initiated by the CPUC pursuant to California Assembly Bill ("AB") 117 to develop a program known as the CCA Program. The issues addressed by the CPUC in D.05-12-041 include customer notice requirements, operational protocols, and the determination of cost responsibility protocols for individual CCAs. This decision will enable cities and counties to aggregate load of electric customers within their jurisdictional boundaries and purchase power on behalf of the aggregated load. No CCAs are currently providing electric procurement services in California. However, two local governmental entities, the City and County of San Francisco ("CCSF") and the City of Chula Vista, have taken significant steps in their respective CCA program implementation plans. The CPUC believes that these two local governments are the closest to implementing their respective programs. If CCSF can meet various other milestones set forth in the AB 117, CCSF estimates that it can start delivering power to electric customers as soon as March 2007. The City of Chula Vista conducted a CCA program feasibility study in 2004 and determined that implementing a CCA program could save the City between $21 million and $122 million on a net present value basis from 2006-2023. These efficiency gains could be realized through the competitive procurement of power.

The table below shows California cities by utility service territory that are considering CCA.6

The CPUC initiated a rulemaking in 2002 to develop demand response as a resource to enhance system reliability, reduce power purchase costs and individual consumer costs, and further protect the environment. Through this rulemaking, the CPUC sought to make available a broad spectrum of demand response programs and tariff options to customers who would, in exchange, make their demand-response resources available to the electric system.

The first year of this proceeding resulted in two major CPUC decisions. Decision No. 03-03-036 adopted a Statewide Pricing Pilot ("SPP") to implement a pilot project to test the impact of time-of-use and critical peak pricing tariffs on residential and small commercial customer usage patterns. The second decision, Decision No. 03-06-032, adopted demand response programs for customers with load exceeding 200 kW and established annual megawatt targets to be met through demand response programs. The CPUC has recently adopted a more aggressive target for demand response megawatts for 2007, i.e., 5% of each utility's annual system peak demand.

Over the course of approximately three years, the CPUC, with the assistance of the California Energy Commission made significant progress in advancing the demand response agenda set forth in the CPUC's initial rulemaking. For example, recently the three investor-owned utilities ("IOUs") filed applications for authorization of their 2006-2008 demand response programs. Moreover, at this point, most customers in California with loads greater than 200 kW already have advanced meters, are served under time-of-use rates, and have the choice of a variety of dynamic rates and demand response programs. California is currently considering several proposals for the deployment of an Advanced Metering Infrastructure ("AMI") to all IOU customers to further advance demand response in the residential and small commercial customer sectors and also improve utility operations. Recently, PG&E has requested authority to deploy AMI in 2006 and SDG&E and SCE are seeking similar authority in separate proceedings.

Regarding critical peak pricing ("CPP"), most California residential and small commercial customers are not currently able to sign up for CPP rates with the exception of customers already enrolled in the experimental CPP program that was developed as part of the Statewide Pricing Pilot. Development of non-experimental time-differentiated tariff options for these customer classes will occur in the near future, and the CPUC has directed the three IOUs to include such tariffs in their next rate design applications. Furthermore, the Commission is considering the adoption of CPP tariffs as a default for customers with demand exceeding 200 kW.

The following table shows that between 2005 and 2006, the CPUC expects an increase in the MW available under demand response programs by the three IOUs. The MW set forth below could be technically curtailed under demand response programs in severe conditions.

Three Utility MW under Demand Response7

Utility

Baseline Potential MW May `05

Summer 2006 Potential MW

Incremental MW Gain `05-`06

SDG&E

82.9

243

160.1

PG&E

701.5

791

89.5

SCE

1313

1635

322

The CPUC also participated in a FERC technical conference in September 2005 connected to the CAISO's Comprehensive Market Redesign Proposal8 to explore tariff issues related to demand response options, including special case nodal pricing. In addition to demand response, generally, and special case nodal pricing, the issue of wholesale load choosing to opt out of Load Aggregation Points ("LAP")9 was also addressed at this conference.

Along with energy savings from the demand response program, the CPUC has initiated several important energy efficiency programs. In 2000, the CPUC adopted the Summer Energy Efficiency Initiative of 2000. As a result of the 2000-2001 energy crisis, the goal of this Initiative was to reduce the amount of electric and gas demand as quickly as possible. To achieve this goal, the CPUC allocated $72 million in public goods charges, a fee collected on all customer bills, to fund energy efficiency and other demand reduction programs. More recently, on September 22, 2005, the CPUC approved $2 billion in funding for the energy efficiency portfolios of the four IOUs10 to be spread over the three years, 2006-2008. With this augmented funding, the IOUs' cumulative estimated incremental annual savings by 2008 will be 7,334 GWh in electricity energy and 121,989 Mt of gas use. The gross total savings to ratepayers (including avoided transmission, distribution, electric generation and natural gas costs) will be approximately $5.4 billion over the three-year cycle. Considering a total cost estimation of approximately $2.7 billion, including customer out-of-pocket costs, the total investment in energy efficiency will result in about $2.7 billion in net resource benefits. Additionally, the 2006-2008 programs will result in avoided greenhouse gas emissions by an estimated 3.4 million tons of carbon dioxide by 2008.

The IOUs' 2006-2008 program portfolios include a wide array of energy efficiency and conservation programs across all market sectors. Examples include point-of-purchase and on-line rebates for energy efficient lighting, Energy Star appliances and HVAC systems, financing strategies, energy audits for homes, schools and businesses, local government partnerships, and marketing, education and outreach programs designed to inform customers about options to conserve energy and save money. These programs will be available to customers starting in the first quarter of 2006.

In order to foster more customer choice and retail competition, the CPUC initiated the distributed generation (DG) proceeding in 2004 with the goal of aggressively reducing peak energy demand through a self-generation incentive program. Under phase one, of the CPUC's plan (2001 through 2005), the CPUC sought to have 39 MW of renewable distributed generation projects installed and 83 MW of small cogeneration installed. During phase two of the CPUC's plan (2006 through 2007), the CPUC seeks to accomplish the following goals: (1) implement the emissions and efficiency standards required by California Assembly Bill 1685 and (2) evaluate program impacts such as load reduction, utilization of waste heat, and overall costs and benefits, and consider adjusting funding levels and incentive payments to increase participation.

The CPUC also directed IOUs to incorporate DG into long-term resource plans and submit implementation plans to consider DG as an alternative to traditional distribution investments. In order for the DG program to be successful, the CPUC has the following critical criteria: adopt tariffs to reflect various levels of grid use by DG customers, develop a cost-benefit methodology to help agencies, utilities and DG installers assess the economics of a DG project, ensure that utility interconnection rules are applied consistently and fairly across the state, and consolidate DG data collection and improve public dissemination.

3(a). What benefits have occurred because of competition in wholesale and retail

electricity markets?

As a result of the California energy crisis of 2000-2001, California customers have not experienced the potential benefits of a competitive market such as increased reliability, the lowering of costs, and a full-fledged competitive retail market. Except for a few years prior to the energy crisis of 2000-2001, California has not been open to additional retail competition in the form of Direct Access. Accordingly, the full benefits of retail competition cannot be captured now. The chart below shows the estimated rates charged to customers of California's three IOUs on a per/kW hour basis. The chart also shows that restructuring and wholesale competition have not lowered costs to California ratepayers.

Estimated Three Utilities Average Electricity Rates (cents/kW hr of electricity)

for Residential Customers from 2000 to 200511

Year

2000

2001

2002

2003

2004

2005

PG&E

10.7

12.8

13.3

13.2

12.7

12.85

SDG&E

10.32

11.34

13.67

14.33

14.32

14.49

SCE

12.8

15.4

16.19

14.55

12.55

12.98

3(b). What additional benefits are expected?

The CPUC believes that robust competition will force inefficient generation units to retire and add more efficient generation including renewable generation. Competition will also provide more transparency in the market and, yield finally, systematic cost savings and service reliability to ratepayers.

California ratepayers have yet to realize the true benefits of lower costs and increased reliability in electricity services as a result of competition. The CPUC believes that as the market becomes more restructured, individual market participants should be made more accountable to the states, FERC, and customers. Similarly, in a competitive market construct, FERC should not encourage a higher return on equity for private transmission companies. Higher returns for unregulated companies (such as merchant transmission companies) will compensate transmission owners more than the embedded costs needed to recover the return on transmission investment. In sum, such higher returns will create a disparity in the market given that the basic nature of the transmission business as compared to the generation and distribution businesses provides lower risk and more certainty in returns.12 Overall, the CPUC encourages this Task Force to avoid making market rules that may harm the spirit of competition and create a situation of cross-subsidy payments from ratepayers to electricity transmission and generation owners.

January 5, 2006 Fax: (415) 703-2262

CERTIFICATE OF SERVICE

I hereby certify that I have this day caused the foregoing document to be served upon all known parties of in this proceeding by mailing by first-class a copy properly addressed to each party.

Dated at San Francisco, California, this 5th day of January, 2006.

1 The CPUC has been working with issues such as resource adequacy and reserve requirements, market structure, financial capabilities, long-term planning framework, and data confidentiality to encourage competitive long-term procurement by utilities. For details on the load serving entities' competitive procurement process, please refer to Decision No. 04-12-048, R.04-04-003, Opinion Adopting Pacific Gas and Electric Company, Southern California Edison Company and San Diego Gas & Electric Company's Long-Term Procurement Plans, December 16, 2004.

2 On December 15, 2005, the CPUC opened a new rulemaking, R. 05-12-013, for the purpose of expanding upon the resource adequacy requirements adopted by the CPUC in a prior rulemaking, R.04-04-003, and to focus on specific issues such as local resource adequacy requirements.

3 For new transmission projects the CAISO uses a common methodology called Transmission Economic Assessment Methodology ("TEAM") to evaluate the economic need for transmission projects within California. This methodology compares the expected project benefits to the costs to ratepayers, producers, and transmission owners.

4 See, CAISO Department of Market Analysis 2004 Annual Report, April 2005.

5 In California, Direct Access or DA means that customers purchase electricity from an Electric Service Provider ("ESP") instead of a regulated electric utility. The CPUC suspended DA on September 20, 2001 by Decision No. 01-09-060. According to the CPUC, DA service is not currently available to "new" customers and will not be until all the Department of Water Resources long-term power contracts purchased during the energy crisis expire. Pursuant to California Assembly Bill 1X (2001) and California Water Code Section 80110, these contracts must expire before DA suspension is lifted. Currently, a certain select group of customers are eligible for DA service, including customers that were receiving DA service as of September 20, 2001 or those who had a DA contract in effect as of September 20, 2001. Such DA eligible customers may switch between ESPs or return to bundled utility service pursuant to the DA Switching Exemption rules set forth in CPUC Resolution E-3843, Decision No. 03-05-034, as subsequently modified.

6 Source: CPUC Energy Division.

7 Source: The three California IOUs.

8 California Independent System Operator, Inc., 112 FERC P61,013 at ¶39 (2005).

9 Id. at ¶37 ("[E]ach wholesale customer should have the option of establishing, as a separate zone, the set of nodes where it receives energy....")

10 PG&E, SDG&E, SCE, and Southern California Gas

11 Source: Estimates by CPUC Energy Division and Utilities.

12 Of the three utility functions, the generation business is considered the most risky and the distribution business follows. Transmission is considered the least risky. A Standard & Poor's ("S&P") report described how the rating criteria for utilities are determined by explaining: " [S&P] analytical groups choose various ways to express these scores [overall financial risk profile]: Some use letter symbols, while other use numerical scoring systems. For example, utilities' scoring is from 1 to 10 - with 1 representing the best. Companies with a strong business profile - typically, transmission/distribution utilities - are scored 1 through 4; those facing greater competitive threats - such as power generators - would wind up with an overall business profile score of 7 to 10." See, Standard and Poor's Report on Corporate Ratings Criteria: June 2003, p. 17, The McGraw-Hill Companies, New York.

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