STATE OF CALIFORNIA
ARNOLD SCHWARZENEGGER, Governor

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

February 24, 2005

The Honorable Martha Escutia
Chairwoman
Senate Energy, Utilities, and Communication Committee
State Capitol, Room 5046
Sacramento, CA 95814

Dear Senator Escutia:

I am pleased to forward to you answers to your Committee’s questions regarding the activities and operations of the California Public Utilities Commission. I trust that the answers will provide you with the information that you need. As a follow up to your question at the February 22nd hearing, we have also included in our answer detailed information on the amount of refunds received by the utilities and DWR as a result of on-going FERC and court litigation.

Please have your staff contact our office if they need any additional information.

Sincerely,

STEVE LARSON
Executive Director
Attachments

Cc: Senator Bill Morrow
Senator Kevin Murray
Senator Richard Alarcon
Senator Joe Simitian
Senator Jim Battin Randy Chinn
Senator Debra Bowen Lawrence Lingbloom
Senator John Campbell
Senator Dave Cox
Senator Joseph Dunn
Senator Christine Kehoe

RESPONSES TO THE SENATE ENERGY COMMITTEE QUESTIONS TO THE CALIFORNIA PUBLIC UTILITIES COMMISSION

IN PREPARATION FOR THE MARCH 1st COMMITTEE MEETING

Energy

1. What specifically has the Commission done to reduce electric rates and what will the commission do to return electric rates to pre-crisis levels?

• By Decision (D.) 03-07-029 the Commission reduced Southern California Edison Company’s rates by approximately 13%, $1.3 billion annually, to reflect the recovery of SCE’s historic procurement costs incurred during the energy crisis.
   
• By D.04-02-062 the CPUC reduced PG&E’s rates by approximately 8%, $800 million annually, to reflect resolution of bankruptcy issues and the issuance of the modified settlement agreement adopted in D.03-12-035.
   
• By D.03-09-018 the CPUC reduced DWR’s revenue requirement by $1.002 billion to return reserves DWR no longer needed.
   
• The CPUC has taken other steps to reduce rates:
  
  Participating at FERC in the renegotiation of DWR contracts and settlements with energy suppliers on refunds of procurement costs.
  
  Authorizing financing of PG&E’s Regulatory Asset with lower cost debt financing using the dedicated rate component (DRC).
  
  Ensuring cost-effective procurement contracts through competitive solicitations.

What specifically has the Commission done to reduce electric rates?
Supplemental Response

At the request of Senator Escutia at the February 22nd hearing, the following information addresses the amount and disposition of cash refunds received by the utilities and DWR.

PG&E:

• In 2004, PG&E applied $183 million received in refunds from the Enron ESP Claim, other ESP Claims and the El Paso settlement to reduce its Regulatory Asset (RA). PG&E’s 2004 electric revenue requirement decreased by approximately $10 million as a result of the reductions in the RA from the settlements.
   
• PG&E’s practice is to not reflect supplier refunds in the RA until settlements are final and unappealable. According to PG&E, settlements with Duke, Dynegy, and Mirant are not yet final and unappealable.
   
• Since, the RA revenue requirement is allocated to customers on an equal cents per kilowatt-hour basis pursuant to the rate design settlement agreement adopted in D.04-02-062, the effect of applying refunds to the RA is to give customers the benefit of the refunds on an equal cents per Kwh basis.
   
• Energy supplier refunds received after the second series of bonds to finance the RA have been issued are to be refunded to consumers via the newly established energy recovery bond balancing account.

SCE:

• SCE has credited approximately $169 million received in refunds from El Paso, Williams, Dynegy and Duke to its ERRA as of February 2005.
   
• Refunds are to be booked to the ERRA account to offset procurement costs (D. 03-10-087; Resolution E-3894). The refund amounts credited to ERRA will be passed on to customers in a consolidated revenue requirement change after the 2005 DWR revenue requirement decision is issued (expected in March ’05).
   
• SCE’s ERRA revenues are currently allocated to customers on a system average percent change basis; allocation of refunds based on the ERRA allocation will result in refunds allocated as follows:
  
  Domestic customers: 35%
  Small and medium commercial customers: 40%
  Industrial customers: 21%
  Agricultural and pumping customers: 3%
  Street lighting: 1%.

SDG&E:

• SDG&E has credited $ 59 million in supplier refunds received from El Paso, Williams, Dynegy and Duke to electric accounts as of February 2005.
   
• Out of this total, $31 million was used to reduce SDG&E’s under-collection associated with the 6.5 cent/kWh energy price cap for residential and small commercial customers mandated by AB 265 in year 2000. $28 million has been credited to the ERRA account.
   
• Until the elimination of the AB 265 under-collection, SDG&E was allowed (D.03-10-087; Resolution E-3893) to use 70% of the supplier refunds to reduce this under-collection as customers subject to AB 265 represented 70% of the total sales. The remaining 30% were credited to the ERRA.
   
• The AB 265 under-collection was eliminated on 11/30/04. Beginning December 2004, all refunds are credited to ERRA.
   
• SDG&E’s ERRA tariffs specify that the ERRA balance will be amortized in customer rates when the over or under collection reaches 5% of the prior year’s utility owned or procured energy expenses (approximately $30 million).
   
• SDG&E has not yet amortized its ERRA balance since its has not reached the “trigger” amount to date; SDG&E expects that the ERRA balance will be over collected by more than the “trigger” amount by mid-2005.

DWR:

In addition to the refunds directly received by PG&E, SCE and SDG&E, DWR has received the following refunds from suppliers.

El Paso Corp: $163.4 million
Dynegy: $98.7 million
Duke: $13.5 million
El Paso Electric: $15.5 million
Portland General: $6.1

Total DWR Monies Received as of 1/31/05: (Approximately) $297.2 million 

2. Please provide an estimate of the reduction in ratepayer obligations associated with the issuance of bonds pursuant to SB 772 (Bowen), Chapter 46, Statutes of 2004. Please compare the current estimate to the estimate provided a year ago. 

When PG&E finishes it second bond sale by the end of this year, nominal savings to ratepayers will exceed $1 billion. This level of savings is consistent with previous estimates of potential savings to ratepayers. 

On February 3, 2005, PG&E through a subsidiary sold almost $1.9 billion of bonds in the first of two Bond offerings. PG&E sold five asset-backed securities (ABS) maturing in one year to about 7.7 years, paying interest of 3.32 percent to 4.47 percent. The average coupon rate is 4.18%. This bond issuance results in a Nominal Savings to ratepayers of $745 million. With the second bond issuance by the end of this year we expect total ratepayer savings to exceed $1 billion in line with estimated ratepayer savings of about $1.0 billion anticipated a year ago, (PG&E Modified Settlement Agreement (MSA) Decision (D.) 03-12-035, page 72 and SB772, 848.1 (a)).

The Commission’s Financing Team worked closely with PG&E on this transaction, and it is expected to work with PG&E on the second transaction to maximize ratepayer savings.

3. What are the current cost responsibility surcharge under-collections for each IOU? What are the forecasted under-collections and projected repayment dates? Please provide updates to responses provided in January 2003.

Since January, 2003 the Commission has completed the following major items regarding the “cost responsibility surcharge” of Direct Access customers.

July 2003

• The Commission completed its promised “re-look” at the 2.7 cent cap on the Direct Access Cost Responsibility Surcharge (DA CRS) and found that it was not necessary to raise the cap in order to ensure payback of the undercollection from Direct Access customers by the end of the DWR contracts in 2011.

January 2005

• The Commission finalized the 2001-2002 undercollection obligations of Direct Access customers, and adopted a near-final estimate of the 2003 undercollection

In 2005, the Commission will complete its biannual “re-look” at the sufficiency of the current 2.7 cent cap on the DA CRS, as it promised to do in July 2003.

In D.05-01-040 the Commission adopted the undercollections shown below:

In its 2003 Decision to maintain the DA CRS cap at 2.7 cents, the Commission stated its goal of full payback of the undercollection from Direct Access customers by the time most DWR contracts end, in 2011. However, that decision also provided for periodic reassessment of the cap, in order to check whether forecasts were deviating from actual results. This provision for timely midcourse corrections and periodic readjustments of the cap to ensure payback by 2011 is intended to protect bundled customers. The cap can be periodically adjusted, as needed, to reflect updated forecast data so that full repayment occurs no later than 2011.

The Commission concluded that reassessment of the cap once every two years is sufficient to assure that the payback schedule is met, unless significant variances in certain forecast variables indicated a need to revisit the cap sooner[1]. We specified that the next regular reassessment of the DA CRS cap would be initiated two years from the effective date of this order, or by July 2005.

Because the 2005 proceeding to reassess the DA CRS cap has not yet begun, there is no Commission-adopted estimate of the projected repayment dates more recent than the July 2003 decision. However, Commission staff have been working regularly with DWR staff, and informal updated estimates of the expected paydown dates have been prepared. It is important to note that these estimates have not been reviewed or agreed upon by either the IOUs or the affected Direct Access customers. We expect that this public review process will be initiated in late March or early April, shortly after the Commission has completed its review and allocation of the 2005 DWR revenue requirement. Based solely on these staff-level estimates, the current estimated high balances and paydown dates are provided in the table below:

Compared to the estimates provided to the Committee in January, 2003, as well as subsequent estimates that served as the basis for the Commission’s decision to leave the cap at 2.7 cents, the outlook for PG&E has improved somewhat, while paydown in SDG&E territory is now expected to occur much sooner, and paydown in Edison territory is now expected to extend to 2016. The outlook for SDG&E improved because more usage pays the CRS than was originally expected. The outlook for Edison worsened because refinements that improved the accuracy of the DWR calculations resulted in increases in the estimated undercollection that must be paid down over time.

Finally, it is important to note that, in the past, estimates like these have been revised considerably once they have undergone intensive scrutiny by the IOUs and customer groups. Nevertheless, the possibility that the undercollection in Edison territory may extend beyond the length of the DWR contracts is a matter of significant concern to the Commission, given our goal of returning all of the undercollection to bundled customers by 2011.
 

4. Does the Commission believe renewable energy credits (i.e. unbundled from energy) may be used for purposes of compliance with the Renewable Portfolio Standard (RPS) established by SB 1078 (Sher), Chapter 516, Statutes of 2002? Please explain.

The Commission has said very little regarding the use of tradable renewable energy credits (TRECs) in the RPS program. In D.03-06-071, which implemented the program, the Commission did not adopt a TREC system, finding that:

While we leave open the possibility that a REC trading system may be implemented in the future, we note that creation of such a system raises a number of significant issues that would need to be addressed. Before we consider a REC trading system, we will need a clear showing that a REC trading system would be consistent with the specific goals of SB 1078, would not create or exacerbate environmental justice problems, and would not dilute the environmental benefits provided by renewable generation." (Decision at p.9-10)

In the December 16th, 2004 Scoping Memo for the RPS proceeding, the Commission solicited comments from parties regarding how a TREC system could be designed to meet the requirements specified above. Commission staff is aware of the Legislature's interest in this subject, and tailored the request for TREC comments accordingly, specifically seeking input regarding "initially limited applications of the concept, such as inter-utility trades."

Staff believes that a limited, inter-utility application of the TREC model may provide near-term relief from transmission constraints in RPS development, and may lower the cost to ratepayers of RPS compliance, without requiring further Legislative authorization.

A broader TREC market, encompassing ESPs, municipal utilities and other IOUs throughout the West, might provide greater efficiency and flexibility, but is clearly beyond the ability of the Commission to affect. Any staff effort to implement an inter-utility TREC system would be explicitly designed for compatibility with a larger TREC market, should one develop.

5. What has the Commission done to ensure energy service providers (ESPs) have met their RPS obligations which began January 1, 2003? How will the Commission ensure ESPs participate under the same terms and conditions applicable to IOUs as required by SB 1078? How is the Commission tracking direct access contract expirations and renewals in order to calculate ESPs’ accumulation of RPS procurement obligations?

With the first RPS solicitation successfully launched last summer, the Commission initiated a two-step process in December whereby ESPs will be brought in to the RPS program. These steps are;

• Determine the extent of the Commission's legal authority to direct ESPs to take specific steps in renewable procurement. Once these legal parameters have been established;
   
• Address technical questions regarding ESP procurement planning for RPS and the timing and content of annual solicitations to reach the 20% goal. SB 1078 requires that all ESPs begin procuring renewable generation under the RPS in 2006.

Both of these steps are being addressed in the RPS proceeding.

SB 1078 also requires that ESPs apply RPS targets to procurement for customers acquiring service after January 1, 2003. Direct Access was suspended on September 20th, 2001, and no new customers have been permitted since that date; hence, this provision of SB 1078 has not been applicable in practice.

The RPS statute further requires, although the language is ambiguous, that RPS targets apply to sales to customers with contracts that expire and are subsequently renewed. When the Commission completes the process of establishing its legal authority to direct RPS procurement by ESPs, it will review the relevant contracts of the ESPs and will consider this information when setting annual procurement targets.  

6. Has the Commission implemented the ESP registration requirements contained in AB 117 (Migden), Chapter 838, Statutes of 2002?

Yes, as required by the statute, by D.03-12-015, the Commission adopted ESP registration requirements for entities offering electric service to large customers (>20 kW) within the service territory of an electrical corporation. As a result, the entities serving large customers fulfilled all requirements and were registered by the Commission’s Energy Division. There are currently 17 ESPs registered to serve small and large customers, a listing of which is available on the Commission’s web page. Each month, the Energy Division verifies that all entities serving customers in the utility service territories are registered.

7. What is the status of implementation of the SB 39XX program (Burton), Chapter 19, Statutes of 2001?

The Commission has adopted and is implementing all Standards required by SB 39XX. Generators have argued, however, that the program is federally pre-empted and may file court challenges.

In May 2005, the Commission adopted General Order (G.O.) 167, which among other things incorporated Maintenance Standards adopted by the California Electric Facilities Standards Committee (CEFSC) for plants larger than 50 Megawatts. (Smaller plants are covered by less detailed standards of conduct.) Commission staff has conducted three extensive audits to determine whether power plants comply with standards. These audits were for the:

• Huntington Beach power plant (January, 2005) which found many violations of standards; a response from the power plant operators is due February 27, 2005;
• El Segundo power plant (soon to be issued); and
• Potrero Power Plants (soon to be issued).

In the longer-term, the Commission will require power plants to submit summaries of their maintenance programs, which will allow more complete and consistent application of maintenance standards.

In December 2005, the Commission adopted a revision of the General Order to incorporate Operations Standards for power plants newly adopted by the CEFSC. Plants are required to certify adoption of operations plans by March 21, 2005. At that point, staff audits will examine whether power plants comply with operation standards. Plants will submit summaries of the operations plans in late spring or early summer, to allow staff to apply standards more completely and consistently.

In addition to Maintenance and Operations standards, the Commission is auditing for compliance with two other standards. First, the CEFSC determined that enforcement of Maintenance and Operation Standards would be feasible only if plants kept systematic and chronological records of their operations. Therefore, the CEFSC adopted Logbook Standards, which the Commission has incorporated into the G.O.

Finally, as required by SB 39xx, the Commission has incorporated the Independent System Operators Outage Coordination Protocols into the GO.

The Commission continues to inspect all outages at thermal power plants larger than 50 megawatts, conducting 638 such inspections in 2004. Staff maintains a data base of the results of such inspections to help target power plant audits where they are most needed.

In addition, the Commission shares information gathered through its inspections and audits with other state agencies. The Commission works with the CEC to maintain a database on power plant status and condition. The Commission has access to the ISO’s detailed database on power plant outages. The Commission is working to conclude agreements with other agencies allowing full exchange of confidential power plant data.

Finally, the Commission’s May 2004 decision requires power plants to report design, availability, and outage information to a the Generation Availability Data base maintained by the North American Electricity Reliability Council. Plants larger than 50 megawatts must report historical data back to 1998. Smaller plants report current data only. Data is just beginning to arrive at NERC. Commission staff will analyze that data—for the first time available plant-by-plant, to help target audits where they are most needed.

Telecommunications

1. When the commission considers the proposed mergers between SBC and AT&T and between Verizon and MCI it will be guided by state law which requires that the commission first find that the merger does not adversely affect competition and that at least half of the benefits of the merger go to ratepayers. Please describe the commission’s process for reviewing this merger. Is merger review a high-enough priority to ensure sufficient resources are devoted to it?

The review of merger proposals among major utilities has always been a high priority of the Commission in the consideration of staff resources. Since mergers are not routine occurrences and the prospect of entertaining two large ones simultaneously is rather unique, the Commission will need to undertake efforts to provide sufficient staffing to ensure appropriate coverage of both merger applications. With Commission staffing reductions having occurred over the past few years, this will be a challenge for Commission management.

Utility mergers are covered by the requirements of Public Utilities Code Section 854. Before authorizing a merger of a utilities with revenues in excess of $500 million, the Commission `is required to consider various criteria, including whether the requested merger is in the public interest and not adverse to competition.

Traditionally, mergers, such as the ones involving SBC-ATT or Verizon-MCI, are considered in a Commission formal proceeding. The utilities seeking the merger would file an application supported by arguments to justify the merger, consistent with the criteria identified in Section 854. The application should also contain information about short and long-term economic benefits that would be generated by the merger. Interested parties would then have an opportunity to comment on the application. If needed evidentiary hearings could be held.

The process also requires the Commission to seek an advisory opinion from the Attorney General’s office.

The result of the process would be Commission decisions either approving, rejecting, or approving with modifications the proposed mergers. The process may take up to one year depending on the issues involved.  

2. The commission recently voted to stay the telephone consumer protections enacted in May 2004. The stay order said that the commission intended to act expeditiously to address implementation issues. What progress has the commission made in addressing those issues? What is the timetable for resolving those issues?

The Commission has stated its intention to resolve the telecommunications consumer protection issues by the end of the year. Commissioner Gruenich is planning an all party meeting to specifically focus on the telecommunications consumer protection issues in late March or early April 2005.

In D.05-01-058 (adopted in January 2005), the Commission stayed the telecommunications consumer protections it adopted in May 2004 to;

• Allow adequate time to address implementation issues;
• Ensure that California’s consumer protection structure will be viable and enforceable; and,
• Consider a broader reexamination of policy issues related to those consumer protections.

This stay also allows the Commission time to address issues raised by recently filed Petitions for Modification of the Decision. In D.05-01-058, the Commission stated its intention to specify clearly the effective date of the new consumer protection structure, and the termination date of the stay by no later than the end of 2005.

3. The availability of broadband infrastructure is increasingly an economic development issue that also raises questions about universal access. The Commission recently released a draft report on broadband deployment in California which observed a Digital Divide based on ethnicity and income. How is the Commission addressing this Digital Divide issue?

The Commission initiated the Broadband proceeding, Rulemaking (R.)03-04-003, in response to SB 1563 (PU Code Section 709). The Draft Report, released on February 1, 2005, finds that broadband access and usage is low for three California communities--disabled persons, low income populations and rural areas, even though the broadband market is growing in California and is expected to continue growing with refinement of a some regulatory and legal practices. Chapter 9 of the Draft Report, "Conclusions and Recommendations" outlines actions that will address barriers facing the lower use communities.

Some of the proposed solutions are within the Commission's authority to implement;

• Develop and monitor a baseline metrics for measuring broadband usage in specific geographic areas and among demographic groups in the state.
• Expand the Deaf and Disabled Telecommunications Program to provide subsidized customer premises equipment for VoIP, broadband and assisted services for people with disabilities, including JAWS screen-reading and voice recognition software.

The Broadband report identified other more far reaching options that would expand broadband services if the Legislature and Governor seek to achieve this goal. These options could include;

• Make eliminating barriers broadband deployment and access an explicit policy objective of all state agencies, boards and commissions.
• State government should lead by example in operations and public access--e.g. accessible websites; web casing of public meetings; video conferencing; voice over the Internet telephony.
• Develop a statewide California Broadband Task Force charged with the ongoing task of identifying barriers to deployment and access to advanced telecommunications services and making recommendations to eliminate such barriers.
• Provide time-limited tax incentives to providers deploying broadband facilities in geographic areas and communities with lower use rates.
• Provide infrastructure grants and low-interest loan guarantees for construction of broadband facilities to serve low penetration areas and communities.
• Provide state funds (general fund, Public Goods Charge or Universal Service Fund) for a matching grant program to encourage public/private partnerships for the deployment of broadband in lower use areas and communities (one-third state, one-third local government or CBO, one-third private funds or in-kind contribution).
• Establish a special tax deduction for donation of used laptop and desktop computers to CBO projects that facilitate broadband access in lower use areas and communities.

Office of Ratepayer Advocates

1. It has become clear that there exist institutional barriers which impede ORA’s effectiveness. Those barriers include the ORA Director’s lack of control over ORA’s budget and staff, including legal representation. How are you going to improve ORA’s effectiveness and independence?

When Ms. Appling was appointed Director of ORA by Governor Schwarzenegger, she identified areas both internal and external to ORA that she felt needed changes or improvements. As to the external issues that she felt were beyond her unilateral control, she sought my assistance to resolve; (1) use of ORA’s budget and staff, and (2) legal support for ORA.

I am pleased to report that we have resolved the major part of Ms. Appling’s budget and staff issue simply by ensuring compliance with PU Code Section 304.5(f) which states that “funds in the Ratepayer Advocate Account shall be utilized exclusively by the division in the performance of its duties.” Secondly, the Commission has taken steps through the Executive Director to establish the Ratepayer Advocate Account by way of submission of a budget change proposal to the Department of Finance.

Regarding Ms. Appling’s concern about legal support for ORA, the General Counsel, prior to Ms. Appling’s arrival, already had undertaken necessary steps to increase and improve the legal staff available to ORA. The commission’s general counsel has met with Ms. Appling to assure her that ORA is one of Legal Division’s top priorities and that ORA consistently will have competent legal staff to develop and present its cases not only through pleadings, but also in commission hearing rooms and before the full commission. My understanding is that those talks are productive and ongoing and that legal staffing assigned to ORA cases has increased significantly since the reorganization of the Legal Division in July, 2004.

I believe that this commission benefits from objective and independent analysis provided by ORA. I fully support and will do what I reasonably can to help ORA improve its effectiveness. However, I’m sure that Ms. Appling will readily acknowledge that ORA has internal challenges that Ms. Appling also must address that are squarely within her control and responsibility, and for which she is accountable.

Rail Safety

1. Recent train and grade crossing accidents raise concerns about rail safety, which is a responsibility of the Commission. Does the Commission have sufficient authority and resources to ensure safe railway operations?

PU Code §§ 315 and 309.7 provide authority for the Commission to investigate every rail accident that results in death, injury or property damage; to inspect all main line and branch line track annually; to inspect every mechanical repair facility every six months; and to enforce federal railroad safety regulations in accordance with an agreement with the Federal Railroad Administration.

In the last two years, attrition, vacancy sweeps and hiring freezes have reduced the current staffing levels of the Rail Crossings Branch and the Rail Operations Safety Branches to the point where they are not able to meet these legislative mandates[2]. The Rail Operations Safety Branch (which is funded by the Railroad Users Fee) is in the process of staffing back up, but the funding level of this program is not sufficient to investigate the numbers of accidents that, in the Commission’s opinion, require investigation.[3] The Rail Crossings Safety Branch (which is funded by the State Highway Account) is also staffing back up, but its funding levels are not sufficient for it to absorb the workload of the federal government’s impending issuance of the final “Quiet Zone” rules. These rules will preempt California law, and will allow trains to not blow their horns at crossings that, under certain conditions, are protected by active warning devices.

Following the implementation of the Federal Railroad Safety Act of 1970, which created the Federal Railroad Administration, federal preemption of state railroad safety regulation has been problematic for California. In July of 1991, the Southern Pacific Railway Co. derailed tank cars of metam sodium, a water-reactive herbicide, into the Upper Sacramento River north of Redding. The resulting spill destroyed all life in the river for 40 miles downstream, threatened the watershed of Lake Shasta, and represented one of the most catastrophic ecological disasters in California history. In 1992 the California legislature passed legislation, consistent with federal statutes, directing the Commission to identify Local Safety Hazard Sites within California, and adopt regulations to reduce potential hazards. The Commission initiated a rulemaking and complied with the legislative directives in its Decision D 97-09-045, identifying 19 Local Safety Hazard Sites in the state where greater regulatory oversight were needed. The railroads immediately sought and were granted injunctive relief in US Federal courts.

Following more than ten years of challenge at the US District and Appellate court levels, the CPUC finally exhausted all possible avenues of legal recourse when the US Supreme Court refused to hear California’s appeal of the lower courts decision that invalidated the Commissions identification of every Local Safety Hazard Site in California. It is significant to note, that since the Local Safety Hazard Sites exemption for state safety regulation was codified into the Federal Railroad Safety Act of 1970, not a single state has been successful in a bid to identify such a location.

Although the courts denied the Commissions identification of Local Safety Hazard Sites, they remanded other related issues back to the lower courts for rehearing. In 2004, the CPUC reached a settlement of the case with the railroads, and achieved a landmark success for railroad safety in gaining California’s legal right to enforce the railroads own operating rules over the Local Safety Hazard Sites identified by the Commission. This authority set a precedent, and exceeds that of the federal government in this area.

It is the ambiguities inherent to the Local Safety Hazard Sites exemptions for states within the Federal Railroad Safety Act of 1970 that thwarted the Commissions efforts to improve railroad safety in California. Commission staff and the CPUC legislative subcommittee are currently evaluating changes to that act, as well as other recommendations to modify two pieces of legislation at the federal level that we believe will significantly improve railroad safety. Specifically, the Schumer-Graham US Senate bill (not yet enrolled) calls for the investigation of every fatal railroad accident, more frequent inspection of railroads and railroad equipment, improvements to rail car tank design, the elimination of uncontrolled rail switches, greater penalties for railroads that do not comply with the law and increased funding for better regulation and inspection of the railroads.

HR 2378 (Oberstar) calls for sweeping reform of the railroad safety act including revision of the hours of service act and mandates the railroads development of fatigue counter measures, the further development and implementation of positive train control, the safety certification of track inspected by railroad employees, and whistleblower protection for railroad employees who report unsafe conditions to regulators.

I will continue to work with my staff to develop changes and recommendations for your consideration that will serve to improve railroad safety in California. 

Commission Process

1. The Commission has announced a meeting on climate change. While the issue is very real, it is not an issue which is at the core of the Commission’s mission. Moreover, there is no specific legal authority for the Commission to delve into this issue. The same can be said for other issues which the Commission has started to take up, such as the creation of an electric capacity market. Do such discretionary initiatives deprive resources from the Commission’s core regulatory functions? How does the Commission choose the issues it deals with, and how does the commission staff those issues without budget authorization?

The Commission’s core function is clearly ensuring that customers receive safe, reliable, environmentally-sensitive energy at just and reasonable rates. The Commission’s efforts on global climate change and capacity markets are consistent with this goal.

A major issue in reviewing the energy utilities’ procurement strategies, for example, is the need to assess the future availability, reliability, and price of energy resources. Just as the Commission in the past has routinely had to consider the economic, political, and technical trends affecting the future supply of energy resources, it is appropriate for the Commission to now consider the effect that climate change initiatives could have on the future supply of energy resources. Electric generation and consumption is the source of approximately thirty-five percent of California's greenhouse gas emissions. Thus any changes to the supply or price of energy resources due to climate change activities could have a significant effect on electric rates and reliability. Natural gas procurement and hydroelectric generation could also be significantly affected. Telecommunications and water utilities are also significant users of energy.

In addition to concerns over future economic costs, the Legislature has directed the Commission to consider environmental issues in such areas as renewable energy development (PU Code 399.1), utility research and development activities (PU Code 740.1) and utility procurement generally (PU Code 701.1). Consideration of environmental issues is also an important part of the Energy Action Plan adopted by the Commission and the CEC. An improved knowledge of climate change activities enhances the Commission’s ability to achieve these goals.

In adopting a green-house gas adder for use in considering electric procurement choices, it is important to note that the Commission chose this adder not as a value judgment over the societal costs of climate change but instead as an economic risk assessment that concerns over climate change are likely to result in future increases in the cost of fossil fuels. This type of planning is consistent with the resource procurement and planning activities the Commission has always undertaken. The Climate Change workshop was exceedingly useful in assisting the Commission in further evaluating this risk and potential means to mitigate it.

To this end, the Commission is working with the energy utilities to identify opportunities and actions to mitigate financial risk associated with carbon emissions, and to minimize the utilities' greenhouse gas emissions contributions. The Commission is working with the utilities to develop a plan that will be beneficial to ratepayers and residents of California, and to act responsibly and proactively to ensure that the utilities business practices are well positioned. Our efforts related to climate change are directly related to our charter to ensure reasonable rates and to promote the health of California's economy.

Similarly, the Commission is looking into the development of capacity markets as a mechanism to enforce/ensure resource adequacy, which is part of our core mission of regulating and overseeing the utilities’ obligation to serve and the Energy Service Providers’ obligation to meet reliability standards. Capacity markets can help implement resource adequacy because they have the potential to address several critical issues:

• Minimizing otherwise potentially stranded costs that may stem from load migration;
• Providing a means for small load serving entities, such as ESPs, of meeting the resource adequacy requirements since they often purchase in smaller amounts.
• Providing larger LSEs a forum in which to sell capacity;
• Allowing for market monitoring and market power mitigation; and
• Making implementation and enforcement of resource adequacy standards more manageable.

2. The SB 960 report shows that only 53% of Commission proceedings involving hearings were resolved on time, a decline from the 61% resolved on time in 2003. What accounts for this performance and what is the Commission doing to improve the timeliness of its decision-making?

The apparent decline actually reflects the closure of many proceedings that exceeded the 12 or 18 month deadline in earlier years. While we are actively managing current proceedings, we are also working diligently to resolve and close older proceedings.

The Commission is still dealing with a backlog of proceedings as a result of the energy crisis. Even so, we have been actively managing the 104 proceedings that were not resolved on a timely basis. Many of these proceedings are working dockets in which we continue to consider ongoing issues. Thus, in many of these proceedings, the Commission actually issued at least one decision and has been actively managing the cases.

Many of the open proceedings still relate to industry restructuring, and remain open to address lingering issues related to the energy crisis, such as the PG&E bankruptcy and Department of Water Resources contracting and bond issues. Other proceedings are impacted by external factors such as environmental reviews or action by other governmental agencies. Still others remain open because we have acceded to parties’ requests to leave the docket open, depend on issues being resolved in other proceedings, or are simply low priority, considering other pressing matters.

The breakdown of the 104 separate proceedings not resolved on schedule is as follows:

We will continue to address both our older proceedings and our timely current proceedings and seek to resolve the ongoing issues in a way that ensures administrative efficiency. I meet with ALJs in my assigned proceedings on a regular basis and I encourage the other Commissioners to do so, as well. In addition, I have directed the division directors to initiate industry coordination meetings with the ALJs and Commissioner advisors to ensure that issues are raised and addressed in a timely and coordinated fashion.

3. The SB 960 report shows that Commissioners were present in less than 1 out of every 5 hearing days. As you know, one of the motivations underlying SB 960 was to encourage more direct participation by Commissioners, including more time in the hearing room. What accounts for the absence of Commissioners in the hearing room and what are your suggestions for improving Commissioner attendance?

Commissioners are actively involved in their assigned proceedings and regularly meet with the assigned ALJs to discuss issues. The scoping memo ruling, issued by the Commissioner, sets forth the scope of the issues in a particular proceeding, as well as the schedule for resolving the proceeding. This is a very important mechanism to keep the Commissioner involved and to ensure that the record is developed to address issues in which they are actively interested. In addition, while their schedules do not often allow Commissioners to act as principal hearing officers, they do regularly attend prehearing conferences, final oral arguments and full panel hearings. Of course, Commissioners are also actively involved in reviewing the proposed decision and determining whether a simultaneous alternate should be issued. Assigned Commissioners are rarely able to choose to take on the role of Presiding Officer or PHO. Since those roles are the major source of attendance mandates in SB 960, assigned Commissioner attendance at most formal hearings in adjudicatory and ratesetting matters is discretionary.

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

The ALJ Division and the Legal Division are coordinating on a notice and comment process to address the confidentiality issues raised by SB 1488 and to consider further the balancing test to assess open decision-making and whether market-sensitive information is a trade secret, or whether it may lead to gaming behavior to the detriment of ratepayers. The staff of both the Commission and the CEC are working actively together to assess confidentiality concerns related to information presented in both the CEC’s IEPR proceeding and the Commission’s procurement proceeding. Our goal is to ensure open, transparent decision-making, consistent with protecting ratepayers to the extent necessary and lawful.

[1] These variables are natural gas prices, sales prices for off-system sales, and levels of Direct Access load.

To the extent that any one of these variables deviates significantly from the forecast assumptions underlying D.03-07-030, we shall order the assigned ALJ to take further procedural steps to consider the need for a reassessment of the level of the DA CRS cap.

[2] As reported by CPUC in the 2003 & 2004 Annual Railroad Safety Activity Report to the California State Legislature

[3] The CPUC currently investigates only approximately 10% of accidents that happen at grade crossings or accidents involving pedestrian/trespassers. Furthermore, we only investigate approximately 25% of derailments, train collisions and hazardous materials spills.