February 13, 2007 Response to Committee Questions

CALIFORNIA PUBLIC UTILITIES COMMISSION

RESPONSES TO QUESTIONS IN PREPARATION
FOR THE FEBRUARY 13, 2007 HEARING OF
SENATE ENERGY, UTILITIES AND COMMUNICATIONS COMMITTEE

Q1. Please provide a comparison of current and year 2000 electric rates for each of the three largest investor-owned utilities for each of the following classes:

• Residential (non-CARE), by tier
• Residential (CARE)
• Small Commercial
• Industrial
• Agricultural
• System Average

Why do rates remain so high? Please identify the significant factors driving rate increases. What actions can the CPUC and utilities take to reduce electric rates to pre-Energy Crisis levels?

(Please update the charts provided as Attachment 1, Charts 1-3, and Attachment 4, Tables 1-6, in your response to questions from the Committee for its February 22, 2006 hearing.)

Answer:
A detailed comparison of rates effective January 2007, and rates for year 2000, for Southern California Edison Company (SCE), Pacific Gas and Electric Company (PG&E), and San Diego Gas & Electric Company (SDG&E) is provided in Table 1 and in Attachment 1, which includes updates to electricity and natural gas rate charts provided to the Committee in February 2006. Attachment 1 includes detailed information on rates for various customer classes for the years 2000 and 2007.The data below highlights some key elements about rates.

System average electric rates for all the three major electric utilities are higher as of January 2007 compared to the year 2000 average rate.

Power generation and power purchase costs are the largest component of electric rates, followed by distribution system costs. Aging distribution infrastructure and need for transmission expansion requires increased capital investments. Additionally, Public Purpose Program funding, which includes funding for CARE programs, has expanded substantially from the year 2000 to 2006. 

Power generation/purchase costs account for more than 50% of the utilities’ total annual revenue requirements (in millions)

Average monthly gas prices rose by 86% from 2000 to 2006 which resulted in substantial increases in cost of power generation/purchases. High electric generation and purchased power costs are driven primarily by high gas prices. Average monthly NYMEX gas settlement prices were 86% higher in 2006 than in 2000.

The Commission has taken several steps to mitigate the impact of rising natural gas costs on customers’ bills.

• Implementing the Energy Action Plan loading order: The loading order identifies energy efficiency, demand response, renewable resources and distributed generation as the State’s preferred means of meeting growing energy needs.
  
  Because nearly 50% of natural gas consumed in California is used to generate electricity, cost-effective electric energy efficiency dampens California’s demand for natural gas.
  
  Renewable generation under the RPS program provides resource diversity and can provide a hedge against natural gas prices
   
• Implementing AB 57 and AB 1576. The Commission strictly scrutinizes utility long term power procurement plans in accordance with these statutes. Most procurement is undertaken pursuant to solicitation processes that maximize competition among potential suppliers and are intended to minimize cost to ratepayers.
  
  On the gas side the Commission is promoting adequate access to diverse gas supply sources including LNG. The Commission has taken several measures to assure that adequate infrastructure exists to provide California utilities and customers customers’ unconstrained access to a diverse portfolio of natural gas supplies, including new liquefied natural gas supplies, expected to begin flowing to California in 2008.
   
• Helping residential customers manage their gas bills and reduce price volatility by authorizing gas hedging. For example, CARE eligibility for gas customers was enhanced in the winter of 2005-2006, expanded natural gas hedging programs were adopted in 2005, and a PG&E gas 10/20 program was first adopted in 2005.

The Commission will continue to critically evaluate the utilities’ procurement activities and operational costs proposed in general rate cases and other Commission and FERC proceedings to ensure that they provide safe and reliable service at the lower possible costs.

Table 1. Electricity Rate Comparison

January 2007 versus Year 2000
(Cents per kilowatt-hour, unless noted otherwise) 

Q2. How long will the current AB 1X rate protections relating to the first 130% of residential baseline usage be in effect? At what point will the Commission consider raising these residential rate tiers?

Answer:
Water Code section 80110 provides that the rate protections relating to the first 130% of residential baseline usage shall remain in effect “until such time as [DWR] has recovered the costs of power it has procured for the electrical corporation’s retail end use customers.” Pursuant to the Rate Agreement entered into between the Commission and DWR, DWR shall receive two streams of revenue from electric customers – the Bond Charge and the Power Charge. (See Opinion Adopting a Rate Agreement Between the Commission and the California Department of Water Resources (“Rate Agreement Decision”) [D.02-02-051] (2002) __Cal.P.U.C.3d __.) Both the Bond Charge and the Power Charge are to recover the costs of power procured by DWR in response to the energy crisis. (See Rate Agreement Decision [D.02-02-051], at pp. 40 & 49.)

Although the statutory language concerning the end of the rate protection does not provide a date certain, prior Commission action indicates that the termination date is tied to termination of the Bond Charge. Under the Rate Agreement, the Commission cannot terminate the Bond Charge on its own without risk of being in default. (Rate Agreement Decision [D.02-02-051], Appendix C, pp. 9 (Section 5.1(a)) & 13 (Section 8.1) (slip op.).) The Rate Agreement, and the Bond Charge, shall terminate “when payment of the Bonds and all other Bond Related Costs required to be paid by [DWR] under the Financing Documents have been made or provided for in accordance with the Financing Documents.” (Rate Agreement Decision [D.02-02-051], Appendix C, p. 14 (Section 9.1) (slip op.).) Section 5.1(a) of the Rate Agreement is irrevocable. (Rate Agreement Decision [D.02-02-051], p. 92 (Ordering Paragraph No. 3.).) Consequently, the earliest that the Commission can consider termination of the AB 1X rate protection is 2022.

Q3. A recent petition invited the CPUC to investigate “reopening” direct access, which was suspended in 2001 pursuant to statute (Section 80110 of the Water Code). At what time do you believe the direct access suspension will lift according to the terms of the statute? Do you believe there are any circumstances other than those described in the statute under which the suspension can be lifted without further legislative action?

Answer:
The questions posed relate directly to issues raised in the petition for rulemaking. As the Commission has yet to make a determination whether to grant the petition, to take a position at this point could be seen as prejudging the issues.

Water Code section 80110 specifies that direct access shall be suspended “until [DWR] no longer supplies power.” DWR currently serves as the credit-worthy counterparty to the power purchase contracts, and various provisions within the Water Code suggest that DWR will continue to “supply” power until these contracts expire. For example, Water Code section 80110 states that DWR is the “owner” of the power sold under the contracts; Water Code section 80110 provides that “all money collected with respect to any power acquired and sold” pursuant AB 1X is property of DWR; Water Code section 80104 states that retail end use customers are deemed to have purchased power from DWR. Thus, it appears that the suspension of direct access could not be lifted until 2015, when the last power purchase contracts expire.[2] A consideration at this point, however, is whether the statute would permit the Commission to phase out the suspension of direct access as the DWR power purchase contracts expire, rather than wait until all the power contracts expire. In this respect, the Commission would appreciate any direction and guidance provided by the Legislature.

The Commission can also note that Water Code section 80110 distinguishes between the duration of the suspension of direct access and the duration of the rate protection for residential baseline customers. Direct access shall remain suspended until DWR no longer supplies power, while the AB 1X rate protection for residential baseline customers remains in place until DWR has recovered the cost of power it has procured. Therefore, it appears that that the suspension of DA could be lifted before or at the same time as termination of the AB 1X rate protection.

One of the circumstances under which the suspension might be lifted sooner without further legislative action is if there was novation of the power purchase contracts so that the investor owned utilities (IOUs), and not DWR, serve as the credit-worthy counterparties to the contracts. However, it is unknown the extent to which the contracting parties, as well as the IOUs, would be willing to agree to novation. Further, not all the power purchase contracts contain novation clauses.

Q4. While a “20% by 2010” Renewables Portfolio Standard (RPS) has been formally enacted, reports suggest a lag in bringing new renewable projects online and that utilities are not on pace to achieve 20% by 2010. Recent filings show that ESPs subject to the same requirement have procured virtually zero renewable energy. Do you believe all retail sellers will achieve 20% by 2010 under the current RPS framework? What actions are necessary to achieve this goal?

Answer:

IOUs Have Made Substantial Progress but 20% by 2010 Will be Challenging

In 2006, actual renewable deliveries stood at 12%, 16.7%, and 5.3% of the retail sales of California’s three large utilities: Pacific Gas & Electric, Southern California Edison, and San Diego Gas & Electric, respectively. These IOUs are actively signing contracts for more RPS generation, but, pursuant to RPS legislation, the Commission uses actual deliveries, not contracted capacity, as the metric to determine RPS compliance. The IOUs are closing in on the 20% target, with 4 years of procurement ahead. Each IOU also has short-listed 2005 and 2006 bids and contracts pending approval at the Commission that represent a significant potential increase in RPS generation. Based on Commission-approved and short-listed contracts to date, PG&E, SCE, and SDG&E are forecasted to achieve the 20% RPS goal in the 2010 – 2012 timeframe. 

CPUC is Actively Engaged in RPS Project Development Process

To ensure that the IOUs’ RPS contracts result in actual renewable generation, the Commission tracks each project’s progress in meeting its milestones, and concurrently, strives to facilitate project development by ensuring adequate transmission is being built in a timely fashion. The Commission is less able, however, to mitigate risk posed by such factors as deployment of new technology and cannot ensure permitting by other governmental agencies. Ultimately, it is the responsibility of the RPS-obligated load-serving entities to achieve the 20% by 2010 goal by procuring from viable renewable projects.

CPUC Decisions Provide the ESPs Several Avenues for Achieving the 20% by 2010 Goal

With regard to electric service providers (ESPs), SB 1078 (Sher) created a phase-in process for ESP RPS procurement targets, with the potential for an ESP to begin assuming its RPS obligations as early as January 2003. SB 107 (Simitian) changes the initial date of ESPs’ obligations to be January 2006 across the board. As a group, ESPs currently provide about 0.25% of their retail sales from renewable resources. 

SB 107 (Simitian) and Commission decisions provide the ESPs several avenues for achieving the 20% by 2010 goal, e.g., long-term contracts, short-term contracts, procurement entities, and Renewable Energy Credit (REC) trading. Ultimately, it is the responsibility of the ESPs to achieve the 20% by 2010 goal or face RPS procurement penalties.

Where do you expect this new renewable energy to come from? Do you believe that buying renewable energy or credits from energy colonies outside of California is a satisfactory approach to achieving California’s RPS?

Answer:
In The Near Future, Renewable Energy Will Come from New and Existing Facilities Located In or Near California.

With the recent passage of SB 107, LSEs will soon be able to access additional renewable resources located outside of California. In addition, SB 107 authorizes the use of RECs to comply with the RPS procurement requirements. However, out-of-state REC trading will not be an immediate panacea for LSEs with RPS-procurement obligations:

a. Full implementation of a REC trading system will require considerable work and coordination from the Commission and the CEC such as the mandated demonstration of energy delivery associated with any RECs used for RPS compliance.

b. SB 107 requires that the CEC’s WREGIS tracking system be fully functional before REC trading can commence.

Q5. Please describe the CPUC’s recent actions in the area of utility greenhouse gas emissions. Please report specifically on the status of implementation of SB 1368 (Perata).

Answer:
In April, 2006, the Commission opened a greenhouse gas rulemaking (R.04-06-009) as follow-on to our conceptual decision to implement a load-based cap on electric utility greenhouse gas emissions. That proceeding has been divided into two phases:

• Phase 1, which was designed to implement an emissions performance standard. In October of 2005, both the Commission and the California Energy Commission (CEC) adopted policy statements with an intent to develop an emissions performance standard such as the one that has now been codified as SB1368 (Perata).
   
• Phase 2, which was designed to implement the load-based emissions cap for which the Commission adopted parameters in February 2006 (in D.06-02-032).

Phase 1 began in April 2006 with a round of comments from parties. In June 2006, the Commission staff held three days of workshops to help parties reach consensus on the details of an emissions performance standard (EPS) policy that could be adopted by the Commission. Parties offered another round of comments after the workshops, and Commission staff produced a final workshop report with staff recommendations on October 2, 2006. SB 1368 was signed shortly before production of the final staff report in late September 2006, which necessitated the Commission developing additional record with comments from parties to address areas where the workshop consensus recommendations differed from the final outcome of SB 1368 provisions and requirements.

A proposed decision incorporating SB1368 requirements and parties’ comments was mailed for public review on December 13, 2006 and the Commission adopted the standard on January 25, 2007.

In parallel, we are also working closely with the California Energy Commission (CEC) to ensure that the EPS we adopt is consistent, wherever possible, with the EPS that the CEC is required by SB 1368 to adopt for the publicly-owned utilities. The CEC held a workshop on December 11 in which Commission staff participated. Another public workshop at the CEC was held January 11.

Substantively, there are a small number of differences between my proposed EPS rules (I am the assigned commissioner at the Commission) and those proposed by the CEC staff. Some of these differences reflect the different situations and facts of the situation related to the publicly-owned utilities procurement practices. For example, one major difference is that investor-owned utilities do not typically sign long-term contracts with financial intermediaries for system power, whereas some publicly-owned utilities do. Due to this situation, the technical details of how to account for the emissions characteristics of a contract where the underlying generation resource is not specified in the contract will be more complex for the CEC’s EPS than the Commission’s. That is just one example. Our staffs are diligently working together to make the EPS standards as consistent as possible.

We have also consulted extensively at the staff level with both the Air Resources Board and the California ISO on the implementation of the EPS and believe we have their support in our approach to the EPS.

Q6. As AB 32 (Nunez) is implemented, how will the CPUC coordinate and/or modify its preexisting activities to avoid duplication and inconsistencies with the Air Resources Board and other agencies?

Answer:
For Phase 2 of the Commission’s greenhouse gas rulemaking, we have been working very closely with the California Environmental Protection Agency (Cal EPA) and the Air Resources Board (ARB) to develop a common understanding and approach to implementation of AB 32. I believe we have reached agreement that the Phase 2 of the Commission’s rulemaking will be the venue to develop a uniform set of recommendations to the ARB for the electricity and natural gas sectors for implementation of AB 32. I believe that this is consistent with the provisions of the law and is a practical approach. We intend to continue working very closely with the CEC to ensure that our investigation and rulemaking will result in recommended rules for adoption (by the Commission for IOUs and the ARB for publicly-owned utilities) that work for all players in the electricity and natural gas markets, and not just those we regulate. I believe that this is the most efficient and expeditious way of addressing rules for the electricity and natural gas sectors, since the Commission and CEC can be engaged in careful investigation and rulemaking for these sectors while the ARB and Cal EPA are focused on other aspects of AB 32 implementation, including for many other industries.

I expect that the outcome of the Commission’s proceeding (with constant coordination, consultation, and input from the ARB, CEC, and Cal EPA) will become a subset of the larger emissions policy of the State of California under development by ARB. We intend to conduct our proceeding in parallel and with the intent of integrating the electricity and natural gas sectors with an overall economy-wide approach designed by the ARB, with assistance from all of the other agencies involved.

I have heard a great deal of concern about whether the Commission’s load-based approach will be able to be coordinated effectively with what is likely to be a source-based approach by the ARB for many other sectors. I want to go on record to say that I do not see this as a significant obstacle to uniform implementation of emissions caps in California. Taking a load-based approach to the electricity, and potentially natural gas, sector ensures two very important things:

• First, it allows us to capture emissions associated with California’s significant electricity imports. To that extent, a load-based approach is totally consistent with AB 32. I also note that approximately half of our emissions footprint is associated with our imported power and not with power produced within California.
   
• Second, a load-based approach allows the Commission and the CEC (among other agencies) to continue to utilize our policy levers for renewables and energy efficiency, because it puts the responsibility for achieving emissions reductions on load-serving entities. If we were to take a source-based approach and apply emissions caps only to generators, then it would make it much more difficult to integrate energy efficiency and renewables policies into our overall climate strategy.

As I said above, I believe this approach is consistent with both AB 32, and with the Climate Action Team (CAT) report recommendations of April 2006.

The Commission intends to continue to participate in a number of ongoing coordination mechanisms for AB 32 implementation. These include the CAT meetings, the economic subgroup of CAT in which staff actively participate, the energy-related subgroup of the CAT (which includes the CEC, ARB, Commission, and CalEPA), as well as bi-weekly staff meetings among the agencies.

We are doing our best to ensure coordination and no duplication of efforts on AB 32 implementation. Implementing this law and policy is an enormous challenge, and an important one. We will only succeed if we work together as openly and efficiently as possible.

Q6. What are your views about the costs and benefits of re-licensing the currently operating nuclear power plants in California? Should the utilities be required to seek CPUC approval before applying for license renewals at the U.S. Nuclear Regulatory Commission? What factors should be taken into account by the CPUC?

Answer:
With the re-licensing process 15 years out in the future, it is difficult to predict the costs and benefits of re-licensing. Currently operating nuclear facilities make an important contribution to our electric generation resource base. It is difficult to predict the costs and benefits of re-licensing, as the re-licensing process is 15 years off. I anticipate and hope that by the time of license expiration, (2022 in the case of SONGS and 2024 for Diablo Canyon) there will be much additional supply and infrastructure for environmentally preferred resources such as geothermal, solar and wind. In addition, by the 2020s there may be a well-developed regime for limits to greenhouse gas emissions from energy production which potentially could favor nuclear resources. Also we will have more information on the long-term nuclear waste storage options by that time.

As the utilities weigh going forward with re-licensing in the years to come, the supply implications will be reflected in their Long Term Procurement Plans. I expect that California’s utilities will also need to demonstrate compliance with a GHG emissions cap that is developed by California, or potentially on a federal level. It would be premature to require examination by the Commission of the costs and benefits of re-licensing at this juncture. However as the dates for re-licensing get closer we can re-examine whether the further operation of these existing plants is consistent with the Long Term Procurement strategy of the IOUs and the framework in which they will be operating, with respect to nuclear waste, GHG emissions and the existing nuclear decommissioning trusts.

Q7. What are your goals with respect to development of utility infrastructure? Beyond adhering to the procedural requirements of CEQA, how should the CPUC reconcile the need for additional utility infrastructure, such as transmission lines, with the need to protect and enhance public health, the environment, and unique public resources, such as state parks?

Answer:
The CPUC’s goal with respect to development of utility infrastructure is to have early participation in statewide transmission infrastructure planning. Such coordinated planning will provide a process where public interest, environmental and land use (federal forest, state parks, and community interest) issues can be identified and potentially addressed before transmission plans are finalized and utilities’ applications are submitted to the Commission. With the approval of SB 1059, the Commission is already discussing state-wide energy corridor planning with the California Energy Commission. We should collectively create a state wide electric infrastructure plan with an increased time horizon of 5-10 years. Also, non-wires alternatives, such as local generation (both conventional and renewables), demand response, time of use metering, advanced technology, and energy efficiency should be considered as a complement or a substitute when considering new transmission infrastructure.

Q8. How does the CPUC apply the “loading order” to applications for new energy supply projects, such as transmission lines or fossil fuel power contracts? For example, is it possible for the CPUC to defer or reject a supply project, even if needed, on the basis that energy efficiency is available at a lower cost? How would the CPUC reach such a conclusion?

Answer:
Long Term Procurement Plans are the Commission’s method of ensuring the utilities are following the loading order.

In accordance with Public Utilities Code 454.4, the Commission requires the electric utilities to prepare bi-annual long-term procurement plans (LTPPs). The Commission initiated Order Instituting Rulemaking (OIR) 06-02-013 to continue its efforts to ensure a reliable and cost-effective electricity supply in California through the integration of a comprehensive set of procurement policies and review the 2006 utility LTPPs. On December 11, 2006 the IOUs filed 2006 LTPPs covering 2007-2016. A decision approving the LTPP, and requiring modifications if necessary, is expected this year. (The 2006 LTPPs are available on the Commission’s website at: http://www.cpuc.ca.gov/static/hottopics/1energy/r0404003.htm.)

As directed by the Commission, the IOUs’ LTPPs are a form of integrated resource plans that demonstrate how the utility incorporates the loading order priorities into the utilities' procurement decisions on a short and long-term basis. In its LTPP, the utility must demonstrate that it has in place a ten-year resource plan designed to exist within all policy constraints and that will enable the IOU to adequately meet its bundled customer load needs. The IOUs were directed that their 2006 LTPPs need to reflect all of the procurement related decisions made by the Commission to date in all other procurement related dockets. The Commission has other proceedings for various loading order resources – such as energy efficiency, demand response, and renewable energy – and in those separate Commission proceedings goals and forecasts are established and the programs are evaluated. The goals and forecasts for each resource type are a part of the long-term procurement plans, and therefore both the trade-off between loading order resources, as well as the need for additional resources beyond the loading resources, occurs when the Commission approves the LTPPs. However, the maximization of a particular loading order resource takes place in the context of the resource-specific proceeding that examines program evaluation for that particular resource.

Specific projects are evaluated for compliance with the Long Term Procurement Plans.

Once the LTPPs are approved, individual applications for energy supply projects are reviewed for compliance with the utility's long term procurement plan and the loading order priorities, as well as other Commission goals such as fairness and cost-effectiveness. The Commission approved the 2004 LTPPs in D.04-12-048, and those LTPPs have governed the Commission’s consideration of new supply resources since December 2004. If a project is in compliance with the expected resource needs in the long term procurement plan, then it already has been evaluated to ensure it represents the most cost effective application of the loading order. For example, PG&E’s approved 2004 LTPP called for the addition of ~2,200 MW of new supply resources, in addition to aggressive goals for new preferred loading order resources (energy efficiency, demand response, etc.). In Application (A.) 06-04-012, PG&E requested approval of seven new power plant contracts and the Commission approved those contracts in D.06-11-048. The Commission’s contract approval was based on the previously established 2004 LTPP determination of need, which already assumed the preferred loading order resources were being achieved at their maximum levels.

Oversight of procurement activities enables the Commission to respond to changes between planning cycles.

Through its ongoing oversight of the utilities' procurement activities, the Commission is able to further evaluate if a proposed supply resource could reasonably be replaced by a resource higher in the loading order at lower cost, i.e. if the LTPPs are in need of mid-course corrections prior to the next planning cycle.

The IOUs 2006 LTPPs are expected to be ruled on by the Commission in 2007. The IOUs are expected to submit 2008 LTPPs in 2008 that cover the period 2009-2018. The biennial review process allows the Commission to make corrections to long-term plans based on the results and revised goals achieved for each loading order resources. More detailed information on how the Commission directed the utilities to file LTPPs, in particular the directions with respect to how the Commission expected the IOUs to file the Loading Order, can be found in the Scoping Memo issued September 25, 2006, available at http://www.cpuc.ca.gov/static/hottopics/1energy/r0404003.htm.

Q9. Please describe the nature of telecommunications complaints received by the CPUC since 2005. How does the CPUC staff assist consumers who contact the CPUC with complaints?

Answer:
The Commission through its Consumer Affairs Branch (“CAB”) provides assistance to consumers both over the phone and in writing. A consumer can submit an informal complaint to CAB in writing via our website at: http://www.cpuc.ca.gov/static/forms/complaints/index.htm, with more complex complaints requested in writing. A CAB Representative will “work” a complaint using information from the consumer, the carrier, and the Commission’s rules. Our goal is to resolve informal complaints within 90 days. Urgent matters, in particular potential disconnections, may be made by phone, and are treated as the highest priority.

As shown, in 2006 approximately ¾ of all complaints received by the Commission were for telecommunications. These complaints were against telecommunications carriers regarding billing and service issues. Also, in 2006 CAB took on responsibility for a new category of work, not technically a complaint, but rather an appeal of a determination of a customer’s eligibility for LifeLine Telephone Service.

These LifeLine appeals merit further examination. Pursuant to an order of the Federal Communications Commission, the Commission was required to make substantial changes to verification of LifeLine eligibility or lose substantial funds. In July 2006, a third party certification agent, under contract to the Commission, took over many of the functions formerly performed by the telecommunications carriers. This disruption of the long-standing relationship between the carriers and their customers resulted in customer confusion and a subsequent increase in the volume of customer calls and correspondence to CAB. Beginning in July 2006, an increasingly large percentage of CAB’s intake related to telecommunications issues were actually appeals by customers who had problems re-enrolling in the California LifeLine Telephone Service program. By January 2007 approximately 40% of Informal Complaints were actually Lifeline appeals.

In November 2006, the Commission suspended the annual customer verification (re-enrollment) part of the LifeLine program for up to six months to make a closer examination of re-enrollment processes. With the active involvement of several carriers, the Commission is improving the LifeLine customer notification process by increasing public awareness of the LifeLine program, redesigning envelopes, extending the period in which customers can return their forms, and providing for voice contact when a customer has not returned the form. The Commission will measure the impacts of these programmatic changes, and determine when and how to reinstitute customer verification.

Removing the affects of Lifeline appeals, the table below shows the distribution of 2006 written complaints among different segments of the telecommunications industry: wireless, local (e.g. basic) service, and complaints that are not against the local exchange company. The most common complaint categories for both written and phone complaints are billing disputes and service quality.

With regard to pending complaints (excluding LifeLine), the Commission entered 2007 in the best shape it has been in since the beginning of the energy crisis. The backlog of open complaints has been markedly reduced. These improvements are attributable to the Legislature’s approval of staff augmentation, as well as to our strong focus on backlog reduction. The table below provides the information directed by the Legislature, and depicts the progress the Commission has made. Because CAB has recently closed many old cases, the average time to close each written case so far during this fiscal year has been high. A more useful metric for measuring caseload management is how long the average case has been open. Average case duration has been reduced by 77%, declining from over a year to under three months. While we expect to see case duration decline even further, this reduction is real and substantial progress.

*Information required by SB 531.

Q10. What is the status of the CPUC’s effort to improve services to telecommunications consumers who do not speak English fluently? When is the CPUC implementing California law which requires telecommunications contracts to be in the same language as the marketing material? What consumer protection measures has the CPUC established specifically for limited-English speaking customers?

Answer:
In 2006 the Commission’s effort regarding serving customers who do not speak English fluently was centered on the implementation of programs in the Telecommunications Consumer Protection Initiative, also known as the CPI (D.06-03-013). The Commission collaboratively created, mass-produced and -distributed four brochures on current telecommunications issues including slamming and cramming, purchasing wireless service, understanding your bill and a tips on service. The brochures are available in hard copy in English, Spanish, and Chinese and distributed through various outlets including community-based organizations. Additionally the Commission created an independent website called at: http://www.calphoneinfo.com / that reproduces our in-language knowledge base in Korean, Vietnamese, Thai, Russian, Tagalog, Farsi, Arabic, Hmong, Khmer, and Armenian.

The Commission’s primary information pamphlet, “The Consumer Guide” is now available in English, Spanish, Chinese, Vietnamese, Russian, Tagalog and Farsi. Key Commission reports, decisions and press releases (e.g., Commission Energy Action Plan) have been translated into other languages. We have increased the number of translated documents available our website.

On January 11, 2007 the Commission launched R.07-01-021, our Order Instituting Rulemaking titled “Order Instituting Rulemaking to address the needs of telecommunications customers who have limited English proficiency” to determine if current consumer protection rules are effective for limited-English proficient (LEP) telecommunications consumers. This rulemaking is the formal culmination of work that began with institution of the CPI in March 2006. The rulemaking will develop of a set of options for targeted actions that take into account the costs, benefits, and feasibility of solutions to the documented challenges and problems facing LEP consumers. The rulemaking will explicitly address when, P.U. Code and Civil Code sections that require telecommunications contracts to be in the same language as the marketing material, should be applied. http://www.cpuc.ca.gov/word_pdf/FINAL_DECISION/63728.pdf

Commission staff completed a comprehensive review of the state of language in California with the help of the telecommunications industry, local community-based organizations and consumer groups. A series of workshops were held across California (San Francisco, Los Angeles, Fresno, Stockton, and San Diego) that assisted the Commission in determining that a more formalized approach was necessary. The Commission has also instituted consumer protection measures specifically for limited-English speaking customers. Namely, the ability of our CAB to answer inquiries and resolve informal complaints against telecommunications carriers, in-language, has been enhanced with the recent hiring of four (4) Spanish-speaking and two (2) Chinese-speaking Reps taking our bi-lingual Staff to over 13 Reps.

Q11. As a condition of approving their mergers, the CPUC required AT&T and Verizon to offer "stand-alone" DSL.

Has this condition been implemented?

Yes.

• AT&T offered DSL within the merger Decision’s timeline.
• Verizon was granted an extension and offered DSL within the extension.

What is the price of “stand alone” DSL?

Price as a condition of the FCC’s approval of the AT&T/BellSouth merger, to be offered within 12 months of the merger closing date (by December 29, 2007), for 30 months from its initial offering date:

Is this requirement working as envisioned?

The merger decision (D.05-11-028) envisioned that stand-alone DSL would be a viable competitive product. Both AT&T and Verizon report that they have been selling the stand-alone service and currently have customers. However, AT&T has very few such customers, whereas Verizon has far more in real numbers, but especially relative to its customer base in comparison to AT&T.

The merger Decision envisioned a significant retail customer response, but the very small number of AT&T stand-alone DSL customers does not support that vision.[3] There may be room for debate for the Verizon numbers since they are much greater, even thought Verizon’s product had a later roll-out date. The pricing differences between AT&T and Verizon are consistent with what one would expect regarding customer response in that Verizon gives customers twice the speed for significantly less money.

However, the number of AT&T customers is likely to increase dramatically when AT&T complies with their own concession as a condition of the FCC’s AT&T/Bell South merger approval. This concession, enforceable by the FCC, drops the price to $19.95 no later than the end of this year. At that point, the Commission vision for AT&T’s stand-alone product will likely begin to be fulfilled. Unfortunately, the Commission has not had jurisdiction over DSL pricing, and was unable to require competition-enabling pricing in its original decision. Apparently Verizon set prices consistent with the spirit of the decision, whereas AT&T did not.

Q12. The CPUC is required to review the California High Cost Fund – B to reflect current operating costs and reduce costs. That report was due by January 1, 2006. What is the current status of that review?

Answer:
Pursuant to SB 1276 (Chapter 847, Statutes of 2004), the Commission issued Rulemaking (R.) 06-06-028 on June 28, 2006 to review the state’s California High Cost Fund – B (B-Fund) program. The main goals of this review include adjusting universal support payments to reflect updated operating costs, evaluating whether B-Fund support levels can be reduced and made more predictable while maintaining program goals, ensuring the program is competitively neutral, reducing rate disparity in residential basic service between urban and rural areas in the state, and finally, making the current administration of the program more efficient.

In this rulemaking, the Commission is seeking comments on whether the program is meeting its respective statutory purposes and requirements as articulated by the Legislature in statutes and in our decisions adopting the program. To the extent deficiencies are identified, constructive remedial proposals will be provided. Comments were sought on a number of issues including the following:

•  Updating of program costs
• Can Universal Service rate support levels be reduced while still meeting program goals?
• Should the concept of revenue neutrality for fund recipients be continued?
• How should support be calculated and appropriately targeted to high cost areas?
• How can the program administration and implementation be made more efficient?
• General issues

The Commission has received opening and reply comments on the OIR. The assigned ALJ and assigned Commissioner are evaluating the comments. There will likely be an ALJ and/or Assigned Commissioner ruling seeking further clarification and more comments.

The issues in this rulemaking are complex and will likely be decided in phases. Some of the issues should be resolved later in 2007. The remaining issues should be decided by the end of 2008.

Q13. What specific steps will the CPUC take this year to improve public participation and public access to information in CPUC proceedings?

Answer:
It is a goal of the Commission to reach out to the public to solicit information relevant to formal and informal proceedings. The Public Advisor’s Office has initiated, organized, or implemented an array of public events which range from the formal Public Participation Hearings that are conducted by Commission ALJs and result in a formal record; to large Commission sponsored conferences/symposiums which include panels of industry experts and keynote speakers; to Small Business Expos that allow small business to learn how to become utility suppliers; to informal workshops and meetings designed to solicit input from consumers on an informal level. The Public Advisor also receives and responds to letters, phone calls and e-mails from the public commenting on specific proceedings, decisions or policies. to the Commission. The Public Advisor summarizes and categorizes the comments and distributes reports to the Commissioners, Executive Office and other PUC management.

* Includes public participation hearings, prehearing conferences, en bancs, symposiums, small business expos, in-language workshops, other proceeding specific workshops and Commission sponsored conferences.

The Commission has also initiated several rulemaking proceedings this past year to address new policies. It tends to be easier for consumers to participate in rulemaking proceedings where they present policy positions, rather than evidentiary hearings where they are subject to more stringent rules of evidence and address more technical issues. The Commission intends to do more quasi-legislative proceedings such as rulemakings in the coming months, which we expect will broaden participation by groups that are more comfortable with the legislative process. Examples include Commission rulemakings on protections for limited-English proficient telecommunication consumers and rulemakings on California’s solar initiatives.

(See http://www.cpuc.ca.gov/word_pdf/FINAL_DECISION/63728.pdf and http://www.cpuc.ca.gov/static/energy/solar/_index.htm respectively.)

With the implementation of electronic filing, which includes posting copies of all materials filed electronically on the website, the public can more easily follow Commission proceedings without participating formally and make a more informed decision on whether to get involved in some manner. As of January 1, 2007, approximately 60 percent of the formally filed documents are now filed electronically. The ability to file and serve documents electronically has definitely decreased the cost and simplified the process of public participation.

Q14. Do you believe utility consumers are adequately represented in CPUC proceedings? What actions would you propose to improve consumer representation and ensure that CPUC decisions reflect consumers’ interests?

Answer:

Any discussion regarding consumer representation at the Commission must include a discussion of the Commission’s Division of Ratepayer Advocates (DRA). DRA is an independent division of the Commission and advocates solely on behalf of utility ratepayers. It’s statutorily designated mission and goal, as set forth in Public Utilities Code section 309.5, is to “represent and advocate on behalf of the interests of public utility customers and subscribers,…to obtain the lowest possible rate for service consistent with reliable and safe service levels.” To fulfill this mission and goal, DRA participates, as a party representing consumers in Commission proceedings, including rate settings, investigations, and rulemakings. DRA also participates in Commission-sponsored working groups, advisory boards, workshops, and other forums. Among its many responsibilities, DRA evaluates utility proposals, investigates issues, presents findings and formal testimony, litigates complaints, and makes recommendations to the Administrative Law Judges and Commissioners.

The Director, Dana Appling, was appointed to her position in September 2004 and was subsequently unanimously confirmed by the Senate. Effective January 1, 2006, SB 608 (Escutia), among other things made significant changes to strengthen DRA, including emphasizing that the Commission is required to provide sufficient legal support for DRA, authorized the Director to appoint a general counsel, and specified that the DRA Director may independently control DRA's budget.

The Commission looks to DRA to provide the consumer perspective in Commission proceedings. DRA’s perspective is focused, its analysis is professional and due to DRA’s efforts the Commission has a richer, more balanced record upon which to deliberate before voting out decisions. DRA is often the only consumer advocate participating in Commission proceedings and without their participation, truly informed decision-making is less likely.

In addition to the DRA’s participation in Commission proceedings, the Commission pays intervenor compensation to other non-profit or privately funded consumer groups that participate in Commission proceedings. The vigorous participation by those groups is reflected in the increase in both the number of intervenor compensation awards and the total amount of those awards made in 2006 as compared to 2005. The number of awards increased from less than 60 awards to over 90 awards. The total amount of the awards increased from approximately $5 million to approximately $8 million.

One way the Commission is trying to increase consumer representation and ensure that the Commission is aware of consumer’s positions is to increase the number of workshops and pre-hearing conferences that are held outside of San Francisco. By bringing the proceeding to the consumers, it will be less expensive and more convenient for consumers to participate.

The Commission is also increasing its outreach activities throughout the state. The Commission’s Outreach Officers meet with community-based, service, and business organizations to explain Commission programs and services. They visit local and state elected officials’ offices and public libraries to provide resource materials for further distribution throughout the state. They give presentations and participate in community events to inform consumers about current Commission issues and to assist them in understanding how to participate. In 2007, the Commission is adding outreach personnel in the Inland Empire and Los Angeles area, as well as implementing a program designed to outreach to small businesses throughout the state.

Finally, the Commission is holding a series of Community Utility Bill Forums throughout the state, where consumers can meet with and discuss billing issues with the Commission and utility representatives. The Commission provides interpretation services at these forums so consumers can communication in their language of choice. The forums provide a neutral, comfortable, and non-threatening atmosphere in which consumers can ask questions to understand their bills and resolve billing issues.

[1] SDG&E’s 2000 Generation costs include PX charges.

[2] DWR has recently renegotiated one of the power purchase contracts and extended the contract until 2017. Legal Division understands that another contract may also be extended to 2017.

[3] The Commission has reviewed this data for AT&T and Verizon. However, both companies view this data as confidential and not to be made public, so it is not reported here.