CALIFORNIA PUBLIC UTILITIES COMMISSION

RESPONSES TO QUESTIONS IN PREPARATION FOR FEBRUARY 22, 2006 HEARING OF THE ENERGY, UTILITIES AND COMMUNICATIONS COMMITTEE

ELECTRICITY RATES

Please provide the average electric rates by customer class for PG&E, Southern California Edison, and SDG&E from 2000 through the present.

The rates are shown in Attachment 1, Charts 1, 2 and 3 for the following customer classes: residential, small commercial, large commercial and industrial, agricultural, lighting, and system total.

What is the CPUC's forecast for electric rates for the next several years?

In setting electric rates, the CPUC establishes an electric revenue requirement for a future “test year” based on the utility’s cost of service. This includes the utility’s cost of owning and operating its transmission, distribution, generation facilities, its fuel and purchased power expenses including the cost of paying the California Department of Water Resources (DWR) revenue requirements, and its cost for implementing public purpose programs such as energy efficiency programs, low-income discounts and energy efficiency assistance, renewable programs, and research and development programs. Rates are set on a short term, annual forecast basis. The CPUC does not forecast electric rates for longer term periods.
 

Current rates for 2006 are shown in the attached charts. The rates for SCE may increase slightly, e.g., by approximately 1%, later in the 1st quarter of 2006, as a result of its pending general rate case. PG&E’s rates may increase by an additional 3% in 2006 due to FERC authorized transmission rate increases, the California Solar Initiative, and authorization for demand response program funding.

What factors will cause rates to change?

Gas prices are a key element affecting electric rates. Gas prices affect the utility’s fuel and purchased power expenses including the revenue requirement to pay for the DWR contracts. The cost of maintaining the utility’s transmission, distribution, and generation facilities to ensure safe and reliable service affect the utility's revenue requirements and rates. The utility’s cost of capital and authorized rate of return are affected by financial conditions including interest rates, and these factors impact electricity rates. Programs to enhance reliability and the environment such as demand response programs and the Solar Initiative affect rates.
 

What are the relative proportions of generation, transmission and distribution in system electric rates for each major investor-owned utility?

These relative proportions of generation, transmission, and distribution revenues in current electric rates are shown below:

Edison

Generation: 60%
Distribution: 23%
Transmission: 3%
Other (public purpose, nuclear decommissioning, on-going CTC, fixed transition amount): 14%

SDG&E

Generation: 43%
Distribution: 31%
Transmission: 14%
Other: 15%

PG&E

Generation: 53%
Distribution: 27%
Transmission 7%
Other: 13%
 

What has been the cost trend for transmission and for distribution for each utility?

The utilities’ transmission and distribution revenue requirements over the last several years are provided in Attachment 2, Charts 1, 2, and 3.

Within the generation component, what are the relative proportions of DWR contracts, QF contracts, other purchases including spot market purchases and purchases by the ISO, and utility-owned generation?

Attachment 3, Charts 1, 2, and 3 show these relative proportions.
 

Does the CPUC intend to reduce rates? How will this be accomplished?

In various ratemaking proceedings, the CPUC endeavors to make sure that the utilities’ requests for cost recovery are reasonable and that the utilities do their best to keep costs at a minimum consistent with the mandate to ensure reliable service and to meet the energy policy goals set by the Energy Action Plan. All of the utilities’ requests for cost recovery and rate increases are examined in formal proceedings following a rigorous public process that provides for fact finding and public participation. Rates are reduced when costs decline and vice versa. Rates for PG&E customers were reduced by $800 million following the bankruptcy settlement (D.04-02-062). Similarly, the Commission reduced rates for Southern California Edison’s customers by $1.25 billion in D.03-07-029 after the Procurement Related Obligations Account (PROACT) was paid off.

The CPUC will reduce rates if it determines that the utilities’ costs of serving customers will decline. The CPUC reviews non-fuel related costs of service in the utilities’ general rate cases and fuel related expenses in the annual Energy Resource Recovery Account proceedings. If the CPUC determines in these proceedings that costs are lower than what the utilities are currently recovering in rates, it will require that the utilities lower rates to reflect the reduction in costs.

DIRECT ACCESS

Please explain the CPUC’s actions to ensure that energy service providers (ESPs) have met their Renewable Portfolio Standard (RPS) and resource adequacy (RA) obligations. How will the CPUC ensure ESPs participate in the RPS under the same terms and conditions applicable to Investor Owned Utilities (IOUs) as required by SB 1078 (Sher), Chapter 516, Statutes of 2002?

 

1. Renewable Portfolio Standard Compliance
   
   On November 21, 2005 the CPUC issued D.05-11-025, which determined that ESPs, Community Choice Aggregators (CCAs), and small/multi-jurisdictional utilities (SMJUs) are to be treated identically to the large IOUs for the following purposes:
   
   The requirement that 20% of retail sales come from renewable sources by 2010, as required by the Energy Action Plan
   
   The requirement that they increase their renewable retail electricity sales by l% per year through 2010
   
   The requirement to report their progress toward meeting RPS program requirements to the Commission
   
   The ability to utilize the same flexible compliance mechanisms
   
   The requirement that they be subject to the same penalties and penalty processes
   
   In response to D.05-11-025, the CPUC ordered the ESPs, CCAs, and SMJUs to file RPS implementation proposals with the CPUC by February 17, 2006. The parties were asked to “compare and contrast” their proposal with the existing RPS requirements for the large utilities. The Commission plans to issue a decision by summer 2006 that adopts a specific RPS implementation plan for ESPs, CCAs, and SMJUs.
    
2. Resource Adequacy Compliance
   
   All Load serving entities (LSEs), including IOUs, ESPs, and CCAs, are required to make filings with the CPUC showing their compliance with the resource adequacy rules (the summer 2006 filings are due 2/16/06). The CPUC has held workshops, distributed filing guides, and provided other assistance to ensure all LSEs comply with the filing requirements.

How is the CPUC tracking direct access contract expirations and renewals in order to calculate ESP’s accumulation of RPS procurement obligations?

In accordance with D.05-11-025, an Administrative Law Judge ruling dated November 28, 2005 directed ESPs, CCAs, and SMJUs to file Preliminary Renewable Portfolio reports with the Commission by January 26, 2006. These reports provide information regarding the amount of RPS procurement, as well as Direct Access contract expiration and renewal. The Commission is currently reviewing these reports. Based on the information filed, combined with stakeholder meetings and upcoming workshops, the Commission will refine the existing IOU-specific RPS reporting guidelines for ESP and CCA use.

Please explain the CPUC’s practices with regard to public disclosure of information related to ESPs’ compliance with the RPS and resource adequacy requirements.

1. Renewable Portfolio Standard Compliance
   
   Consistent with the treatment of confidential IOU data, ESPs and CCAs can file confidential information under seal. However, any ESP or CCA requesting to file data under seal must identify specific items that need confidential treatment and provide a justification. Parties may challenge an ESP or CCA’s request for confidential treatment. The Administrative Law Judge (ALJ) will then make a determination based on the merits of the justification for confidential treatment and the arguments and factors supporting public disclosure of the information.
    
2. Resource Adequacy Compliance
   
   Sensitive information filed by all LSEs (both ESPs and IOUs) in the Resource Adequacy proceeding is kept confidential. All information is filed pursuant to a protective order issued by the ALJ overseeing the proceeding. Only persons who have signed a non-disclosure agreement may view the information. Commission staff and ALJs have access to confidential information under Commission rules.

Specific Steps to Improve Public Access to Information in the Resource Adequacy Requirements (RAR) Proceedings

Last year’s RAR proceeding (i.e., the RAR portion of the umbrella procurement rulemaking, R.04-04-003) addressed broad RAR policy issues as well as technical implementation rules. The proceeding was conducted using a public workshop and comment process, and it was decided without the need to consider confidential information.

The current RAR rulemaking (R.05-12-013) recently commenced with a pre-hearing conference on February 3, 2006, and no determination has been made whether any information introduced into the proceeding will need to be treated as confidential. At this time it appears that it may be possible to conduct this proceeding without the need to consider any confidential information.

The Commission has recognized that customer load (demand) information and resource information submitted by individual LSEs in compliance with the ongoing RAR program may be considered confidential. In D.05-10-042 the Commission took a “conservative” approach and determined that, pending completion of the SB 1488 rulemaking proceeding, both load and resource data that an LSE claims as confidential would be entitled to confidential treatment. By taking this approach, the Commission signaled that it would consider further the confidentiality of the LSEs’ RAR compliance filings in light of the determinations made in the generic confidentiality rulemaking.

CPUC Practices with regard to public disclosure of information related to ESPs’ Compliance with RAR

The Commission has taken a uniform approach to the issue of public disclosure of information submitted by LSEs in their RAR compliance filings. In other words, it has determined that load and resource data submitted by ESPs in their RAR compliance filings should be treated confidentially to the same extent that load and forecast data submitted by the investor-owned utilities and community choice aggregators are treated confidentially. As noted above, the Commission has taken a conservative approach and deemed the LSEs’ load and resource data as confidential pending the outcome of the SB 1488 proceeding.

NATURAL GAS

Please provide the natural gas rates and delivered volumes by customer class for PG&E, Southern California Gas, and SDG&E from 2000 through the present.

The utilities' gas rates and delivered volumes by customer class are provided in Attachment 4, Tables 1 to 6.
 

Please list the CPUC decisions between 2000 and the present, and describe the policies set forth in those decisions, regarding:

• Procurement of natural gas for core customers by local distribution companies (LDCs), including specifically any assessments of the merits of long versus short positions for procurement of gas supply for end-use customers
  
  In the mid-1990s, the Commission established gas cost incentive mechanisms for California’s three largest natural gas utilities, SDG&E, SoCalGas, and PG&E. An incentive mechanism for Southwest Gas became effective in 2005. These mechanisms eliminate “reasonableness reviews” of natural gas procurement costs for these utilities, and provide a financial incentive for the utilities to procure natural gas at prices below monthly market prices. If the utilities procure natural gas at costs below annual benchmark costs, which are based on monthly market indices, the utility receives a financial reward. If the utilities procure natural gas at costs above the annual benchmark costs, the utility incurs a financial penalty. These performance based incentives allow the utilities considerable flexibility to procure natural gas for core customers and manage natural gas costs.
  
  The mechanisms provide the utilities with general authority to purchase natural gas financial instruments to hedge the price of natural gas, since the costs and gains due to the use of financial instruments are typically included as actual costs in the gas cost incentive mechanisms. While the Commission reviews the operation and performance results of the gas cost incentive mechanisms on an annual basis, and staff often discusses procurement activities with the utilities, the CPUC does not micromanage utility procurement activities, including the use of financial instruments.
  
  The Commission has not addressed in any decision between 2000 and the present the general merits of long versus short positions for natural gas procurement for end-use customers. In Decision (D.) 05-10-015 and D.05-10-043, discussed below, the Commission approved confidential hedge plans for PG&E and SoCalGas/SDG&E, respectively, in order to protect utility gas customers from potentially very high gas prices, and removed the costs and potential gains associated with those hedging activities from the gas cost incentive mechanisms of those utilities.
  
  Given the recent tightening of the gas supply market and the increased volatility in gas prices, the Commission may consider modifying existing incentive mechanisms to encourage (or require) the utilities to manage gas risk similar to the way they manage electric risk, i.e. with a combination of long, medium, and short-term transactions, including financial hedging products. In considering these changes, the Commission will address the utilities’ recent claims, following the escalation in gas prices after Hurricane Katrina, that the current incentive mechanisms, by basing rewards and penalties on a monthly index, disincent hedging and longer term transactions.
  
  With regard to natural gas procurement in general for core customers by LDCs, the Commission issued the following decisions:
  
  a. D.00-06-039: Awarded SoCalGas $7.7 million for savings under its Gas Cost Incentive Mechanism (GCIM) Year 5, ordered staff to file an evaluation report on the GCIM, and extended the term of the GCIM.
  
  b. D.01-05-002: Awarded SoCalGas $9.8 million for savings under its GCIM Year 6.
  
  c. D.01-05-003: Corrected a flaw in the method of calculating the procurement rate for SDG&E core and noncore customers, and ordered a rebate to core customers.
  
  d. D.02-06-023: Adopted modifications to SoCalGas’ GCIM, and ordered the Commission’s Energy Division to prepare an Order Instituting Investigation to determine whether utilities caused 2000/2001 gas price spikes.
  
  e. D.02-08-064: Found Southwest Gas’ procurement practices in 2000-2001 to be unreasonable, and ordered Southwest Gas to refund $2.7 million.
  
  f. D.02-08-065: Declined to adopt a SoCalGas/SDG&E proposal to consolidate their core procurement departments, and adopted rules for eligibility for core service for noncore customers.
  
  g. D.03-07-037: Modified and extended the term of the SDG&E gas procurement PBR.
  
  h. D.03-08-064: Awarded SoCalGas $17.4 million for performance under Year 8 of the GCIM, pursuant to the modified GCIM adopted in D.02-06-023.
  
  i. D.03-08-065: Awarded SoCalGas $30.8 million for performance under Year 7 of the GCIM, pursuant to the modified GCIM adopted in D.02-06-023.
  
  j. D.03-12-061: This decision primarily addressed PG&E’s backbone transmission and storage rates, but it also extended the term of the PG&E Core Procurement Incentive Mechanism (CPIM).
  
  k. D.04-02-060: Adopted a GCIM reward for SoCalGas under Year 9 of the GCIM of $6.3 million, subject to the outcome of I.02-11-040.
  
  l. D.04-09-022: This “Phase 1” decision of the Commission’s Gas Supply and Infrastructure Rulemaking proceeding included several key policies: Adopted procedures under which natural gas utilities enter into contracts for firm interstate pipeline capacity rights for their core customers, and allowed the utilities to decrease the amount of pipeline capacity SoCalGas held at the time for noncore customers.
  
  m. D.05-04-003: Adopted a GCIM reward for SoCalGas under Year 10 of the GCIM for $2.3 million, subject to the outcome of I.02-11-040.
  
  n. D.05-05-033: Adopted a gas cost incentive mechanism for Southwest Gas.
  
  o. D.05-10-015: Authorized PG&E to purchase financial hedge contracts in order to protect core customers from the possibility of very high prices in the winters of 2005-2006, 2006-2007, and 2007-2008. The Commission also removed these costs from treatment under the CPIM, thereby protecting the utility from risk that the contracts would result in higher costs. The hedging plan was submitted confidentially to the Commission.
  
  p. D.05-10-043: Authorized SoCalGas and SDG&E to purchase financial hedge contracts in order to protect core customers from the possibility of very high prices in the winter of 2005-2006. The Commission also removed these costs from treatment under the GCIM, thereby protecting the utility from risk that the contracts would result in higher costs. The hedging plan was submitted confidentially to the Commission.
  
  q. D.05-11-004: Allowed SoCalGas and SDG&E to file an application to consolidate their core procurement portfolios.
  
  r. D.05-11-027: Authorized SoCalGas to convert 4 billion cubic feet of very low cost “cushion gas” in storage to “working gas” and sell that gas to low-income customers in the winter of 2005-2006.
   
• Holding/release of firm interstate pipeline capacity by LDCs
  
  a. D.02-07-037: Established rules for California subscription to “turned-back” El Paso interstate pipeline capacity, and required natural gas and large electric utilities to sign up for a portion of the El Paso capacity.
  
  b. D.04-01-047: Established cost allocation methodology for costs of the “El Paso turned back capacity” obtained by utilities pursuant to D.02-07-037.
  
  c. D.04-09-022: This “Phase 1” decision of the Commission’s Gas Supply and Infrastructure Rulemaking proceeding includes several key policies: Adopted procedures under which natural gas utilities enter into contracts for firm interstate pipeline capacity rights for their core customers, and allowed the utilities to decrease the amount of pipeline capacity SoCalGas held at the time for noncore customers.
   
• Expansion of utility system transport capacity at the interconnections between the SoCal system and the Kern River pipeline; between the PG&E system and the Kern River pipeline; between the PG&E and SoCal systems; at the entry points to the SoCal system on the Arizona border (Ehrenberg and Topock)
  
  a. D.01-12-018: Approved the Comprehensive Settlement Agreement (CSA) for SoCalGas and SDG&E, which adopted a system of firm tradable capacity rights at SoCalGas transmission receipt points, and found that this system would provide economic signals related to the construction of new intrastate transmission facilities. (Note: The Commission never implemented the CSA framework. Due to controversy over the implementation advice letters, the Commission ordered SoCalGas to file an application to implement the CSA framework. SoCalGas filed an application, which the Commission adopted in D.04-04-015, but the decision was stayed.)
  
  b. D.04-04-015: Adopted implementation of D.01-12-018, but stayed its order pending the issuance of a decision regarding firm tradable rights in the Commission’s Gas Supply and Infrastructure Rulemaking.
  
  c. D.04-09-022: As noted above, this is the Phase 1 decision of the Gas OIR. With regard to receipt point issues, the decision:
  
  - adopted a nomination system for SoCalGas that would allow increased deliveries through Kramer Junction, the Kern River interconnect with SoCalGas;
  
  - allowed SoCalGas and SDG&E to establish new receipt points as needed at Otay Mesa, Salt Works Station and Center Road Station, with Otay Mesa being a “common receipt point” for both utilities;
  
  - required SoCalGas and SDG&E to request a system of firm tradable rights in another application;
  
  - adopted policy on the cost responsibility for new utility infrastructure required to bring in new supplies, and;
  
  - required the natural gas utilities to file nondiscriminatory open access tariffs for interconnections with new supply sources.

Please list the decisions of the CPUC between 2000 and the present, and describe the policies set forth in those decisions, regarding the formulas for reflecting the price and cost of natural gas in electric rates.

Natural gas prices affect electric rates through the IOUs’ Energy Resource Recovery Accounts (ERRA). These accounts were established pursuant to D.02-10-062. D.02-12-074 modified and clarified D.02-10-062. The electric utilities file annual applications for Commission approval of forecast and actual expenditures in the ERRA account to recover energy procurement costs associated with fuel and purchased power, utility retained generation, ISO related costs and costs associated with its residual net short procurement requirements to serve its bundled service customers. Also included are costs for: qualifying facility (QF) contracts, inter-utility contracts, irrigation district contracts and other Power Purchase Agreements (PPA), bilateral contracts, forward hedges, pre-payments and collateral requirements associated with procurement (including disposition of surplus power), and ancillary services.

The dollars accrued in each IOU ERRA is passed through to rate payers through the revenue requirement for that IOU. The ERRA excludes DWR power purchase contract costs. The specific treatment of natural gas costs for QF power, DWR power purchase contracts, and utility retained generation and bilateral contracts are described below.

QF Power: In D.96-12-028, the Commission adopted the “Transition Formula,” pursuant to Section 390 of the California Public Utilities Code (Section 390), in order to calculate monthly short run avoided cost (SRAC) as-available energy prices paid to QFs. Section 390 was part of the legislation for restructuring the electric industry in California under Assembly Bill (AB) 1890. Section 390 prescribes the basic elements for determining as-available energy prices paid to QFs based on “an average of current California natural gas border price indices,” pursuant to Section 390(b).

Modifications to the Transition Formula have been considered in Order Instituting Rulemaking into Implementation of Pub. Util. Code Section 390, R.99-11-022. To date, sixteen decisions have been issued in R.99-11-022. These decisions can be grouped as follows:

• Transition Formula Pricing – 6 Decisions. D.00-10-030 denied a June 28, 2000 emergency motion by Edison to implement a provisional QF avoided cost posting for September 2000 and future months, which would have reduced SRAC energy payments. D.01-03-067 revises Edison’s transition formula ‘factor’ adopted in D.96-12-028 and establishes a procedure to replace the Topock index adopted in D.96-12-028, which have the effect of reducing SRAC energy payments to QFs under contract to Edison. The Commission issued three decisions (D.01-12-025, D.02-02-028, and D.02-04-065) to address requests for rehearing and/or petition for modifications. D.05-09-003 is a relatively minor decision that relieved “the IOUs of the obligation to pay QFs, that have power purchase agreements (PPA) with the IOUs, within 15 days of the end of the QF billing period.”
   
• Contract Amendments -- 7 Decisions. D.01-06-015 “pre-approved three voluntary QF contract amendments for Edison, SDG&E, and PG&E that address the special circumstances presented by the dysfunctional wholesale market in California.” The three contract amendments were: (1) a 5-year, fixed-price energy payment of 5.37 cents/kWh, (2) supplemental energy payments, or (3) incentive payments for excess QF generation. There are six additional decisions on issues related to these contract amendments: D.01-07-031, D.01-09-021, D.01-09-027, D.01-10-069, D.02-01-033, and D.02-05-012. These decisions did not specify any changes to the SRAC energy pricing transition formula.
   
• Line Loss Factors – 2 Decisions. D.01-01-007 revised the line loss factors used to calculate energy deliveries. D.01-06-043 denied a request for rehearing on certain issues.
   
• QF Switchers – 1 Decision. Directed PG&E to pay QFs, which exercised their one-time option to switch to Power Exchange (PX) pricing, SRAC payments based on the Transition Formula adopted in D.96-12-028, or as modified, for power produced as of January 19, 2001.

DWR Power Purchase contracts: Under the Rate Agreement between the CPUC and DWR, the CPUC is obligated to accept DWR’s annual revenue requirement forecast and ensure that it is collected from IOU ratepayers and remitted to DWR. The CPUC cannot change a request from DWR, and has no say regarding how DWR estimates its annual contract costs, including the forecast price of natural gas used by DWR in its estimates.

Regarding the overall influence of the cost of natural gas on DWR’s annual contract costs: first, many of DWR’s contracts are based on fixed contract prices, so their cost does not change when the price of natural gas changes. A second group of DWR’s contracts are dispatchable at the discretion of the IOU that has been assigned that contract. Those contract costs do change with the price of natural gas (DWR purchases gas for these contracts pursuant to IOU recommendations). Finally, two of DWR’s base and peak load contracts include a “gas tolling” provision, under which DWR (on behalf of the IOU to which the contract is assigned) purchases the gas that supplies the plant that generates the electricity to supply that contract.

Utility retained gas fired generation and bilateral contracts where the utility supplies the gas: D. 02-10-062 established the ERRA account and a semi-annual update process for fuel and purchased power forecasts recorded in the ERRA. The ERRA includes generation fuels. In the first half of the year, the IOU’s file an application for annual fuel and purchased power forecasts. In the second half of the year, the ERRA balance account is reviewed for reasonableness and prudence. D.04-01-014 modified the dates for 2004 and 2005.

D.02-12-074 approved the IOU’s short term procurement plans and modified/clarified D.02-10-062. D.02-12-074 requires the IOUs to file monthly reports with supporting documents supporting each entry over $100 to the CPUC Energy Division.

The Commission authorized the use of hedging instruments to protect ratepayers from some of the risk of variation in natural gas prices. D.02-08-071, provided utilities the authority to use financially-settled hedging instruments for interim procurement, including natural gas hedges. D. 02-10-062, listed products that the Commission determined were appropriate to meet procurement needs including calls, swaps, gas storage and forward gas purchases. D. 03-12-062, continued authorization of the procurement products listed in D. 02-12-062.

Please describe the CPUC’s technical resources, capabilities and programs for monitoring natural gas supply and price movements for purposes of setting gas and electric rates.

The CPUC wishes to first clarify the relation between natural gas supplies and prices and natural gas utility rates.

First, natural gas utilities only procure supplies for core customers. Although core customers are by far the most numerous, their delivered volume only constitutes about a third of the utilities’ delivered supplies. Other customers procure their own supplies.

Second, the utilities’ procurement cost of natural gas is recovered in a “procurement rate” that is part of the core customers’ natural gas rate. (The other major component of customers’ rates is the transportation rate, which recovers the utilities’ operation and capital costs.) Procurement costs are generally based on wholesale natural gas transactions trading in a national market. The procurement rate is changed every month by each of the four major natural gas utilities in California, in order to reflect the utilities’ expectation about the procurement costs it will incur during the upcoming month. Actual costs are ultimately recovered through a “balancing account” which is amortized, also as part of the procurement rate.

Third, the utilities propose to the Commission every month what the new procurement rate should be, through a regulatory vehicle called “advice letters” (ALs). These advice letters are typically very routine filings. The staff of the CPUC’s Energy Division has the authority to approve these ALs, which it typically does on a routine basis. The CPUC’s Division of Ratepayer Advocates also reviews these filings, acting as an advocate for core customers, and may protest the filings if it believes the rates are calculated incorrectly or improperly.

For reviewing the utility filings to assure that natural gas rates are close to market prices, we have capable staff and access to important pieces of industry information. Staff in the Energy Division’s natural gas section have experience in natural gas regulation that ranges from a few years to 15 years. The CPUC’s Division of Ratepayer Advocates also has staff with a similar level of natural gas regulatory experience.

CPUC staff has access to key pieces of market information about natural gas prices and natural gas industry developments. For example, we subscribe to:

• Gas Daily and Natural Gas Intelligence which provide well-accepted industry price indices and current information about daily, weekly, and monthly prices, NYMEX prices and natural gas industry and regulatory developments,
• Foster Natural Gas Report
• PIRA consulting services

Staff in the Energy Division, the Division of Ratepayer Advocates, and the Division of Strategic Planning reviews these publications rigorously.  

The Energy Division and DRA hold regular discussions with natural gas utilities, including biweekly phone calls with SoCalGas to discuss market developments and prices.

CPUC staff and staff from other state government agencies such as the California Energy Commission have been meeting on a monthly basis for several years to discuss natural gas issues, including prices.

Finally, we also occasionally have meetings with industry representatives to discuss natural gas supply and price issues.

While we have good understanding of financial instruments and their use as price hedging and speculative tools, staff has limited detailed expertise on natural gas financial instruments, and limited time to analyze short-term price movements in relation to events in the financial market. Improvement in this area would better our ability to analyze natural gas prices, but is not necessary for the purpose of setting monthly natural gas rates.

Gas price forecasts are used in setting electric utilities’ fuel and purchased power revenue requirements in Commission proceedings. CPUC staff reviews these forecasts in the course of these proceedings.

Supplemental Question submitted 2/7/06:  

What are the current cost responsibility surcharge under-collections for each IOU? What are the forecasted under-collections and projected repayment dates?

Current Under-Collections

In the Feb 1, 2006 Final Report of the Cost Responsibility Surcharge (CRS) Calculation working group established by ALJ Pulsifer, the parties (PG&E, SCE, AreM, CLECA, CMTA, TURN, and DRA) jointly recommended adoption of the following under-collection estimates, as of the end of 2005:

•  PG&E under-collection: $60 million
• Edison under-collection: $577 million
• SDG&E under-collection: None. The under-collection has been paid off in SDG&E territory, as of approximately November 2005.
   

Forecast Under-Collections and Projected Repayment

• PG&E: working group members developed estimates showing that the current $60 million under-collection in PG&E territory will be repaid about midway through 2006.
   
• Edison: working group members developed estimates showing that the current $577 million under-collection in Edison territory will be repaid sometime in 2008.

TELECOMMUNICATIONS

What is the status of the California Emerging Technology Fund? When will board members be selected? Does the CPUC have a diverse group of applicants (i.e. different industries, companies, public interest groups) from which to choose?

The California Emerging Technology Fund (CETF) was established by the Commission as a condition of its November 2005 approval of two telecommunication mergers, SBC and AT&T, and Verizon and MCI (See Decision 05-11-028 & D-11-029). The CETF’s purpose is to achieve ubiquitous access to broadband and advanced services in California by 2010 through the use of emerging technologies. The Commission required the merged entities to provide initial funds ($60 million over five years) to support the CETF at its onset.

The CETF is presently in an early development stage. The Commission is currently seeking nominations to appoint four members to a twelve person governing board. The other members of the governing board will either be named by the merged companies or by the selected CETF board members.

In response to a Commission notice seeking nominations to the CETF governing board, 61 people have applied to be on the CETF board. The applicant pool is wide ranging and well-qualified, and includes government officials, academics, library workers, community-based groups and industry representatives. The Commissioners are currently reviewing the resumes of this large applicant pool and decisions on the four Commission appointees are expected to be made at the 2/16/06 Commission meeting (Agenda Item 5333).

Please describe the status of implementing Section 884 of the Public Utilities Code (SB720 of 2003) regarding the expenditures from the California Teleconnect Fund for the benefit of community-based organizations, particularly with respect to AT&T (formerly SBC).

What the SB 720 Program Does:

The PUC implemented Section 884 of the PUC code (SB 720) on June 1, 2005. The program provides discounts for one-time costs to install new advanced services for entities that do not have access to these services between September 23, 2003 and March 1, 2006. “Advanced services” are defined using the FCC’s current practice: broadband transport at rates greater than 200 MBPS in both directions. The FCC is considering raising the level to one megabit per second.

What Has Been Accomplished to Date:

In January 2005 the Telecommunications Division installed a new management team, subsequently assigned new staff resources and initiated discussions with the CTF Advisory Committee to accomplish program outreach. The PUC has received three claims for a total of approximately $1300 associated for T-1 services. AT&T claims represent about half of the total.

Carriers Decline to Offer DSL in the CTF Program, Which Reduces Demand for SB 720 Funds:

Because carriers decline to provide DSL service at a discount to CTF clients, participation rates by CBOs in particular is materially lower than anticipated. DSL, an advanced service, is extremely cost-effective for most CBOs.

Earlier in the program the PUC directed carriers to provide discounted DSL service in the CTF program. The PUC issued Resolution T-16742 in May 2003 to confirm and clarify prior Commission decisions that DSL is a CTF-eligible service. Ordering Paragraphs 1 and 3 of Resolution T-16742 state:

1. The California Teleconnect Fund (CTF) program rules are modified to allow qualified health care institutions and community based organizations (CBO) to receive 50% discounts on all Measured Business Service, Switched 56, ISDN, DSL, T-1, DS-3 and up to and including OC-192 services or their functional equivalents.

3. All certificated telecommunications carriers are directed to file Advice Letters to reflect the new CTF discounts and expanded types and quantities of services within 30 days of the effective date of this resolution. The Advice Letter and associated tariff sheets shall become effective within 15 days of the filing.

FCC Pre-empted State Authority Re IP-Services, Which Includes DSL:

Notwithstanding these clear requirements, and subsequent meetings with staff who directed the carriers to comply, the carriers did not bring their tariffs into conformance with the Commission’s orders. The carriers’ position was further bolstered by the FCC’s action last summer. In decision FCC 05-150 issued on 8/5/05, the FCC asserted sole jurisdiction over all IP-based services, including DSL. Consequently, the PUC no longer has the authority to enforce the provisioning of DSL service under state tariffs. Carriers offer DSL under federal tariffs.

CTF Will Reimburse Carriers Who Present Claims for DSL Service Under the Program, Even Though DSL Is Not a Jurisdictional Service:

The Commission invites all certificated telecommunications carriers to offer DSL discounts to qualifying entities in the CTF program and will continue to reimburse certificated carriers who do so.

“Naked” DSL Will Be Available Shortly, Which May Accelerate Demand for SB 720 Funds:

As part of the merger agreements concerning the “old” AT&T and MCI, the Commission required AT&T by June 30, 2006, and Verizon by February 28, 2006, to offer so-called “naked” DSL in California. An indeterminate number of CTF participants may elect such DSL service, which presumably will be offered at prices less than currently set for “bundled” DSL, even if it is not discounted in the CTF program.

Most CTF Clients Already Have Advanced Services, Which Reduces the Expected Demand for CTF Funds:

Because the program applies only to those CTF clients who do not have advanced services, participation in the SB720 program is lower than initially anticipated. After its inception, the carriers initiated a review of the market potential for SB720 discounts. Carriers have reported that most, if not all, non-CBO CTF participants already subscribe to some form of advanced services as defined by SB720. Consequently, few non-CBO CTF program participants qualify for the SB720 program.

TD Has Expanded Eligibility for the SB720 Program As Far As Possible Under Current Law:

The Telecommunications Division recently communicated to CTF carriers and participants that the SB720 program is available to install new advanced services to each location at a single address. This action clarifies inquiries regarding the scope of SB720 coverage at a single address. For example, each building on a school campus would be candidate for the SB720 program if no advanced services are currently installed. Legislation that would relax this requirement further is likely to result in greater program participation.

CPUC PROCESS

The President of the CPUC was made responsible for directing the staff of the commission by legislation enacted in 1999. How have you discharged this responsibility? How much of your time is taken up with these responsibilities? Prior to the 1999 legislation the Executive Director was responsible for directing the staff. Please discuss the benefits/detriments of Presidential responsibility for staff compared with Executive Director responsibility.

SB 33 (Peace) was enacted in 1999 (Ch. 509) as a means to help the five Commissioners exert more effective control over the Commission staff, and to increase accountability among the five Commissioners to the Governor and the Legislature. The measure requires the Governor to name the Commission President, gives the President authority to direct the Commission’s Executive Director, General Counsel and Commission staff in accordance with Commission policies and guidelines, and increased the number of exempt Commissioner advisors from one to two per Commissioner.

When I was appointed to the Commission in 2002, I had an opportunity to evaluate the SB 33 reforms as a Commissioner rather than as President. I had first hand experience in confronting the power of the “strong President” model on both administrative issues and more important substantive issues, such as moving long-stalled cases in the energy arena. Because the Commission President had the ability to control what item would (or would not) appear on the Commission’s business agenda, it was extremely frustrating to me and some fellow Commissioners in discharging our responsibilities. The President also had the power to assign new and existing cases to fellow Commissioners, or keep them and assign herself to the proceeding. I observed that the President devoted a substantial amount of time in the detailed management of both substantive and administrative matters, which often engendered absences in critical policy development and delays in disposing of items because the office needed more time for review.

To deal with the most troubling aspects of this period, I worked with Commissioner Jeff Brown to craft a set of Commission guidelines that would force the President’s hand on the practice of holding items off our business agenda for unreasonable lengths of time, or allowing the unlimited use of “holds” to defer action on an item that did get placed on the agenda. A majority of the Commission adopted those guidelines (Commissioner Report No. 2), which still exist today, although their use has been extremely infrequent during my Presidency. The guidelines are on our website at http://www/cpuc.ca.gov/static/documents/laws+rules+procedural+guidelines/policies_guidelines.htm.

Based on my prior business experience, and my brief tenure as a Commissioner, I accepted the position of Commission President with a determination to let people do their job. I wanted to eliminate the excessive use of power which had, in my opinion, previously led senior staff and managers to be risk-averse and fearful to move forward without express permission from the President’s Office. While I do not seek to minimize the challenges in managing a state agency with the size and responsibilities of the CPUC, my approach to that challenge was to assemble a first class management team and let them use their skills to manage. I meet with the team twice each month, discuss priorities and give direction where needed, and the results of those meetings are made available to my fellow Commissioners. Of course, the team is on call to meet the needs of any of my fellow Commissioners. In a sense, I have returned to the model that served the Commission well for the many decades preceding the adoption of SB 33.

I also wanted to remove the barriers to the other four Commissioners feeling fully enfranchised as equal partners in carrying out the Commission’s mission. I initiated a practice of using consensus whenever possible on controversial matters. Because case assignments are always a sensitive issue, I charged the Chief ALJ with developing a case priority system and tracking assignment of new and existing caseloads to assure each Commissioner has a fair allocation of caseload.

As I have reported to your Committee during the past three years of my presidency, the Commission has continually strived to improve our record for making our decisions within statutory deadlines. In 2005 we resolved 84% of our proceedings within the statutory requirements. While that is an acceptable rate in my view, we can do better. I have directed the Chief ALJ to strive for a 90% compliance rate for 2006.
 

You have been involved with the CPUC for more than 30 years, as an outside advocate for a utility, as a lobbyist, as well as a commissioner. What are the responsibilities of the CPUC to the public, in your view? How have the responsibilities of the CPUC to the public changed over the years? How has the professional quality of the CPUC staff changed over the years? How has the role of the staff changed? How would you assess the ability of the staff to discharge its responsibilities to the public?

Thirty years ago the Commission oversaw a set of firms with monopoly franchises that were subject to traditional cost of service regulation. Since then several of the industries we regulate have undergone significant transformations, while others have changed very little. Technological innovation and restructuring at both the state and federal level have been the principal drivers.

Today the industries under our jurisdiction range from the traditional public utility monopolies (water), to a hybrid market structure that combines monopolistic and competitive elements (electricity), to highly competitive (telecommunications). Despite these changes, our fundamental responsibilities to the public remain essentially the same: assure reliable service at reasonable rates, protect consumers from fraud and discrimination, and maintain public safety.

What has changed over time is the way that we go about carrying out our mission. Technological innovation and changing market structures have required the Commission to adopt new approaches, and to tailor them to the particular circumstances of the different industries we regulate.

Technological innovation in the telecommunications industry has resulted in rapid proliferation in the number and type or providers, fostering healthy competition but also increasing complexity. Our emphasis has shifted away from regulating rates and toward protecting consumers from fraudulent and deceptive practices (for example the new Telco Bill of rights and Fraud Unit).

Restructuring of the electricity industry and successive efforts to improve its environmental performance have brought many new classes of stakeholders into our orbit (i.e. merchant generators, solar equipment manufacturers and installers) and significantly broadened the scope of issues before the commission (i.e. assuring resource adequacy in a market with direct access and community choice aggregation, managing carbon risk). Another important development in recent years has been that the Commission is increasingly taking on design and/or implementation of major policy initiatives such as the Renewable Portfolio Standard, California Solar Initiative and efforts to reduce greenhouse gas emissions.

An overarching change in the past 30 years, in my view, is that our focus on consumer issues has significantly improved. We have dramatically increased our emphasis on and resources dedicated to consumer education and our responsiveness to consumer complaints. We also assist the diverse population in California by providing assistance in languages other than English.

The composition of our staff has evolved over time to meet these changing circumstances. Whereas we once employed mainly attorneys, regulatory analysts and engineers, today we have many more staff members with backgrounds in public policy, economics, business, environmental studies and project management. We have many challenges in terms of the State’s hiring and compensation system, but we have developed impressive new programs in the past year for training and recruitment and I believe that the current PUC organizational structure and performance is the most effective it has been in over a decade.
 

Please describe the CPUC’s efforts to implement SB 1488 (Bowen), Chapter 690, Statutes of 2004, regarding public access to information in the possession of the CPUC. What specific steps will the Commission be taking this year to improve public access to information in Commission proceedings?

In June, 2005, the CPUC opened a rulemaking to implement SB 1488, Proceeding R.05-06-040. The Order Instituting Rulemaking (OIR) may be viewed at http://www.cpuc.ca.gov/PUBLISHED/FINAL_DECISION/47631.htm. The OIR created two phases: 1) Phase 1, focused on confidentiality of records related to electric utility and Energy Service Provider (ESP) procurement, RPS, resource adequacy and related energy proceedings, and 2) Phase 2, focused more generally on the confidentiality of records submitted to the Commission, as well as the Public Records Act.

In particular, Phase 1 is focusing on the intersection of the confidentiality requirements of Pub. Util. Code Sec. 583, 454.5(g), and the need for open, transparent decision-making:

”We must seek to construe § 454.5(g) in a manner that is consistent with the public participation and open decision making requirements of SB 1488. Blanket claims of a need for confidentiality will no longer suffice if we are to satisfy SB 1488’s concerns. Nor can we ignore § 454.5(g)’s mandate to ensure the confidentiality of market sensitive information. Rather, we must attempt to strike an appropriate balance. Thus, we will require that parties asserting confidentiality be as specific as possible about the harm that they contend will result from publication of various types of procurement information.

We are most interested in knowing which data categories contained in various procurement documents are the most sensitive and the most likely to cause ratepayer harm if released verbatim. In response to this OIR, the electric utilities shall, and other parties may, comment on the preliminary Energy Division confidentiality recommendations contained in Appendix A to this OIR. If they disagree with those recommendations, they should do so on a category by category basis. For all of the categories, even the most sensitive, the utilities should specify timeframes or other parameters for the Commission to use to protect them. For example, certain procurement documents may be sensitive if they reveal hourly or daily information, but may lose their sensitivity if they cover longer timeframes.

Importantly, each utility should explain how long the data category should remain confidential, or identify the timeframe (e.g., hourly, daily) of information that requires protection. Equally important, the utilities should explain with specificity the ratepayer harm that may result from release of the information. It will not help us for parties to provide only general allegations about ratepayer harm. Rather, utilities should describe how one might use the data to unfairly affect electricity market prices or cause other harm.

Finally, for each category of confidential information, the utilities should identify how we might allow other parties access to the information in summary, aggregate, percentage-based, or partially redacted form, or via delayed release. That is, they should balance the harm they allege with procedures designed to maximize open decisionmaking. They should provide alternatives to full redaction or sealing for each type of data. (R.05-06-050, p. 18.)”

The assigned Administrative Law Judge held Phase 1 hearings from November 28-December 2, 2005, and plans to issue a draft decision in spring 2006 relating to confidentiality of electric procurement and related documents. A Commission decision will follow the public review and comment period. Among the many contentious issues in this proceeding is the challenge of defining “market-sensitive information.”

In addition, as confidentiality disputes arise in individual procurement-related proceedings, the assigned ALJs are closely coordinating with the ALJ handling the SB 1488 rulemaking to ensure sensitivity to the issues and consistency of outcomes.

Phase 2 of the proceeding will take place later in 2006. It will address confidentiality more generally, in the context of non-procurement/RPS/resource adequacy energy matters, telecommunications, and water proceedings.
 

Please describe the manner in which the CPUC and the Division of Ratepayer Advocates (DRA) have implemented the provisions of SB 608 (Escutia), Chapter 440, Statutes of 2005. Has the DRA been permitted to independently present its budgetary needs to the Department of Finance?

The Commission’s implementation of Senate Bill 608 included, as an initial step, changing the name of the Office of Ratepayer Advocates to the Division of Ratepayer Advocates (DRA). Also, the recently released State Budget for 2006-07 contains resources for DRA to hire a Lead Counsel for the Division. While current statute allowed for a separate line item in the State Budget for DRA that had not been the practice previously. That situation was rectified in the current year budget and is also reflected in the proposed 2006-07 State Budget. Pursuant to PU Code 309.5 (c), the DRA Director “develop(s) a budget for the division which shall be subject to final approval of the commission.” DRA then participates in the agency’s presentation of its budgetary needs to the Department of Finance.

Attachment

STATE OF CALIFORNIA
ARNOLD SCHWARZENEGGER, GOVERNOR
 

PUBLIC UTILITIES COMMISSION
505 VAN NESS AVENUE
SAN FRANCISCO, CA 94102-3298

June 1, 2005

To: Telecommunications Carriers Serving Customers Approved for California Teleconnect Fund Discounts 

Re: California Teleconnect Fund Administrative Letter No. 8

Implementation of Public Utilities Code Section 884

SB 720, signed by the Governor on September 24, 2003, amended Section 884 of the Public Utilities Code to include the following:

(b) If the moneys expended from the California Teleconnect Fund Administrative Committee Fund are less than the amounts appropriated in the annual Budget Act for the 2003-04 and 2004-05 fiscal years, from the unencumbered difference between what was appropriated and what was expended , notwithstanding any other law or existing program of the commission but consistent with the purposes for which those funds are appropriated, the commission may expend up to three million dollars ($3,000,000) for up to an additional 40 percent of the one-time installation costs for entities that do not have access to advanced telecommunications services.

(c) For the purpose of this section:

(1) "Advanced telecommunications services" includes high speed communications services such as digital subscriber line (DSL) services and T-1 technology.

TD is implementing this program by this administrative letter.

This program is limited only to 40% of the cost to install new qualifying advanced services. Service providers may submit claims, with the following limitations:

• Service provider reimbursement must be for qualifying services provided to CTF-eligible customers. Qualifying services include DSL, and switched 56, ISDN, T1, DS-3 and up to OC 192 and their functional equivalents. 1MB and its functional equivalents are not included.
• Discounts are only for new, advanced services customers. Customers who are installing additional advanced service capability are not eligible for this discount.
• Installation dates must be after September 23, 2003 and prior to March 1, 2006.
• Claims must be submitted prior to March 1, 2006. A one-time exception to the one year and forty-five day and one claim rule is granted for this special purpose.
• Claims must be submitted using the attached claim form and supporting workpapers, using the attached example workpaper format.
• The 40% CTF grant must first be offset by any E-rate grant funding applicable to the service for which a claim is made.
• Claims must be segmented into discounts by calendar month. All reimbursements provided during a calendar month must be included in the claim for that month.
• Claims will be paid on a first-come, first serve basis. If the funding is exhausted prior to March 1, 2006, the CTF will be unable to reimburse those claims. TD will provide the status of the funds remaining for the benefit of potential claimants.

Please address questions about this administrative letter to Katherine Morehouse, 415-703-5331.

John M. Leutza, Director
Telecommunications Division