Grueneich Gamson Appendices 1 to 3 Revision 2
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COM/DGX/ALJ/DMG/hkr ** DRAFT Agenda ID #8801 (Rev. 2)

Decision PROPOSED DECISION OF COMMISSIONER GRUENEICH AND
ALJ GAMSON (Mailed 8/25/2009)

BEFORE THE PUBLIC UTILITIES COMMISSION OF THE STATE OF CALIFORNIA

Application of Southern California Edison Company (U338E) for Approval of its 2009-2011 Energy Efficiency Program Plans and Associated Public Goods Charge (PGC) and Procurement Funding Requests.

Application 08-07-021

(Filed July 21, 2008)

And Related Matters.

Application 08-07-022

Application 08-07-023

Application 08-07-031

DECISION APPROVING 2010 TO 2012
ENERGY EFFICIENCY PORTFOLIOS AND BUDGETS

TABLE OF CONTENTS

Title Page

DECISION APPROVING 2010 TO 2012 ENERGY EFFICIENCY PORTFOLIOS AND BUDGETS 22

1. Summary 22

2. Procedural Background 1111

3. Overview of Utility Proposals 2424

4. Policy Guidance 2727

5. Statewide Programs 102102

6. Non-Statewide Programs 243243

7. Evaluation, Measurement, and Verification (EM&V) 291291

8. Low-Income Energy Efficiency 303303

9. Mid-Cycle Funding, Fund-Shifting Rules and Rolling Budgets 304304

10. Consistency With Criteria From Decision 07-10-032 310310

11. Incremental Funding Requirements, Requested Ratemaking
Treatment and Projected Rate/Bill Impacts 312312

12. Implementation Issues 318318

13. Categorization and Assignment of Proceeding 329329

14. Comments on Proposed Decision 329329

Findings of Fact 332332

Conclusions of Law 350350

ORDER 362362

Appendix 1: Proposed Program Budgets

Appendix 2: Program Performance Metrics

Appendix 3: Determination of Customer Incentives for SDG&E and SoCalGas

DECISION APPROVING 2010 TO 2012
ENERGY EFFICIENCY PORTFOLIOS AND BUDGETS

1. Summary

Energy efficiency is the first priority in California's loading order for energy resources. This decision authorizes the next three years of ratepayer-supported energy efficiency programs in step with California's energy policies and greenhouse gas mitigation strategies. Specifically, this decision approves the 2010-20121 energy efficiency programs to be managed by California's investor-owned utilities2 and supported with approximately $3.1 billion of ratepayer funding. This amount is about 42% higher than the prior three-year program cycle and will support programs designed to produce deeper and more comprehensive savings that we believe California's utilities can and will achieve.

In 2008, the Commission adopted the landmark California Energy Efficiency Long Term Strategic Plan (Strategic Plan).3 The programs and budgets we authorize in this decision will make significant progress toward our Strategic Plan goals and our adopted Big, Bold Energy Efficiency Programmatic Initiatives, including taking the next steps towards achieving zero net energy homes in California as standard practice by 2020 and zero net energy commercial buildings by 2030.

By law, the utilities' efficiency portfolios must be cost-effective and program expenditures must be just and reasonable. Precisely because California and our utilities have been leaders in energy efficiency for over thirty years, our energy efficiency programs can no longer rely primarily on inexpensive, easy to obtain energy efficiency but must pursue more challenging and costly implementation efforts.

This decision addresses four main issues:

1) Goals: The energy savings goals the utilities must achieve between 2010 and 2012;

2) Budgets: The budgets we authorize to achieve those goals and the cost-effectiveness finding that is required, with these two in turn determining justifiable ratepayer costs and energy resource savings;

3) Programs: The programs authorized to produce these savings; and

4) EM&V: The evaluation, measurement and verification (EM&V) procedures we will use to ensure projected savings actually occur.

We summarize below briefly our determinations in each of these areas.

1) Goals: Energy savings goals for 2010-2012

In prior decisions we have set annual and cumulative4 energy savings goals for the utilities through 2020. At the utilities' request and with public input, we modified our adopted goals earlier this year in D.09-05-037. In this decision, we further modify these goals to reflect updated values for planned savings.

We further reduce total electricity (kWh) goals by 5%, and cumulative demand (kW) goals by 1% for the 2010-2012 period.5 We do not change the natural gas (therm) goals. The adjusted goals reflect an updated understanding of energy savings potential available to the utilities, and set an ambitious standard for energy efficiency delivery in step with the scale our California's energy and climate goals.

Goals and Budgets for the 2010-2012 Program Cycle

 

PG&E

SCE

SDG&E

SoCal

 Total

2010-2012 Program Cycle Electricity Savings (GWh)

3,100

3,316

539

-

6,965

Cumulative Savings (GWh)

6,950

7,581

1,379

-

15,910

2010-2012 Program Cycle Peak Savings (MW)

703

727

107

-

1,537

Cumulative Peak Savings (MW)

1,546

1,644

269

-

3,459

2010-2012 Program Cycle Natural Gas Savings (MMTh)

48.9

-

11.4

90

150.3

Cumulative Natural Gas Savings (MMTh)

108.8

-

24.2

175

308.1

2010-2012 GHG Reductions (MMt CO2e)

1.27

1.08

0.24

0.48

3.07

2010-2012 Budgets (millions)

$ 1,338

$ 1,228

$ 278

$ 285

$ 3,129

Notes:

    1. Cumulative Savings include annual goals set for the 2006-2008 program cycle. Under CPUC policy IOUs are required to ensure that savings claimed in prior program cycles persist over time and any shortfalls between goals and achievements are made up in subsequent cycles.

    2. GHG calculations assume 326 MMt CO2e avoided per GWh and 5,300 CO2e avoided per MMth.

2) Budgets: Authorized budgets and cost-effectiveness requirements

By law, each utility's portfolio of programs for the funding cycle (2010-2012)6 must be cost-effective. We are also required to ensure that proposed expenditures are reasonable and do not include unnecessary costs. At the same time, because of past successes, our increased emphasis on ensuring that energy efficiency efforts result in long-lasting savings and not just short-term results, and the more comprehensive approach adopted in California's Strategic Plan, many energy efficiency efforts are more costly than previously.

We approve today approximately $3.1 billion in total, three year (2010-2012) budgets for the four utilities. These budgets are 42% higher than in the previous three-year cycle, but are 20% less than requested by the utilities. While there is uncertainty in actual savings and costs of these very large portfolios and acknowledging that not all potential costs or savings are accounted for in this decision, the adopted portfolios are cost-effective. We have reduced proposed expenditures in several areas, including:

· The utilities proposed administrative costs that totaled 14% of overall budgets; we place a cap of 10% on administrative costs, which is consistent with national averages for other energy efficiency programs and our other clean energy programs. Similarly, we place a target of 20% on non-resource support costs.7

· We reduce marketing, education and outreach (ME&O) costs from 9% to 6%, again in the direction of national averages and to reflect a more integrated approach we are taking across all of the clean energy ME&O activities;

· We reduce EM&V budget share from 8% to 4% to align with national averages and to reflect the overall increase in program budgets. We will re-examine specific funding needs in a decision later this year. The Commission will ensure that it has the means necessary to meet the Commission's commitment to effective EM&V.

Our legal duty is to ensure cost-effectiveness and reasonable use of ratepayer monies. As proposed, the utility budgets did not meet our legal requirements. With the changes we make, they do so.

3) Programs: Authorized programs for 2010-2012

The majority of the proposed utility programs are well-designed and among the best in the country, if not the world. However, we are committed to ensuring ratepayer funded utility programs align with the Strategic Plan and reflect current conditions and our EM&V results. We thus have made several changes to ensure ratepayer funds are deployed most effectively and that the most promising programs are sufficiently funded.

· Beginning, January 1, 2010, the utilities will launch 12 statewide programs. The utilities' original March 2008 applications proposed over 300 separate programs. At our request, the utilities have reformulated them into the 12 statewide programs that will be consistent throughout the utilities' service areas. Each utility will also offer additional smaller programs to meet unique conditions in its service area or to pilot new approaches but all programs will be meshed into statewide efforts.

· We launch the California Statewide Program for Residential Energy Efficiency (CalSPREE), under which we establish the largest and most comprehensive residential retrofit program in the United States, funded at $100 million for 2010-2012, out of over $900 million for residential energy efficiency during the same period.

· The utilities will offer a tiered suite of residential "whole house" saving options aimed at reducing the annual energy consumption of 130,000 homes over 3 years by 20% through comprehensive retrofits. The program, in coordination with the California Energy Commission's Comprehensive Residential Building Retrofit Program funded through the American Recovery and Reinvestment Act (ARRA), will capture deep savings potential within existing homes and create green jobs in the growing California home performance industry.

· Reflecting rapid progress toward lighting market transformation and the upcoming federal and state mandated phase-out of conventional incandescent lights, fewer ratepayer subsidies will be needed for basic compact fluorescent lights (CFLs) that have commanded considerable funding in past portfolio budgets. Funding for basic CFL programs are reduced and reallocated to advanced lighting programs and other lighting market transformation activities.

· We enthusiastically support increased attention to "benchmarks" as a way to both inform and motivate building owners to undertake energy improvements. This will be a cornerstone of the commercial and governmental efficiency programs, and also supports implementation of AB 1103, which requires building owners to provide building consumption benchmarks in all commercial real estate transactions starting January 2010. We increase the budget above the utilities' proposed level for building benchmarking efforts in the commercial sector and direct that utilities benchmark any facility "touched" by our Commercial Energy Efficiency Program. We also approve improved energy audit and assessment tools that will help residential customers understand their homes' relative efficiency and their best options for improvement.

· We increase the budget above the utilities' proposed level for a very promising industrial program called Continuous Energy Improvement, which will broaden the scope of energy saving programs available to the industrial sector, a sector with significant untapped energy efficiency potential.

· We provide $265 million of funding for energy efficiency programs that will be carried out by some 64 cities, counties, and regional agencies, offering a wide range of programs including government facility retrofits, "reach" building codes, and direct installation programs for small businesses and residents. In addition, the decision funds $83 million for statewide partnerships with the University of California, the California State University System, the Community Colleges, the Department of Corrections, and the Department of General Services to support comprehensive energy efficiency upgrades to state buildings.

· We initiate a new branding effort to coordinate messages about energy efficiency, renewable energy and demand-side management, alongside those of climate action. Concurrently, we will launch this year an Energy Efficiency Web Portal as an on-line clearinghouse of efficiency information for energy practitioners and consumers.

· We direct our Energy Division to issue a Strategic Plan Progress Report by June 2011. This report will assess the key actions, coordinated tasks, and timelines necessary to achieve the goals of the Strategic Plan. In several sections of this decision, we give further detail as to what factors should be considered in determining progress toward the objectives of the Strategic Plan.

· We conditionally approve and fund pilot projects designed to advance the core objectives of the Strategic Plan and our Zero Net Energy targets through innovative program design and delivery methods. We require a clear end point for and increased oversight of these pilots in order to justify that their lessons are identified and disseminate successful pilots into core statewide programs.

4) EM&V: Evaluation, Measurement and Verification

EM&V supports our ability to translate ratepayer investments in energy efficiency into reliable energy savings estimates that can be counted upon in planning for energy procurement and greenhouse gas reductions. In addition, evaluation studies inform our understanding of program effectiveness and are critical in our ability make forward-looking improvements to programs and efficiency investment portfolios. In short, the success of California's efforts in energy efficiency depends on the success of our EM&V efforts.

In this decision we commit to streamlining our EM&V efforts with the goal of increasing their usefulness while lessening the contentiousness witnessed in recent times. In particular, we commit to holding the savings assumptions used in planning this portfolio constant over the course of the program cycle for the purpose of tracking reported savings against goals, contingent on compliance and consistency in utility-submitted data. We also articulate renewed goals for EM&V activities to guide the development of specific EM&V plans for the upcoming program cycle. In order to set California on course to ensure an effective EM&V framework post-2012, we direct our Energy Division staff to initiate a comprehensive review of California's current technical and institutional EM&V frameworks and the extent to which they can meet our needs in the future. This action is in step with similar review being undertaken in other key regions of the country. We will issue a detailed follow-up decision on EM&V by the end of the year.

We are pleased that this decision rests on a foundation of greatly expanded input and review from stakeholders - product manufacturers, building and construction industry representatives, local governments, financial services actors, and the many professionals in the energy efficiency delivery business - all of whom understand what it takes to mobilize action and investment by energy consumers, the ultimate decision-makers we seek to serve with this decision. We welcome their continued engagement with programs as they roll out and respond to market conditions.

We also recognize that utility efficiency programs are a critical component in California's ability to mobilize the hundreds of millions of dollars available to California's households, businesses and governmental agencies for energy efficiency purposes through the federal economic stimulus package and provide green jobs for the future. We value this additional federal investment support that will further leverage efficiency investments in California. We look forward to continued exchange of future efficiency strategies and initiatives with energy policy leaders in Washington.

In this decision, we take the first step not in imagining new and better portfolios of energy efficiency programs, but in their actual implementation. Embodied in the direction given to utilities is unprecedented cooperation and cost sharing among all levels of government, multiple state agencies, and emerging market actors. We are confident that the quality of programs implemented by utilities and their partners over the next three years will be a national model and keep California at the forefront of addressing our nation's energy and climate challenges.

2. Procedural Background

This decision is the most recent in a series of Commission actions that have changed the paradigm for utility energy efficiency programs in California. Public Utilities Code Section 454.5(b)(9)(c),8 the Energy Action Plan and past Commission decisions have established a policy to procure all cost-effective conservation and energy efficiency resources before adding generation resources.

In Decision (D).04-09-060, the Commission articulated its goal to pursue all cost-effective energy efficiency opportunities in support of the Energy Action Plan commitment that conservation and energy efficiency are first in the "loading order" of electricity and natural gas resources. In accordance with this overarching goal, D.04-09-060 at 22 established short- and long-term numerical targets for electricity and natural gas savings. We stated that these targets must be aggressive and must stretch the capabilities and efforts of all those involved in program planning and implementation.

We specified that achievement of the goals must reflect actual installations of energy efficiency measures, not simply commitments to install them. We ordered the utilities to reflect our adopted goals in their resource acquisition and procurement plans so that ratepayers do not procure redundant supply-side resources over the short- or long-term.9 To encourage longer term planning and funding, we authorized a three-year program implementation and funding cycle for electric and natural gas energy efficiency.

We created a framework for utility-administered energy efficiency programs in D. 04-09-060, D.05-01-055 and D.05-04-051. Those decisions made significant changes to the then-existing programs, including:

· Adoption of aggressive annual and ten-year cumulative goals for measured and verified electricity and natural gas savings by megawatt hour, megawatt, and therm;

· Allowing the utilities to develop their own programs and portfolios. Commission oversight of portfolio design was limited generally to determining whether each portfolio as a whole was cost-effective according to the Total Resource Cost and Program Administrator tests and achieved the utilities' numerical savings goals, and;

· Requiring the Commission's Energy Division to develop, launch and implement an extensive evaluation, measurement and verification (EM&V) program to ensure that the utility programs actually produced electricity and natural gas savings that could be relied on to offset the utility's electricity and natural gas purchases. The EM&V program is unprecedented both in the scope and scale of the undertaking and in the nature of the responsibilities placed on this Commission's regulatory staff.

In D.05-09-043 and D.05-11-011, we committed $2.2 billion in ratepayer funds to procure energy efficiency savings over the 2006-2008 program cycle and approved the utilities' program portfolios, including utility efforts to better integrate their programs at a strategic level. For example, we approved the development of a joint plan on statewide marketing and outreach; a sustainable communities program incorporating higher performance energy efficiency and demand reduction technologies, along with clean on-site generation, water conservation, transportation efficiencies and waste reduction strategies; and programs to assist customers in choosing and implementing a package of demand side management measures such as conservation, demand response, and self-generation.

We next summarize other important background and procedural activity leading up to this decision.

The purpose of Rulemaking (R.) 06-04-010 is to examine the Commission's post-2005 energy efficiency policies, programs, evaluation, measurement and verification and related issues. In D.07-10-032, the Interim Opinion on issues relating to future savings goals and program planning for 2009-2011 energy efficiency and beyond, we directed the utilities to prepare a comprehensive, long-term energy efficiency Strategic Plan (discussed below). D.07-10-032 also provided specific policy guidance to the utilities on the development and composition of their 2009-2011 energy efficiency portfolios. D.07-10-032 stated:

Assuring a more comprehensive, integrated model for energy efficiency will require a significant shift in the utilities' approach to program design, development and implementation. Although we have consistently encourage the utilities to think and act strategically in designing and delivering energy efficiency programs, the utilities and indeed other leaders in business and government must adopt a conceptual framework that is more comprehensive and forward looking.

D.07-10-032 also adopted three "Big, Bold Energy Initiatives"10 as goals for future energy efficiency programs, starting with the 2009-2011 portfolios: Zero net energy homes by 2020, zero net energy commercial buildings by 2030, and optimizing the HVAC industry in California, as well as goals for low-income energy efficiency programs. That decision requires a significant shift in the utilities' program mix toward approaches to market intervention which stimulate durable long-term savings and moderate a bias towards short-term measures that have manifested in recent cycles.

Following D.07-10-032, Assigned Commissioner and Administrative Law Judge (ALJ) Rulings issued on February 29, 2008, March 14, 2008, April 11, 2008 and April 21, 2008 in R.06-04-010 set out the requirements for the utilities' 2009-2011 energy efficiency portfolios. The February 29, 2008 Ruling stated "The program applications must reflect State energy policy, energy efficiency program initiatives discussed in D.07-10-032, and the Joint Utility Strategic Plan . . . ." That Ruling contained specific information requirements for the utilities to meet the requirements of Ordering Paragraphs 12, 13, 14 and 20 of D.07-10-032.

D.08-07-047 in the same docket clarified that energy savings goals for 2009-2011 were to be calculated on a gross basis, and adopted energy savings goals for California through 2020. However, that decision did not adopt utility-specific energy savings goals post-2011.

The utilities filed their initial proposed 2009-2011 energy efficiency portfolios on July 21, 2008. On July 31, 2008, Resolution ALJ 176-3218 preliminarily categorized the proceedings as ratesetting. The filings were consolidated by an ALJ Ruling issued August 1, 2008. The first prehearing conference (PHC) was held on August 11, 2008.

In their July 2008 applications, the utilities requested, in total, more than $3.7 billion for over 390 energy efficiency programs for 2009 through 2011. The utilities also jointly requested a number of changes to the way cost-effectiveness, energy savings goals and incentives would be calculated. Only 40% of the proposed statewide budget was categorized for customer incentives, rebates and direct install costs; 44%, or $1.65 billion, was earmarked for overhead, general and administrative costs. At the first PHC, the ALJ asked parties to file initial comments on the utilities' applications with the understanding that the utilities would be required to update the applications for compliance issues, to take into account the developing California Long-Term Energy Efficiency Strategic Plan (Strategic Plan), and other matters. Parties filed initial comments on August 28, 2008 and the utilities replied to these comments on September 8, 2008. The Peer Review Group (PRG) also filed its comments on September 8, 2008.

A September 29, 2008 ALJ Ruling noted that Energy Division had identified a number of areas where the applications failed to comply with previous Commission decisions and Rulings and additional information needed to fully review the applications. These areas of non-compliance included the utilities' failure to use the most up to date Database for Energy Efficient Resources (DEER) values as directed in D.07-10-032.11 The Ruling indicated the ALJ's expectation that the updated applications would provide consistency in statewide programs.

A second PHC was held October 8, 2008. As anticipated at that PHC, a Ruling was issued on October 30, 2008 which required the utilities to re-file their applications. The Ruling stated that the utility portfolios as filed did not comply with Commission direction, and did not fully reflect the "significant shift" sought by this Commission or the near term activities identified in the Strategic Plan. To this end, the Ruling required the utilities to make a number of modifications to produce applications that would comply with applicable Decisions and Rulings on technical, programmatic and policy issues, provide sufficient information to assess the merits of the individual programs and portfolios as a whole, and adequately and accurately reflect policy direction from the Commission.

Specifically, the Ruling directed the utilities to provide sufficient levels of information to assess the utility's plans to implement the Commission-adopted Big, Bold Energy Initiatives from D.07-10-032, and to provide sector-specific plans to develop coordinated and effective programs that lead to market transformation. To this end the Ruling directed the utilities to work together to reorganize their program offerings into about ten coordinated sectoral programs that would be consistent statewide with perhaps another 10-20 programs specific to each utility, plus the third-party programs required under a minimum 20% competitive procurement requirement intended to achieve innovative program delivery approaches.

The Ruling also reiterated the adopted Commission requirement that the utilities use 2008 DEER values for their 2009-2011 energy efficiency portfolio applications. The Ruling specified use by the utilities of the 2008 DEER values as the basis for a fully-developed base case scenario in the re-filing of their 2009-2011 energy efficiency portfolio plans, and the use of the 2008 DEER values as the basis for any additional scenarios that incorporated "utility preferred" policy proposals (with indicated exceptions). The utilities were directed to thoroughly review their administrative costs and explore every opportunity to reduce the level of administrative costs. Finally, the Ruling addressed coordination with demand-side management programs.

In their July 2008 filings, the utilities each set forth proposals for bridge funding in order to continue certain energy efficiency programs into 2009, in the event that the Commission did not finalize a decision on 2009-2011 program applications before the end of 2008. At the August 11, 2008 PHC, the ALJ indicated that the Commission's final 2009-2011 decision would not be made before the end of 2008 due to a late start to the process,12 the need to supplement the applications to conform to the then-developing Strategic Plan and to ensure that the applications complied with previous Commission direction in D.07-10-032 and subsequent Rulings in R.06-04-010. On August 18, 2008, the utilities jointly filed a "Request for funding and authorization to operate 2008 energy efficiency programs in 2009 pending a final decision on the applications for approval of 2009-2011 energy efficiency programs."

On October 16, 2008, the Commission adopted D.08-10-027 authorizing the utilities to expend funds to continue certain 2008 energy efficiency programs until the Commission adopted a final decision on the utilities' energy efficiency portfolio applications for 2009-2011. In addition, SCE was authorized to spend $27 million in pre-2006 unspent, uncommitted energy efficiency funds to prevent the closure of four energy efficiency programs that had almost exhausted their budgets and would have had to shut down before the end of 2008 without additional funding. Ordering Paragraph 5 of D.08-10-027 stated in part: "The bridge funding period shall end three months after the effective date of a final decision on 2009-2011 energy efficiency programs in this docket, or December 31, 2009, whichever comes first."

In D.07-10-032, the Commission required the utilities to create an energy efficiency Strategic Plan, with the assistance of Commission staff and consultants as necessary. D.07-10-032 also stated that the Strategic Plan should reflect a balance between long-range strategies to achieve all cost-effective energy efficiency, and specific actions to achieve near-term savings goals. The Strategic Plan was to identify, at least generally, the program areas and associated strategic implementation activities needed through 2020 to achieve our goal of implementing all cost-effective energy efficiency. The Strategic Plan was to identify specific activities and implementation milestones to carry out in the 2009-2011 program cycle.

On September 18, 2008, the Commission adopted the Strategic Plan in D.08-09-040. This decision was the culmination of an extensive collaborative process involving the utilities and over 500 individuals and organizations working together through intensive public workshops held from November 2007 to January 2008, with review and comment from February to August 2008. Two major themes emerged from the public input. One was the importance of laying out action strategies that extended beyond utility programs to include initiatives needed from business, the California Energy Commission (CEC), local governments and others. The second was the need for the Commission to take a public leadership position in championing this broad perspective both in a planning document and its subsequent implementation.

The Strategic Plan sets forth a roadmap for energy efficiency in California through 2020 and beyond, by articulating a long-term vision and goals for each economic sector and identifying specific near-term, mid-term and long-term strategies to achieve the goals.13 The decision adopting the Strategic Plan ordered the utilities to file amendments to their 2009-2011 applications to incorporate near-term elements of the adopted Strategic Plan for which utility roles had been identified (as further spelled out in the October 30, 2008 Ruling). The decision directed the utilities to assist staff and the Commission in our development of a statewide energy efficiency brand and an integrated Marketing, Education and Outreach strategy to support the goal to achieve all cost-effective energy efficiency.

On November 25, 2008, the Scoping Memo in this docket was issued by an Assigned Commissioner Ruling. That Ruling stated that the overall scope of this proceeding is to determine energy efficiency budgets and approve programs for 2009-2011 for PG&E, SCE, SoCalGas, and SDG&E, and to pursue Commission energy efficiency policy objectives. All topics and issues in the October 30, 2008 Ruling were ruled within the scope of this proceeding, as well as other specified issues.

The Scoping Memo noted that the utility portfolios are expected to be cost-effective, robust, coordinated and consistent with the Commission's energy efficiency policies. The Scoping Memo stated at 4: "Energy efficiency is the first priority in the loading order adopted in the Commission's Energy Action Plan. This proceeding will attempt to fashion the best combination of Utility core programs, third party programs, local government partnerships, and marketing, education and outreach to continue to showcase California at the leading edge of innovative and effective energy efficiency."

The Scoping Memo determined that some of the utilities' proposed policy changes were appropriate for consideration in this proceeding, and others would not be considered here. The Scoping Memo indicated the intent to propose a new Rulemaking to consider energy efficiency incentives issues and to consider a number of the Utilities' policy proposals in a broader context. Therefore, we deferred consideration of several policy issues related to performance evaluation under the Risk Reward Incentive Mechanism (RRIM) to the new rulemaking, and decided to take up within this proceeding consideration of policy rules which are most essential to the formulation of cost-effective portfolios consistent with the Strategic Plan. We subsequently opened R.09-01-019 as our new Rulemaking on RRIM issues, specifying that certain issues proposed by the utilities in this proceeding instead would be a subject of that proceeding.

However, R.09-01-019 was to consider these issues in the context of incentives, but not in the context of cost-effectiveness or design of portfolios. Because of the need to consider certain policy issues in both this proceeding and in R.09-01-019, the ALJ issued a Ruling on February 25, 2009 to allow consideration in this proceeding of certain of the so-called "policy issues" (also known as "counting rules") raised by the utilities in their initial applications for the purpose of determining the cost-effectiveness of the utilities' portfolios and attainment of energy savings goals.14

On May 24, 2009, the Commission issued D.09-05-037. This decision revised Commission policy and counting rules as follows:

· Cumulative savings will be counted for the years 2006-2011 for this program cycle. The Energy Division will study specific assumptions around efficiency measure savings "decay" in advance of the 2012-2015 applications.

· Natural gas therm goals were adjusted downward by 22% for SDG&E and 26% for PG&E to take into account updated information on interactive effects.

· The utilities' proposal to change attribution rules regarding savings credit for actions taken by customers supported by utility programs, but who may also be motivated by external factors, was denied. However, incentives and savings in communities taking the initiative with "reach" requirements for higher local building efficiency will be treated the same as in other communities, and will not be treated as "free riders".

· The utilities' proposal to allow the maximum effective useful lives of measures to increase to 30 years was denied. The Energy Division was directed to conduct a study on the issue of increasing the maximum expected useful lives of measures and report back to the assigned ALJ and Commissioner in the relevant docket no later than December 1, 2010.

· The utilities' proposal to allow Strategic Plan-related costs to be excluded from the risk/reward incentive mechanism was deferred to R. 09-01-019.

· The utilities' request to use the individual utility weighted cost of capital adjusted for taxes for the 2009-2011 energy efficiency portfolios was granted.

· The utilities' request to revise Section IV, Rule 2 of the Energy Efficiency Policy Manual, version 4, to allow mid-cycle funding augmentation to count towards the minimum performance standard was approved.

· The utilities' request to use gross saving in the performance earnings benchmark was deferred to R. 09-01-019.

In accordance with ALJ Rulings granting the utilities' requests for extension of the filing date, the utilities filed amended applications on March 2, 2009. Several amendments and supplements were filed in the next few weeks to correct missing or inaccurate information in the March 2 filing. A third PHC was held on March 16, 2009 to consider scheduling matters. Comments on the re-filed applications were received on April 17, 2009. Reply comments were received on May 5, 2009.

Following D.09-05-037, the utilities were required to file supplements to their re-filed applications to take into account the outcomes of the policy, gas goals, and accounting changes adopted in that Decision. These supplements were filed on July 2, 2009. Comments were filed on July 17, 2009 with reply comments on July 27, 2009.

A number of workshops were held on matters raised in the re-filed applications and by parties, including a transcribed workshop on energy savings goals held on May 17, 2009. Between May 26 and June 24, 2009 nine non-transcribed public workshops were held to allow more focused explanation and dialogue for an extensive list of issues and topics contained in the utilities' voluminous March 2 filings. Between 20 and 75 individuals attended each of these workshops. Per a May 29, 2009 Assigned Commissioner and ALJ Ruling, parties were given the opportunity to comment on these public workshop issues on June 29, 2009, with reply comments on July 10, 2009. This Ruling also requested comments on other issues intended to enhance the record in this proceeding.

Public Participation Hearings were held in Culver City (Los Angeles area) on June 1, 2009, in San Diego on June 2, 2009 and on July 28, 2009 in San Francisco. There were approximately 70 public speakers at these hearings. A recurring theme of public speakers was that utility outreach efforts did not adequately reach many residential and small business customers who would be eligible for ratepayer-funded programs. Many members of the public recommended that the Commission use locally-based and community-based organizations to reach such customers, including use of local and ethnic media, as well as locally-based contractors. Several speakers also recommended that the utilities not be allowed to use energy efficiency funds to hinder formation of community choice aggregators.

We commend our staff for their exemplary work and enormous contribution to the development and implementation of the largest and most advanced energy efficiency programs in the country, and perhaps the world. Our Energy Division has done a heroic job of analyzing thousands of pages of utility filings, party comments, consultants reports, and EM&V results; providing feedback to the utilities; preparing white papers and straw proposals, conducting workshops and working groups; providing support for the previous energy efficiency decisions; monitoring consultants work; and at the same time monitoring the existing utility programs and performing EM&V activities.

3. Overview of Utility Proposals

In their March 2, 2009 applications, the utilities requested, in total, more than $3.7 billion for over 200 energy efficiency programs for 2009 through 2011.15 In their July 2, 2009 supplements to their applications, the overall requests totaled about $3.9 billion. Table 1 summarizes the July 2, 2009 requests of each utility.

Comments on the March 2, 2009 and/or the July 2, 2009 utility filings, or on Rulings requesting comments, were filed by the Division of Ratepayer Advocates (DRA), The Utility Reform Network (TURN), the Natural Resources Defense Council (NRDC), Women's Energy Matters (WEM), City and County of San Francisco (CCSF), Local Government Sustainable Energy Coalition (LGSEC), the National Association of Energy Service Companies (NAESCO), Community Environmental Council (CE Council), EnerNOC, Inc. (EnerNOC), Schweitzer and Associates (Schweitzer), California Building Industry Association/Consol (CBIA), Enalasys Corporation (Enalasys), California Center for Sustainable Energy (CCSE), California Building Performance Contractors Association (CBPCA), California Commissioning Collaborative (CCC), Navigant, and Ice Energy, Inc. (Ice Energy).

In D.07-10-032, the Commission identified several additional energy efficiency objectives beyond those articulated in previous decisions, such as adherence to the to-be-developed Strategic Plan, longer-term energy savings, and leveraging of other stakeholders' actions and resources. D.07-10-032 also listed a combined set of criteria that we intended to use in reviewing the utilities' 2009-2011 applications:16

1. Are the proposed portfolios cost-effective on a prospective basis taking reasonable account of uncertainty with respect to key cost-effectiveness input parameters?

2. Are the portfolios designed such that it will be feasible for the utilities to meet or exceed the Commission's energy savings goals? If each of the annual goals cannot be met in light of the accounting and ramping up transition issues described in D.04-09-060 and D.05-04-051, will the proposed portfolio plans meet or exceed the 2011 cumulative energy savings goal?

3. Are the portfolios and associated funding levels appropriately balanced between activities that address short-term and long-term savings?

4. Do the portfolio plans provide sufficient strategies and funding to address opportunities to reduce critical peak loads and improve system load factors?

5. Do the plans reasonably allocate funds among market sectors and applications with respect to the savings potential that has been identified in the potential studies?

6. Do the plans adequately describe strategies to minimize lost opportunities, per Rule 5?

7. Do the plans provide for adequate statewide coordination of similar program offerings?

8. Do the plans reflect a long-term Strategic Plan that exhibits well-integrated planning along the following four dimensions:

    a) Coordination across stages of technology and program developments, such as research and development, emerging technology promotion, public outreach, upstream distributor marketing, utility customer-focused programs, codes and standards advocacy, and other activities that can take advantage of statewide, regional, and national leverage?

    b) Leveraging the involvement and contributions from a variety of actors and financial resources, e.g. federal government, national manufacturers and distributors, national and regional building industry organizations and professionals, contractors, and educational institutions?

    c) Program designs and implementation strategies that explicitly seek to overcome identified market barriers to increased efficiency adoption? and

    d) Identifying an "end game" for each technology or practice that transforms building, purchasing, and use decisions to become either "standard practice" (sometimes referred to as "market transformation"), or incorporated into minimum codes and standards?

9. Are there reasonable proposals for any fund shifting and program flexibility rules that should be adopted for these program plans?

10. Are the overall funding levels proposed for the portfolio plans reasonable?

11. Is there evidence of program continuity across types of programs, or implementers, for those programs which have proven successful and cost-effective?

12. Are there appropriate strategies and program designs proposed for the three targeted programmatic initiatives?

D.08-09-040, in adopting the Strategic Plan, required that its strategies be incorporated into energy efficiency program planning and implementation starting in 2009. Each of these items was addressed in the utility filings. We will consider each of these objectives and criteria as we review the utility proposals and parties' comments. This decision approves the utility filings with specified exceptions. Therefore, to the extent that certain matters are not controversial, we consider the objectives and criteria met if not discussed herein.

4. Policy Guidance

In the approved energy efficiency portfolios, we and the utilities will begin to implement the Strategic Plan to the greatest extent possible. We discuss specific strategies and their relationship to energy efficiency programs in more detail below.

We approve a three year program cycle for the years 2010 through 2012. The original timeframe for this decision called for approving portfolios for the years 2009 through 2011. Due to factors including the adoption of the Strategic Plan and the need for significant revision to the original utility portfolio applications, we delayed the commencement of the program cycle and adopted the bridge funding decision (D.08-10-027) to ensure that viable programs would continue through 2009.

4.1.1. Position of Parties

DRA, CE Council and CCSF propose that this decision approve programs which will be in effect for two years instead of three - 2010 and 2011. SCE does not agree, as it claims this would create an artificial start date for the program cycle. In its July 2, 2009 supplement, SCE advocates for a 2010 to 2012 timeframe for this program cycle. PG&E advocates retaining the 2009-2011 cycle because it contends that otherwise there would be program delay between the date of this decision and a January 1, 2010 implementation date for the new program cycle. NRDC states that 2012 will likely require a modified approach due to upcoming state and federal policy changes, and that starting a new cycle in 2012 would maintain alignment with low-income energy efficiency and the demand response proceeding. LGSEC advocates using 2010-2011 as a transition period to better-designed programs to be implemented in 2012 and beyond.

4.1.2. Discussion

We have strived to coordinate the timing of our general energy efficiency efforts with our low-income energy efficiency programs and other demand side programs. However, we must also consider coordination of the timing of programs with the implementation of AB 3217 efforts in 2012.

The approved portfolios shall commence implementation on January 1, 2010. The nature of this proceeding is that there will need to be an implementation and transition period between the date of this decision and the start of the new cycle. Utilities will need to adjust staffing, sign contracts and make changes to existing programs, all of which take some time. Given that the bridge funding period can last through the end of 2009, it is reasonable that the new cycle should start on January 1, 2010.

A full three year program cycle is reasonable and appropriate. In recent years we have approved a three-year funding cycle for energy efficiency programs. One reason is that new programs often require a significant amount of time to start-up and become known and effective, and existing programs need to remain in the marketplace in a stable form to gain acceptable and wide use. Our analysis of the 2006 through 2008 portfolios shows that savings exhibit a "hockey stick" effect, where savings levels are lower in the first two years and higher in the third as the programs achieve full impact. Further, it is useful to have several years of information to evaluate both new programs and changes to existing programs before considering a new cycle. Finally, as this proceeding has shown, the process for approving the utility portfolios requires extensive preparation time, analysis by utilities and our staff, and party involvement; if we retain the 2011 end-point for the portfolios, the utilities would have to start immediately on their proposal for the next cycle. Therefore, in order to provide sufficient time for utility energy efficiency programs to operate in a stable manner in the marketplace and to provide appropriate review, the portfolios approved today will be in effect for 2010 through 2012.

The energy savings goals to be met by the current round of utility energy efficiency portfolios were originally established in D.04-09-060. In that decision, the Commission adopted savings targets for each of the utilities for the years 2004 through 2013 that reflect the expectation that energy efficiency efforts in their combined service territories should be able to capture 70% of the economic potential and 90% of the maximum achievable potential for electric energy savings over the 10-year period.

Savings goals were defined as cumulative in D.04-09-060, and reaffirmed in D.07-10-032, and again in D.09-05-037. In effect, this policy holds utilities accountable to make-up shortfalls between achievements and goals over prior program cycles, and to ensure that savings claimed in past program cycles persist over time. The Commission has adopted this policy both to encourage investments in lasting savings opportunities, and to ensure that ratepayer investments in efficiency truly reduce demand over time and can be counted on reliably for the purpose of procurement planning and greenhouse gas mitigation efforts.

The long-term goals established in D.04-09-060 were to be updated as necessary to ensure they remain aggressive yet attainable, in light of the savings opportunities available for pursuit by our utilities. We have made steady efforts to keep our goals relevant in light of our continually evolving understanding of the energy savings impacts of particular measures, market changes, and overall potential achievable by utility programs.

In D.08-07-047, we recognized the increasing role that aggressive state building standards, federal appliance standards, and other market forces would play in capturing identified potential in years ahead, and adjusted our characterization of utility-specific goals accordingly. D.08-07-047 also noted, on the basis of the Itron Goals Update Study, that the goals adopted in 2004 for the 2009-2011 program cycle were a closer reflection of gross potential available to the utilities in the program cycle, than they were of net potential.18 In following, the decision re-defined the adopted goals for 2009-2011 as gross goals. This means that in reporting savings achieved over the program cycle, for the purposes of goal attainment, utilities may report gross, as opposed to net, savings.

In D.09-05-037, we acknowledged certain remaining inconsistencies between the savings assumptions underlying our goals and those applied in measuring utility accomplishments against our adopted goals. The Database for Energy Efficiency Resources (DEER), which holds the collective savings assumptions applied in planning and updated through evaluation, has been continually updated as required by the Commission to ensure the most accurate estimates of actual load impacts resulting from ratepayer investments in energy efficiency. While, D.09-05-037 addressed the most consequential of these discrepancies, by adjusting the therm components of PG&E and SDG&E's goals to account for interactive effects measured when evaluating utility performance against the adopted goals, the decision also acknowledged that there "may also be a need in this proceeding to further consider changes to our existing goals to better match the most recent savings parameters of the DEER."

On May 18, 2009, a transcribed workshop was held on energy savings goals where Energy Division presented analysis to reconcile adopted goals with current DEER values.19 One of the key studies used to establish the goals was the Secret Surplus potential study conducted in 2002. Since this study was conducted in 2002, more recent evaluation information was embedded in the DEER 2008 updates and is not reflected in that study. Therefore staff did an analysis to see how the results of that study would differ if the DEER 2008 updates were applied to the underlying data.

Staff's analysis found that a cumulative goals decrement of 20% and 15% to KWh and KW respectively would be necessary in order to correct all program years between 2004 and 2012 for the discrepancy between existing goals assumptions and 2008 DEER. The analysis found that a goals decrement of 5% and 1% respectively would be necessary in order to correct the annual goals adopted for 2009, 2010, and 2011.20

An ALJ Ruling dated June 9, 2009 sought party input regarding the staff analysis and the need to further modify utility goals. Party comments on goals issues were received both in response to the June 9 Ruling and in April 17, 2009 comments on the re-filed joint applications.

PG&E, SDG&E, SoCalGas, TURN, and DRA all support the Energy Division's recommendation that program cycle goals should be adjusted to comport with current DEER values. SDG&E and SoCalGas suggest that this is an essential step in order to ensure consistency between load impact reporting and goals.21 Similarly, PG&E had previously suggested that utility goals originally adopted in 2004 should "float" with DEER changes in order to align with the potential originally used to set the goals.22 In response to the June 9th ALJ Ruling, PG&E supports staff's analysis at the May 18th Workshop.23 PG&E notes, however, that further changes to DEER after this correction would again misalign the goals and potential and requests that Energy Division develop a process to ensure that going forward energy savings goals are adjusted as DEER assumption are updated. PG&E notes further that the proposed adjustment does not address all outstanding goals issues and that the treatment of measure life savings drop-off or decay must be addressed to align goals with potential.

TURN and DRA suggest that adjusting goals to comport with current DEER values should allow the IOUs to scale back programs that have achieved market transformation and to target areas that would receive greater benefit from ratepayer-funded programs. However, TURN and DRA suggest that this step would only produce meaningful results if proposed ratepayer funding for basic CFLs is reduced and the utilities' 2009-2011 portfolio budgets are limited to approximately their 2006-2008 spending levels. TURN and DRA suggest further that in taking this step we should not lose sight of the ambitious targets the state will need to meet in achieving its greenhouse gas (GHG) reduction objectives.24

SCE, NRDC, and WEM do not support the proposal by staff to reduce goals for the current program cycle. SCE instead argues that energy efficiency savings assumptions should be revised to reflect SCE's proposed revisions to the DEER update issued by the Energy Division in December 2008. SCE states that the updated 2008 DEER values proposed by the Energy Division significantly reduce the amount of energy efficiency savings available from utility programs.

NRDC interprets Energy Division's goals analysis to mean that the goals are aggressive, but feasible. They note that according to Energy Division's analysis both SCE and PG&E would be able to achieve the current goals based on the analysis presented at the time of the May 18, 2009 goals workshop. While they acknowledge that current goals were established under a different set of assumptions, NRDC also raises that Energy Division's analysis does not take into account additional potential due to new technological developments since the 2002 study.25

WEM opposes any further changes to the 2009-2011 utility goals on the basis that additional energy efficiency potential exists now that was not identified in the 2004 goals study. WEM urges further that the Commission should challenge utilities to "stretch" their energy efficiency achievements in light of the severity of the global warming challenge. WEM suggests that if the utilities cannot or will not work to meet adopted goals, the Commission should consider alternative administrators.26

In addition to the utility-wide DEER adjustment, SDG&E proposes to adjust its 2009-2013 annual electricity savings goal stream (KWh and KW goals) to correct for a long-standing anomaly. In D.07-10-032 we determined that D.04-09-060 adopted energy savings goals for SDG&E that are set at 118 percent of maximum achievable potential, substantially higher than those adopted for SCE and PG&E. In D.07-10-032, we committed to revisit SDG&E's energy savings goals, or to address the matter in the budget process. In either forum we said that SDG&E will have the burden to provide a proposal that is technically sound and does not compromise our objectives to promote an aggressive energy efficiency strategy its territory. In D.08-07-047 at 32, in our decision updating goals through 2020, we stated that we would consider this issue in this proceeding. SDG&E proposes adjusting the current goals using the ratio of maximum achievable potential of the other utilities (88%) to SDG&E's current ratio (118%). This results in a 25% adjustment, which SDG&E claims is justified as the ten-year cumulative stream of goals would still achieve over 100% of maximum achievable potential. SDG&E contends that it will face unreasonable and unfair risk of not meeting its goals without these proposed adjustments. No party contested SDG&E's proposal.

Analytic consistency is an essential starting point in setting aggressive yet realistic goals for our utilities. We acknowledge that energy efficiency goals were established in 2004 using a set of assumptions developed years prior, while current program accomplishments are being measured using an updated set of assumptions, which benefit from more current evaluation work.

Therefore, we agree with Energy Division's analysis and the view held by various parties that the Commission should take steps to align current portfolio goals with DEER 2008. This is consistent with our commitment in D.04-06-090 to keep goals updated and reflective of potential available to the utilities.

We agree with both NRDC and WEM that it is appropriate that the Commission set and enforce "stretch" goals for energy efficiency savings, and take care not to over-adjust for the differences we have identified. We also take note of the fact that there may well be additional technologies, measures, and savings potential available to the utilities but not reflected in the potential study informing current goals. Our willingness to reexamine goals is not intended to reduce in any regard the rigor by which the utilities pursue energy efficiency, but rather to adjust forward-looking goals on the basis of updates to measure savings parameters. We note further that the determination in D.08-07-047 to allow utilities to count gross savings was also intended to realign goals with potential and largely achieves this end for the annual goals in this program cycle.27

We reject SCE's request to use the utility's preferred values in updating DEER and goals. The Commission already ruled on this matter in D.09-05-037, when SCE raised it last. We also reject SCE's claim that the DEER 2008 updates reduce the amount of efficiency savings available to utility programs. The updates to DEER resulting from Energy Division's independent analysis do not in any way diminish the utilities ability to deliver savings. Rather they ensure that reported savings are more closely aligned with actual load impacts, as informed by our best EM&V data. We believe it is of the utmost importance that reported achievements reflect honest representations of load impacts, and to the extent that a discrepancy exists, it is far preferable to align goals with reality than to resist adjustments based on updated data.

Examining the results of the Energy Division analysis we find that the appropriate adjustment to make is to adjust the annual savings targets adopted for the program cycle by the remaining differential after these targets are defined as gross goals. In comments on the proposed decision, the utilities argued that our DEER adjustments should extend backwards to the annual goals set prior to the last program cycle. This would imply a significant shift in policy, and in effect relieve utilities of the responsibility to make up for shortfalls between goals and achievements over past cycles.

For this reason, we do not find it appropriate to extend the correction retroactively and reconsider the goals set over past program cycles. We therefore modify the utilities' energy savings goals to reduce the utilities joint annual 2009-2011 KWh goal by 5% and the KW goal by 1%, and incorporate these changes into the calculated cumulative goals for each year.

We also adopt SDG&E's proposed goal changes. These changes imply a 25% adjustment to SDG&E's cumulative goals beginning in 2006. SDG&E's proposal is reasonable because it corrects a long-standing anomaly in goals without unduly lowering the bar for utility savings achievements.

We decline to further reduce therm goals. In D.09-05-037 we referred the matter to this decision for further consideration. With the 20% therm reductions already in place from D.09-05-037, the utilities have a reasonable opportunity to meet their therm goals. Therefore, no further reduction to therm goals is necessary or appropriate.

We acknowledge PG&E's concern that the treatment of measure life savings drop-off in relation to cumulative goals remains an outstanding issue for goals accounting. Whether utilities should assume that all, some, or none of the savings achieved in past cycles persist beyond the end of a program measure's useful life (i.e. whether the measure is replaced at equal efficiency, or reverts to the inefficient baseline technology) has not yet been made clear in Commission policy.

We clarify here that, until EM&V results inform better metrics, utilities may apply a conservative deemed assumption that 50% of savings persist following the expiration of a given measure's life. This reflects our expectation that our energy efficiency program efforts are in fact resulting in market transformation, changing consumption habits and preferences, while acknowledging that measure uptake in the absence of program support may not be universal.

Given the exclusion of 2004-2005 from cumulative savings calculations in D.09-05-037, measure life drop off is expected to have a relatively minor effect on utility goal achievement for the current cycle, hence the appropriateness of a deemed assumption. However, we understand that the scope of this issue will grow over time as cumulative savings obligations increase and a larger swath of measure lives expire. Therefore, this is an important analytical issue critical to our understanding of savings persistence over time, and demands greater attention by in our EM&V work. D.09-05-037 directed Energy Division to study specific assumptions around efficiency measure savings "decay" in advance of the 2012-2014 (now 2013-2015) portfolio applications. We intend to take this up for further examination in R.06-04-010, or its successor rulemaking.

Because we are modifying the timeframe of this program cycle to be 2010-2012, we clarify the utilities annual goals for 2012. D.08-07-047 adopted on an interim basis goals for 2012 through 2020 and required that final goals be adopted in advance of program cycle implementation. D.08-07-047 also adopted a new "Total Market Gross" framework for utility goals for 2012 through 2020. As that framework was intended to take effect in the program cycle following the one under consideration here, we utilize the 2012 goal set in D.04-09-060, and incorporate it into the current cycle by applying consistent modifications: redefine the D.04-09-060 adopted goal as gross per D.08-07-047, incorporate the therm adjustments ordered in D.09-05-037, and finally the DEER adjustments ordered in this decision.

PG&E, SCE, and SDG&E all commented on goals and in particular on cumulative goals as presented in the Proposed Decision. PG&E requests that cumulative goals for the 2010-2012 period be eliminated, stating that the Commission does not yet have reliable data on the derivation of cumulative savings, which leaves these goals uncertain. Absent that, PG&E requests application of a 20%/15% (GWh/MW) decrement to 2010-2012 annual goals to make the 2006-2012 period consistent with DEER 2008 values, again citing uncertainty as a rationale.

SCE similarly requests that a 20%/15% (GWh/MW) decrement to 2010-2012 goals stating that a misinterpretation occurred in application of Energy Division information. SDG&E requests that our proposed 5%/1% (GWh/MW) decrement for 2010-2012 annual goals be applied to 2006-2008 goals as well.

There are several reasons why we decline to make these requested changes. First, as stated clearly in D.07-10-032 and reiterated in D. 09-05-037, it is imperative that our investments in energy efficiency over time result in sustained demand reductions. Without a commitment that cumulative goals will be tracked and met, we cannot make the necessary assurances that fundamental benefits of energy efficiency are in fact being realized. We upheld this principle in D. 09-05-037, while moving the start date from cumulative goal tracking to 2006, due to data concerns with the 2004-2005 period. Eliminating cumulative goals for 2010-2012 (i.e., ignoring utility performance for 2006-2008) as requested by PG&E would violate this important principle. It would also harm our efforts and our responsibility to provide reliable data on energy savings for use in load forecasting and procurement planning purposes.

Second, we decline herein to retroactively adjust savings goals, except in the case of SDG&E where a significant historical anomaly on goals has been noted for some time. Goals are set using the best available data at that time and then, as we affirm elsewhere in this decision today, held constant on a going forward basis once the program period starts. We will however, make greater efforts in the future to update goals with the most recent potential study data on a program-cycle basis. With this principle in mind, we decline to either retroactively apply the 5%/1% (GWh/MW) decrement to the 2006-2008 period, or to adopt the 20%/15% (GWh/MW) decrement for the 2010-2012 period. Both would effectively reduce 2006-2008 adopted goals. As noted by TURN, a number of cumulative reductions have occurred since D.04-09-060 was issued, including the exclusion of 2004-2005 from cumulative savings calculations, the redefinition of adopted goals as gross, and the respective alignments with DEER executed in D.09-05-037 and herein.

The total combined effect of the modifications made since D.04-09-060 amounts to a 43% reduction to the GWh, a 42% reduction in MW goals, and a 41% reduction in natural gas therm goals. We are highly concerned that if the utilities cannot achieve the goals as adjusted to date, there are greater challenges ahead in meeting our state's ambitious climate goals under the current framework for delivery of energy efficiency programs.28

Third, we feel confident that we have approved herein an ample budget for utility achievement of annual and imputed cumulative goals. Overall utility energy efficiency budgets for 2010-2012 will increase 42% from the 2006-2008 period, with only a 10% increase in annual energy savings goals. We also believe that we have approved herein more effective programs as compared to the 2006-2008 period-programs that being guided by the Strategic Plan are poised to and should achieve greater savings in the 2010-2012 period as compared to earlier cycles. The expanded stakeholder involvement we now witness in the development of these programs is likely to support the rapid uptake, collaboration with, implementation and impact of these new programs.

We are also poised in the 2010-2012 period to launch a revised or new ME&O brand that should significantly increase customer energy efficiency actions and participation in utility programs. We have observed in utility applications, and approved for new utility programs, management structures to track and modify programs to improve their effectiveness, such as the continuous improvement/feedback structures in the commercial sector, the increased attention to process evaluations that we foresee by both utilities and Energy Division, and tracking of program effectiveness via performance metrics. Building benchmarking requirements should also assist utilities in more effectively targeting high energy using buildings and deploying program incentives strategically. We have also restored basic CFL program funding to the requested amounts for SCE and SDG&E. Additional innovations will be in place during the program period and will tend, we believe, to increase energy savings achievements for utilities, such as the uptake of new financing mechanisms by local governments (AB 811), the support of "reach" building codes, and the insertion of new measures identified by the Emerging Technologies Program in utility core programs.

We expect the utilities to make every effort to streamline and yet improve the delivery of energy efficiency programs to achieve the aggressive yet appropriate cumulative goals determined in this decision. Energy efficiency's place as "first in the loading order" and its importance as recognized in the California Air Resources Board Scoping Plan require nothing less. Therefore, we do not intend to alter goals further in the current program cycle.

We agree with SCE's and PG&E's comments that measure ex ante values established for use in planning and reporting accomplishments for 2010-2012 should be frozen. However, we do not agree with PG&E or SCE that those ex ante measure values should be frozen using the values found in the E3 calculators submitted with their July 2, 2009 applications. We agree with TURN's comment that frozen values must be based upon the best available information at the time the 2010-2012 activity is starting and that delaying the date of that freeze until early 2010 is a reasonable approach to better ensure that the maximum amount of updates is captured before the freeze takes effect.

The utilities' portfolio measure mix contains both DEER measures and non-DEER measures. As discussed in this decision (e.g., Sections 4.2 and 4.5), the Utilities have not always properly utilized current DEER measure values and assumptions in their submitted cost-effectiveness calculations. We note that the Utilities have commented that the documentation on the use of DEER is insufficient and that the Commission should be more specific about the version of DEER to be utilized. We clarify that the DEER 2008 values referred to by this decision are the complete set of data denoted as 2008 DEER version 2008.2.05, dated December 16, 2008, as currently posted at the DEER website ( http://www.deeresources.com) maintained by Energy Division.

Energy Division must provide the utilities with further detail and clarifications on the proper application of DEER so that the utilities are able to correct these problems. Additionally, as of this decision, Energy Division has not performed a review and approval of non-DEER measure ex ante estimates provided by the utilities. Energy Division must complete that review in a timely manner before those measure assumptions are frozen. It is therefore essential that the utilities work with Energy Division in its review and approval of their non-DEER measures ex ante values so that this activity can be completed as soon as possible. However, Energy Division must implement a review and approval process that balances the need for measure review with the utilities need to rapidly implement the portfolios approved by this Decision. We also recognize that the Energy Division or utilities may identify new measures appropriate for inclusion in the 2010-2012 portfolios that are not yet included in current DEER measure datasets. We also recognize that errors may be identified in frozen measure ex ante values. Energy Division, in consultation with the utilities, should develop a process by which new measures values can be added to the frozen measure datasets and mutually agreed errors in the frozen values can be corrected.

Therefore, in measuring portfolio performance against goals over the program cycle, we will freeze both DEER and non-DEER ex ante measure values as the 2010-2012 portfolio implementation begins. We concur with NRDC's comments that the use of these frozen ex ante values is only for this portfolio planning proceeding and implementation management. These frozen ex ante values may or may not be used for purposes of the incentive mechanism that is subject of another proceeding. Furthermore, the decision here to hold constant measure ex ante values for the purpose of measuring performance against goals, does not imply that we will cease from updating DEER and non-DEER measures for other purposes, and in particular for striving for the best estimates of actual load impacts resulting from the program cycle. Our EM&V activity will continue to develop ex post verified measure, program and portfolio impacts to inform future energy efficiency and procurement planning activities. The frequency and scope of DEER updates going forward is discussed further in the EM&V section below. As for non-DEER ex ante measure review and approval, we direct Energy Division to develop that review and approval process within 30 days from the date of this decision, to be issued in an ALJ ruling.

We find that these actions support the design of a robust, aggressive utility program portfolio. The energy savings goals remain stretch goals which will neither be too easy nor too difficult for the utilities to meet. In addition, with more appropriately aligned goals, we gain the freedom to consider adjustments to the utility portfolios which are responsive to evaluation results without concern that we would be imposing a burden on the utilities with regard to reaching energy savings goals.

Table 2 shows the adopted goals, starting from the goals adopted in D.04-09-060 and incorporating in the changes from D.09-05-037 and this decision. Per D.08-07-047 utilities may count gross savings towards these targets.

Table 2-Adopted Goals for the 2010-2012 Program Cycle29

 

2004

2005

2006

2007

2008

2009

2010

2011

2012

2013**

PG&E

                  

 

Total Annual Electricity Savings (GWH/yr)

744

744

829

944

1,053

1,014

964

1,032

1,114

1,277

Total Cumulative Savings

744

1,487

830

1,773

2,826

3,840

4,804

5,836

6,950

8,227

Total Annual Peak Savings (MW)

161

162

180

205

228

230

218

234

251

236

Total Cumulative Peak Savings (MW)

161

323

180

385

613

843

1,060

1,294

1,546

1,824

Total Annual Natural Gas Savings (MMTh/yr)

9.8

9.8

12.6

14.9

17.4

15.1

15.6

16.2

17.1

25.1

Total Cumulative Natural Gas Savings

9.8

19.6

12.5

27.4

44.8

59.9

75.5

91.7

108.8

133.9

 

 

 

              

 

SCE

 

 

              

 

Total Annual Electricity Savings (GWH/yr)

826

826

922

1,046

1,167

1,130

1,117

1,106

1,093

1,139

Total Cumulative Savings

826

1,653

922

1,968

3,135

4,265

5,382

6,488

7,581

8,720

Total Annual Peak Savings (MW)

167

167

207

219

246

247

245

243

239

240

Total Cumulative Peak Savings (MW)

167

334

207

426

672

919

1,163

1,406

1,644

1,884

 

 

 

              

 

SDG&E*

 

 

              

 

Total Annual Electricity Savings (GWH/yr)

268

268

210

214

213

201

195

187

158

214

Total Cumulative Savings

268

536

210

424

638

839

1,034

1,221

1,379

1,803

Total Annual Peak Savings (MW)

50.4

50.3

41

41

41

40

39

37

31

41

Total Cumulative Peak Savings (MW)

50

101

41

82

122

162

201

238

269

350

Total Annual Natural Gas Savings (MMTh/yr)

1.8

1.8

2.7

3.1

3.7

3.3

3.5

3.8

4.1

5.7

Total Cumulative Natural Gas Savings

1.8

3.6

2.7

5.9

9.5

12.8

16.3

20.1

24.2

29.8

 

 

 

              

 

SoCalGas

 

 

              

 

Total Annual Natural Gas Savings (MMTh/yr)

9.6

9.6

15

19

23

27

28

30

32

36

Total Cumulative Natural Gas Savings

9.6

19.2

15

34

57

84

113

143

175

211

 

 

 

              

 

Total IOU

 

 

              

 

Total Annual Electricity Savings (GWH/yr)

1,838

1,838

1,961

2,204

2,433

2,344

2,276

2,324

2,365

2,630

Total Cumulative Savings

1,838

3,676

1,961

4,165

6,599

8,944

11,220

13,545

15,910

18,750

Total Annual Peak Savings (MW)

378

379

428

465

515

517

502

514

521

517

Total Cumulative Peak Savings (MW)

378

758

428

893

1,407

1,924

2,424

2,938

3,459

4,058

Total Annual Natural Gas Savings (MMTh/yr)

21.2

21.2

30.3

37.0

44.1

45.4

47.1

50.0

53.2

66.8

Total Cumulative Natural Gas Savings

21.2

42.4

30.2

67.3

111.3

156.7

204.8

254.8

308.1

374.8

We establish criteria and requirements for the development and approval of pilot programs.

The utilities have proposed a number of pilot programs in their portfolios. PG&E proposes a $30 million Zero Net Energy (ZNE) pilot and a $17 million Innovator Pilot program for local governments. SCE proposes a $17 million continuing Palm Desert Pilot, plus a $9 million Sustainable Portfolios program and a $10 million Sustainable Communities program (both of which we consider to be pilot programs). SDG&E and SoCalGas propose Sustainable Communities pilot programs, at approximately $1 million each. In addition, the utilities propose a number of pilot programs within Workforce Education and Training (WE&T). As discussed in Section 6.1, we add $32 million for SCE Local Government Strategic Plan Pilot projects.

Pilot programs play an important role in California's energy efficiency programs by allowing the testing of innovative program designs and partnerships that may then enable the utilities to achieve deeper savings and market transformation. Such testing is especially important since much of the "low hanging fruit" in energy efficiency has already been achieved in California and additional, cost-effective savings have become harder to reach. Just as the Emerging Technologies programs are designed to create the energy savings technologies of the future, the pilot programs should be designed to create the measures and program delivery mechanisms of the future.

Some of the proposed pilot programs lack critical elements such as a clear statement of the goal of the pilot, the problem or question the pilot is designed to resolve, clear metrics to determine whether the pilot is a success, the likelihood that the program will lead to cost-effective savings, or clear budgets or timelines. While we encourage the utilities to pursue innovative concepts through pilots, we intend to scrutinize pilot programs to ensure they achieve their objectives before allowing these programs to become more permanent.

In D.07-09-050, our decision approving water/energy pilot projects, we set forth a number of objectives for the pilot programs, including:

1. Create a methodology for calculating cost-effectiveness and evaluating water-derived energy efficiency programs;

2. Test a diverse set of water energy programs and measures, with particular emphasis on new technologies and low-income customers;

3. Better understand what programs and measures are likely to save water and energy; and

4. Provide the basis for meaningful ex-post project assessment.

However, we have not set similar guidelines for our general energy efficiency pilots. In order to provide clearer guidance for the utilities and for our own review of utility pilot projects, we set forth criteria for development, monitoring and information sharing of pilot projects and align our treatment of pilot projects with our policies on Emerging Technologies.

4.3.1. Pilot Project Criteria

The purpose of a pilot project is to test a new and innovative concept, partnership, or program design that is intended to address a specific area of concern or gap in existing programs or to advance a Strategic Plan goal or strategy. The project logic and design should address the concern or gap and contain metrics to measure the success or failure of the pilot project. The pilots should be limited in scope and duration so that results are available in a specified time frame and limited in budget so that unsuccessful programs have a limited impact on the overall portfolio. All results of pilot projects must be shared widely with the other utilities and with the stakeholders in the sector impacted by the pilot. There should be a specific plan and timeframe to move all pilot programs into utility-wide and hopefully statewide use.

Each proposed pilot should contain the following elements:

1. A specific statement of the concern, gap, or problem that the pilot seeks to address and the likelihood that the issue can be addressed cost-effectively through utility programs;

2. Whether and how the pilot will address a Strategic Plan goal or strategy and market transformation;

3. Specific goals, objectives and end points for the project;

4. New and innovative design, partnerships, concepts or measure mixes that have not yet been tested or employed;

5. A clear budget and timeframe to complete the project and obtain results within a portfolio cycle - pilot projects should not be continuations of programs from previous portfolios;

6. Information on relevant baselines metrics or a plan to develop baseline information against which the project outcomes can be measured;

7. Program performance metrics (see Section 4.6.3);

8. Methodologies to test the cost-effectiveness of the project;

9. A proposed EM&V plan;

10. A concrete strategy to identify and disseminate best practices and lessons learned from the pilot to all California utilities and to transfer those practices to resource programs, as well as a schedule and plan to expand the pilot to utility and hopefully statewide usage.

Elsewhere in this decision, we direct the utilities to provide more specific information on proposed pilot projects which do not meet these guidelines. The utilities shall comply with these guidelines for these identified projects and for all future proposed pilot projects. Each utility shall respond to the directives in this decision regarding pilot projects in an Advice Letter for all of the pilot projects approved for funding or otherwise addressed in this decision within 120 days after the effective date of this decision, as directed in Ordering Paragraph 20 of this decision.

We impose a 10% cap on total administrative costs, defined as overhead (General and Administrative (G&A) Labor and Materials), labor (Management and Clerical), Human Resources (HR) Support and Development, Travel and Conference Fees (Administrative Costs).

Administrative costs are a necessary component of implementing energy efficiency programs. Utilities have a number of administrative duties including reporting to the Commission, internal management controls, and oversight of contractors which must be funded in order to carry out their required programs. Administrative costs,30 as we have defined them, include:

· Overhead (G&A Labor/Materials): administrative labor, accounting support, IT services and support, reporting databases, data request responses, CPUC financial audits, regulatory filings support and other ad-hoc support required across all programs.

· Labor (Managerial & Clerical): This category includes utility labor costs related to either management or clerical positions directly related to program administration. SDG&E and SCG also add payroll taxes.

· Travel and Conference fees: This includes labor, travel and fees for conferences.

These Administrative Costs categories do not include EM&V or Marketing and Outreach. Direct Implementation costs for delivering programs, which are defined as "costs associated with activities that are a direct interface with the customer or program participant or recipient (i.e., contractor receiving training)," are also excluded.31 Direct Implementation includes non-resource programs such as Emerging Technologies, WE&T, Lighting Market Transformation, Zero Net Energy Pilots, local & statewide DSM integration and On-Bill Financing. Also included are direct implementation non-incentive costs associated with incentive-based programs. These costs include engineering project management, customer support, certain sub-programs (e.g., Energy Audits and Continuous Energy Improvement), market transformation and long term strategic plan support.

Administrative costs are necessary to well-functioning programs, it is our duty to ensure that administrative costs are reasonable and limited to those overhead and labor costs that are truly required to implement quality programs, so that ratepayer funds are used to the greatest degree possible for the programs themselves.

4.4.1. Position of Parties

DRA advocates that the Commission ensure greater transparency over utility administrative costs, claiming that there is not sufficient data in the applications to understand these costs. DRA contends that the original utility applications filed in July 2008 showed overhead, general and administrative costs constituted between 42% (PG&E) and 57% (SDG&E) the total portfolio budgets, averaging 44%. In the March 2, 2009 filings, the utilities show administrative costs ranging between 9% (SoCalGas) and 16% (PG&E) of total budgets, with an average of 14% across all four utilities. However, DRA and TURN believe that the utilities, instead of reducing their administrative costs in the new applications, have relabeled much of their administrative costs as direct implementation costs, as evidenced by the significant increase in direct implementation costs between the July 2008 and March 2009 filings but relatively level total budget amounts. DRA asserts that the utilities did not provide sufficient explanation as to whether administrative costs actually were reduced or merely reallocated. DRA concludes that while administrative costs are essentially a black box, overall administrative costs did not dramatically decrease between the July 2008 and March 2009 applications.

TURN contends that the proposed utility administrative cost budgets have collectively increased from actual expenditures of $234 million in 2006-2008 to collective requests of $649 million for 2009-2011. This is a 177% increase for administrative costs, as compared to an 82% increase in total budgets. TURN claims that this increase indicates no returns to scale with respect to administration of programs. TURN also notes that, even if we were to accept that the utilities' total administrative costs were in the range of 13%, these costs are still higher than the average administrative costs for energy efficiency programs in Oregon, Massachusetts, New Jersey, Connecticut and Vermont. The average level of administrative costs for those states is approximately 8%.

WEM points out that, for PG&E, total administrative costs for utility core programs are 12.6%, but are 20.6% for third party programs and 20.2% for local government partnerships. PG&E did not respond to this point.

PG&E agrees that there should be improved clarity around the types of costs classified as administrative costs by the utilities. PG&E disputes that its administrative costs were 42% in the July 2008 application, but instead says they were approximately 15%, about the same as in the March 2009 re-filing. SCE claims that the apparently high administrative costs in its initial application were a result of mislabeling of costs inputted into the E3 calculator, and thus incorrectly include various costs into the administrative cost category. SDG&E and SoCalGas claim DRA misunderstood the level of administrative costs, resulting in a misrepresentation of program budget allocations. They also contend that the primary criterion for approving budgets is a cost-effective portfolio, implying that the level of administrative costs should not be a concern if the portfolios are cost-effective.

Several parties, including PG&E, SCE, DRA, LGSEC, and CCSF raised concerns about appropriately defining Strategic Planning program costs (PG&E, SCE) and/or possible utility reduction in funding for Strategic Planning programs and pilots below the budgeted amounts included in their applications (CCSF, LGSEC). Indeed, SCE and PG&E stated they would look to Strategic Plan programs first in their budget reduction efforts.

4.4.2. Discussion

Table 3 shows 2006-2008 reported expenditures and 2009-2011 proposed portfolio budgets highlighting administrative costs and direct implementation costs. This table is shown in two parts on the next page.

First, we do not agree with SDG&E and SoCalGas that administrative cost levels are irrelevant as long as the portfolio is cost-effective. Total costs matter as well. We are obligated to keep overall ratepayer costs at reasonable levels, allow the utility to recover only reasonable administrative costs, and ensure that the maximum amount of funds go directly to valuable programs. Indeed, if we allow utility administrative costs to go unchecked, then we leave open the possibility that savings that do not appear to be cost-effective would be cost-effective if the utilities' administrative costs were controlled. We would thus fail to carry out our legal obligations to ensure that rates are just and reasonable and that the utilities first obtain all cost-effective energy efficiency. Below, we address the need for greater transparency in the utility budgets and the level of total administrative costs.

        4.4.2.1. Budget Transparency

We agree that it is difficult to scrutinize the dollar amounts and percentage levels of administrative costs proposed by the utilities. Despite direction from the Assigned Commissioner to the utilities to report budgets consistently, fully and accurately, the utility costs are hard to pin down with any certainty, as they are spread among several chapters within the utility applications and even beyond them (e.g., allocation of certain general rate case costs attributable to energy efficiency) and categorized and reported differently by each utility. According to DRA, in responses to data requests for administrative costs all four utilities responded that some level of costs including payroll tax, benefits and pensions are funded through the utilities' general rate cases (GRCs) and possibly other cost categories. None of the utilities was able to identify the specific costs that might be recovered from other utility accounts in response to the DRA data request.

TURN and DRA correctly point out that the utilities' administrative costs lack transparency and it is difficult to determine accurately the total cost of the energy efficiency portfolios or whether the utilities' costs were properly classified as administrative costs or direct implementation costs.

Although we have provided guidance to the utilities on the costs to be included in each budget category, we agree with TURN and DRA that compliance is inconsistent. For example, Attachment 5-A of the December 2008 Ruling lists utility Payroll Tax and Pensions as included costs in the Human Resource Support and Development category; according to DRA the utilities have not included these costs in their budgets. Therefore, we adopt the DRA recommendation that we require the utilities to provide a detailed breakdown of all administrative costs required to support energy efficiency programs, including regulatory costs and other partial support functions, in their compliance filing in response to this decision. We also adopt the DRA and TURN recommendation to require a full audit of the utilities' administrative and other costs in order to understand the changes in characterization of costs in the revised applications and to ensure accountability of the amount, allocation and composition of the total administrative costs for this portfolio timeframe. We authorize Commission staff to hire contractors to conduct the audit using EM&V funding.

Our review finds that utilities have included program design, development, planning and program/project management costs in direct implementation non-incentive costs in their applications. While this is not consistent with all details of our previous guidance on this matter, we find the utility approach consistent with that taken in other localities and discussed below, as well as consistent with the increased costs of program design/project management work associated with implementing programs that produce long term lasting savings as called for in the Strategic Plan. PG&E noted that improved clarity around administrative costs would be helpful. We therefore clarify here that we accept utility categorization of program planning, design and project management costs as direct implementation non-incentive costs and direct our staff to issue a revised guideline describing the details of administrative costs versus direct implementation costs.

We also clarify here how Strategic Planning program costs should be allocated: (1) administrative and logistical costs related to workshops on Strategic Planning issues may be considered "administrative costs;" (2) program planning/design/project management and information gathering costs related to specific Strategic Plan related non-resource and resource programs may be considered "direct implementation non-incentive costs;" (3) market, cost assessment and other studies as called for or suggested by the Strategic Plan should be considered part of EM&V planning and policy costs. We further prohibit the utilities, as discussed below, from unduly reducing Strategic Planning non-administrative costs as compared to the budget reduction targets we call for with resource program direct implementation non-incentive costs below. This issue is discussed further in Section 4.5.

        4.4.2.2. Total Administrative Costs

The utilities propose Total Administrative Costs (Line A.5 in Table 3)32 of 16.2% for PG&E, 14.2% for SDG&E, 9.2% for SoCalGas, and 14.3% for SCE. PG&E and SCE's administrative costs have increased as a percentage basis from 2006-2008, while SoCalGas' costs have decreased from 15.1% to 9.2%.33 As TURN suggests, it would be reasonable to expect that there would be economies of scale for administrative costs, as demonstrated by SoCalGas, for the larger budgets in the up-coming portfolio cycle as well as savings from continuation of existing programs.

One possible reason for increased costs appears to be that the utilities propose higher administrative costs for third-party programs than for their own programs, as WEM has shown for PG&E. This seems counterintuitive, as the third-parties perform some of the administrative tasks otherwise undertaken by utilities. This suggests either that there may be excessive burdens placed by utilities on third parties or that utilities are overestimating the costs in this area. PG&E's overall administrative costs would decrease from 16.25% to 12.6% if all programs had identical levels of administrative costs, and would be lower than 12.6% if non-utility core programs had lower administrative costs. Similar adjustments would occur for the other utilities.

In other proceedings we have limited the percentage of administrative costs. In the California Solar Initiative (CSI) decision, the Commission limited total administration, marketing, outreach, and measurement and evaluation costs to 10% of total budgets. In D.06-08-028, Ordering Paragraph 22, the Commission ordered program administrators to spend no more than 5% of their total budget for administration until the Commission addressed marketing, outreach, and measurement and evaluation in Phase II of that proceeding. There has not been a Phase II decision to date.

In the same proceeding, the Commission adopted a program administrative cap for two programs that are subsets of CSI -- the Single Family Affordable Solar Housing (SASH) Program and the Multifamily Affordable Solar Housing (MASH) program.  For the SASH Program, the Commission directed the Program Manager to adhere to the adopted budget allocations, wherein 85% of program dollars would go to incentives, 10% to administration, 4% to marketing and outreach, and 1% to evaluation (D.07-11-045 at 19). For the MASH program the administrative cap is 12% of total funds, which includes marketing and outreach and evaluation (D.08-10-036 at 20).34

In the Self-Generation Incentive Program (SGIP) decision (D.04-12-045) the Commission adopted a 10% administrative budget for each Program Administrator. These costs include, but are not limited to, measurement, verification, and evaluation activities, marketing, outreach, and regulatory reporting. This decision reduced the administrative budget adopted in D.01-03-073, which had allowed each Program Administrator to allocate up to 20% of the SGIP budget toward administrative costs.

In both CSI and SGIP programs, the Commission has limited administrative costs to between 5% and 10% of total costs including marketing, outreach, and measurement and evaluation costs, which are separate categories in the energy efficiency budgets. There are some differences between administration of energy efficiency programs and administration of CSI and SGIP programs, most notably that more CSI and SGIP programs are not directly implemented by utilities. However, the administrative cost caps for these programs are 50 - 75% less than the proposed administrative cost percentages for third party energy efficiency programs, even though the market and EM&V are not included in the energy efficiency administrative costs.

A 10% cost cap is on the upper end of the practices of other states that require utility or third party energy efficiency programs.35 These administrative costs, exclusive of marketing and EM&V, range from a high of 10% to a low of 2%. As some parties suggest in comments on the Proposed Decision, we will delete Vermont from the calculation; In Table 5, Vermont is shown as having 2% administrative costs, which may well not be calculated in a way that is similar to California. Nevertheless, the average of similar states is still under 10%.

SCE, in comments on the Proposed Decision, argues that the data provided by TURN is flawed, inaccurate and misleading. SCE claims that differing administrative structures of utilities in other states and differences in composition of cost categories renders this data unusable. While SCE may be correct that data from other states do not conform exactly to California's energy efficiency structure, using the average levels across several states (excluding the outlier of Vermont) is a meaningful metric to judge the appropriate of administrative cost levels in California. The data from other states also is consistent with the 10% administrative cost cap imposed in other programmatic areas in California, and, while not definitive in and of itself, supports the concept of this cap.

SCE and PG&E also argue that the Proposed Decision substantially increased the administrative and regulatory burden on the utilities. SCE claims that it is unreasonable to expect the utilities to achieve more aggressive goals with fewer resources, while also substantially increasing the regulatory requirements that must be complied with. We acknowledge that this decision increases certain regulatory requirements, consistent with moving toward achieving the comprehensive vision of the Strategic Plan. However, even with a decrease in the percentage of total budget allocated to administrative costs, the overall administrative cost budget for SCE will increase in this portfolio period, from $91 million in 2006-2008 to over $110 million in 2010-2012 due to the increased overall budget. PG&E's administrative cost budget stays about the same as the from $128 million in 2006 - 2008; however PG&E's 2010-2012 administrative costs budget is the highest for any utility for this period.

SDG&E/SoCalGas in their comments on the Proposed Decision that administrative costs would be increased for this next portfolio due to new responsibilities including new Advice Letters and task forces. The Proposed Decision has been modified to streamline or eliminate much of the proposed task force work. While this decision does add certain new responsibilities, the overall additional burden appears to be low compared to approximately $300 million in allowed administrative costs. Any new burden should be offset by economies of scale associated with 42% increases in overall portfolio budget (see Section 4.5) and the fact that the overall administrative cost increase by over 25%, from $238 million in 2006 -2006 (see Table 3 above) to around $300 million for 2010-2012.

A 10% administrative cost cap consistent with the cap for these costs proposed in AB 51 (Blakeslee). The staff analysis of that bill stated that the Commission "supports containing administrative costs for energy efficiency at reasonable levels to maximize the benefits of the programs to consumers." However, the analysis also noted that the Commission was in the process of reviewing administrative costs in the context of the overall budgets and proposed programs in this proceeding and supported the conclusion of that review before considering the appropriate level and method of cost control for administrative costs.

We have now reviewed the record in this proceeding and conclude that a cap is warranted. Throughout this decision, we are attempting to control costs to implement energy efficiency programs to get the most bang for the buck. We find that utility administrative costs can be reduced in order to take into account economies of scale and to bring administrative costs in line with other utility administrative costs for energy efficiency and other similar energy programs. Therefore, we will limit the utilities' administrative costs to 10% for utility programs on a portfolio basis and order the utilities to revise their budgets as set forth below.

The concept of an overall 10% administrative cap provides the utilities with flexibility to implement valuable programs which have different administrative costs. With an overall cap on utility program administrative costs, the utilities need not and should not reduce administrative costs to 10% for all individual utility programs, but they must ensure that overall utility program costs are within the cap.

Different levels of administrative costs must be assigned for different types of programs. However, we do not have a record to allocate these costs among programs within the overall cap. Thus, we require each utility to allocate administrative costs among utility programs in their portfolio compliance filing ( see Ordering Paragraph 15 in this decision), subject to the 10% overall cap.

An administrative cost cap of 10% on third party programs and local government programs is also an important component of containing total portfolio administrative costs. However, imposing a 10% administrative cost cap for each program within these categories would be excessively burdensome for utilities, third party contractors and government partners. Therefore, we direct the utilities to seek to achieve a 10% administrative cost target for third party and local government partnership direct costs (i.e., separate from utility costs to administer these programs). As combined total program categories, third party and local government program administrative costs should strive toward the 10% total administrative cost target. In addition, we agree with comments by LGSEC and CCSF on the Proposed Decision that utilities should not be permitted to unduly shift administrative cost cuts onto local government partnership and third party implementers. Therefore, we direct the utilities to not reduce the non-utility portions of local government partnership and third party implementer administrative costs, as compared to levels contained in the budgets proposed by the utilities in their July 2009 applications and approved herein, except where these costs as filed exceed the 10% cost target level.

Finally, administrative costs include the costs to respond to Commission reporting requirements and other regulatory activities. The Commission must do its part to minimize the regulatory burden on the utilities and have made every effort in this decision to require only necessary filings and reports. We request that the Energy Division review further all existing and new energy efficiency reporting requirements and report on possible ways to streamline these requirements.

The proposed utility budgets result in unacceptably low Total Resource Cost (TRC) ratios for the 2010-2012 portfolios, in the range (as adjusted) of 1.15 to 1.25. In order to mitigate the risk of non-cost effective portfolios, we performed specified budget reductions in order to approach an overall budget TRC ratio of 1.5. The adopted budgets provide TRC ratios that we estimate to be between 1.0 and 1.3 for each utility.

The approved budgets for the 2006-2008 energy efficiency programs, including EM&V, were approximately $2.2 billion total for the four utilities over three years, or about $730 million/year on average for all utilities. For 2009, our bridge funding decision, D.08-10-027, provided $65.3 million per month (plus $6.1 million/per month for EM&V), or $784 million ($857 million with EM&V), for all utilities if the bridge funding period lasted for all of 2009.36 In their March 2, 2009 filings, the utilities collectively requested approximately $3.7 - $4.2 billion over three years (depending on whether the Commission adopted requested changes on several policy issues) or $1.23 to $1.4 billion/year on average, an 80 - 90% increase from the last cycle. Following our policy issues decision, D.09-05-037, the utilities filed supplements to their March 2, 2009 filings to take into account that decision. In those filings, the total utility request is now about $3.9 billion, which would be a 77% increase from last cycle. Table 3 shows the actual budgets for 2006 through 2008, and the utilities' proposed 2009 through 2011 budgets.37

4.5.1. Positions of Parties

Each utility explains similarly that its proposed budget increase is due to several factors, including increased energy savings targets, reduced ability to count energy savings toward goals, retention of core, third-party and government partnership programs, enhanced focus on long-term savings measures such as HVAC retrofits, reduced support for less costly lighting measures, support for integrated activities and marketing efforts, support for Strategic Plan initiatives, increased difficulty of capturing savings, and higher EM&V budgets. The budgets for the utilities do not include at least two important cost areas. First, as TURN points out, a number of utility administrative costs related to energy efficiency (e.g., pensions and workers' compensation costs) are not included in the utility energy efficiency budgets, but instead are included in accounts that would be recoverable through general rate cases. PG&E agrees that these costs are not in the energy efficiency budgets, but contends that the existing practice of recovering allocated administrative and general expenses in the general rate case is appropriate and that there is no double-counting of energy efficiency administrative costs. SCE notes that its recent general rate case approved general expenses, including those attributable to energy efficiency. As TURN points out, this practice in effect increases cost-effectiveness calculations, as compared to considering both direct and indirect costs in the energy efficiency budgets. However, this has been our practice for some time. We see no reason in this decision to alter the practice of approving certain energy efficiency-related costs in general rate cases.

Second, potential utility incentive payments also are not included in the utility budgets. The level of incentive payments utilities may earn for energy efficiency activities is unknown at this time for two reasons. First and foremost, the overall risk/reward incentive mechanism is currently under review in R.09-01-019; we will not presume any particular outcome of that proceeding. Second, even if the current risk/reward incentive mechanism (as adopted in D.07-09-063 and modified in D.08-01-012) continues, there is no way of knowing what actual utility performance will be and whether rewards would be granted (or penalties assessed). Therefore, it is reasonable to not include potential utility incentive payments in the budgets.

All the utilities verified at the May 17, 2009 Goals workshop that these potential incentive payments are included in the energy efficiency cost effectiveness calculations for their March 2009 re-filed applications. However, in their July 2, 2009 supplements, the utilities did not include potential incentive payments in their TRC calculation. D.07-09-043 states "In D.94-10-059,38 we determined that shareholder incentives represent a true economic cost in the production of utility programs and should be included as a direct cost in the various Standard Practice Manual tests of cost-effectiveness, including the TRC test and the predecessor of the PAC test, the 'Utility Cost' test. [footnote omitted] There appears to be no disagreement that this policy rule is still relevant today." Therefore, the utilities are out of compliance with Commission policies on this point.

TURN contends that the utilities' proposed budget levels are unjustified. TURN notes that the proposed budgets are nearly double 2006-2008 levels, while net energy savings goals have increased only 10.3% over that time period and gross goals are actually lower in 2009-2011 than in 2006-2008. TURN argues there should be some economies of scale and scope with the utilities' budget totals. As discussed in section 5.2 below, TURN also claims the applications continue to be inappropriately CFL-focused portfolios and the CFL budgets should be eliminated. TURN also recommends lowering the utility budgets for new construction to a level consistent with current broad economic conditions, reflecting a significant reduction in new construction for 2009-2011.

DRA claims the large increases in proposed program budgets do not correspond to a proportional increase in energy savings. DRA contends the Utilities have failed to show that a doubling of the program budget will provide commensurate and significant value to ratepayers for their investment in energy efficiency programs. For example, DRA shows that PG&E proposes a 64% increase in its energy efficiency program budget over what it spent for the 2006-2008 program cycle, and yet it projects to achieve less energy savings in the new program cycle than it did in the previous one.

4.5.2. Discussion

We are required by Public Utilities Code Section 454.5(b)(9)(c) to approve energy efficiency expenditures that are cost-effective; that is, the overall ratepayer or societal benefits must exceed the overall costs. Our policy, as articulated in Rule IV.6 of the Energy Efficiency Policy Manual, is to evaluate the entire portfolio for cost-effectiveness, and not to require each individual program element to meet this test. For example, several elements of our Strategic Plan may not be cost-effective in the timeframe of this portfolio, but should be cost-effective over a longer period. We remain committed to finding all cost-effective energy efficiency opportunities over time.

As stated in the Rule II.1 of the Energy Efficiency Policy Manual, the Commission's overriding goal for energy efficiency efforts is to "pursue all cost-effective energy efficiency opportunities over both the short- and long-term." Therefore, the Policy Rules establish a threshold cost-effectiveness condition for the utilities' energy efficiency portfolios. Cost-effectiveness is measured using two different tests: 1) the Total Resource Cost (or "TRC") whereby the value of the energy savings is greater than the total cost of installed measures and all program costs; and 2) Program Administrator Cost (or "PAC") whereby the value of energy savings outweighs the cost of utility financial incentives to customers and all other program costs.39 These tests are expressed as ratios of costs and benefits; the higher the ratio, the higher the benefits to the ratepayers for each dollar spent. In order to be eligible for ratepayer funding, each utility portfolio and the entire statewide portfolio must pass both tests on a prospective basis, considering all costs of the programs. These include costs not assignable to individual programs, such as overhead, planning, and EM&V, but do not include Emerging Technology Program costs.

Achieving all cost-effective energy efficiency opportunities on a portfolio basis would, in theory, allow approval of any portfolio with a cost-effectiveness ratio over 1.0. However, theory runs into practicality when using actual numbers. As discussed below, there are measurement problems and imperfections in the utility-submitted cost-effectiveness calculations. There is insufficient record to correct for each imperfection, especially as these imperfections tend to reduce cost-effectiveness. Therefore, we must build in a margin of safety in order to ensure that we maximize energy efficiency opportunities in a cost-effective manner.

In their July 2, 2009 supplements to their March 2, 2009 re-filed applications, the utilities' proposed portfolios show their expected cost-effectiveness calculations. In order to determine exact cost-effectiveness ratios, it would be necessary to make several adjustments to the cost-effectiveness calculations provided by the utilities due to data inaccuracies as well as changes required by this decision. In most cases, the utilities did utilize 2008 DEER values and assumptions as directed by this Commission. However, in some cases the utilities did not properly apply the 2008 DEER values and assumptions when developing their underlying calculations for determining cost-effectiveness. For example, utilities did not always use the correct remaining useful life estimates in DEER, and did not properly calculate the positive electric and negative gas HVAC interactive effects for CFL and other measures due to not properly accounting for air conditioning or natural gas vs. electric space heating saturations within their service areas.

There is insufficient record to calculate cost-effectiveness ratios taking into account all necessary DEER adjustments. However, we note that identified inaccuracies above move the cost-effectiveness ratios lower. As discussed above, in their July 2009 filings the utilities did not include potential utility incentive reward payments in their TRC calculations. Properly including these potential incentive payments also has the effect of lowering the actual cost-effectiveness ratios. We will use the July 2009 utility-provided cost-effectiveness calculations in our analysis, as these are the only fully-discussed figures in the record. In order to meet our statutory obligation to approve cost-effective energy efficiency programs and to set just and reasonable rates, it is prudent policy to adopt a sufficient margin of error so that achieved cost-effectiveness ratios will be certain to remain above 1.0.40

The cost-effectiveness ratios proposed by the utilities in their July 2009 supplemental applications are shown in Table 4.

Table 4-Portfolio Cost-Effectiveness in Utility Applications41

Utility Cost-Effectiveness Summary

 

 

Total Resource Cost (TRC)

Program Administrator Cost (PAC)

PG&E

1.15

1.37

SCE

1.25

2.07

SDG&E

1.24

1.25

SoCalGas

1.17

1.19

 

We agree with DRA that the utilities should be able to attain energy savings consistent with previous portfolio cycles; however, the utilities all proposed portfolios which have high costs and low cost-effectiveness. In this section, significant budget adjustments are made which both decrease costs and increase cost-effectiveness. The method for achieving these dual goals is to reduce proposed budget items which do not directly contribute to cost savings, such as in the areas of overhead, administrative costs, EM&V and ME&O.

In a December 12, 2008 Ruling outlining requirements for the re-filed applications, one principle was that the portfolios should have TRC ratios at or above 1.5. This level of cost-effectiveness provides a safety margin in the event that the utilities do not, for whatever reason, attain the savings anticipated in their applications or if their costs increase above projections. In addition, as noted above the budgets used to calculate the TRCs do not include the costs of any shareholder incentives that may result from the RRIM or administrative costs included in the utilities' General Rate Cases. Each of these variables could cause swings in the costs and/or benefits of the portfolios in the hundreds of millions of dollars.

One of the primary reasons behind our placement of energy efficiency at the top of our loading order is the principle that prudently implemented energy efficiency programs can achieve more savings per dollar spent than a typical power plant. We must ensure that each dollar is spent is necessary in order to deliver the full benefits of energy efficiency programs to ratepayers.

While we are sympathetic to the utilities' arguments that as programs mature, additional savings are harder to reach to ensure the continued premier role of energy efficiency in our loading order and in California energy policies, we must be vigilant in avoiding sky-rocketing costs of obtaining large amounts of energy efficiency. In this decision we approve significant increases in the utility budgets from the last cycle (42% higher) but not the unjustified 77% budget increase from 2006-2008 that the utilities' request.

In Section 4.4, we adopt a 10% cap on the utilities' general administrative costs. In addition, we find compelling the evidence provided by TURN in its April 2009 comments that shows national trends for administrative costs, EM&V levels, ME&O budgets and other areas, as shown in Table 5, below. This table demonstrates that in many cases, the utilities' proposed budgets are out of line with budgets for successful statewide programs in other states. As discussed in Section 4.4, we note SCE's contention that there are significant differences in other states which limit comparisons to California. However, we find the overall set of data from other states to be useful in aggregate (excluding outliers), as they include those states with energy efficiency programs most similar to California's. Further, by taking the average levels of these states, we factor out any significant outliers.

SCE also claims the budget caps in general are unduly restrictive, unnecessary and would jeopardize its ability to successfully implement the portfolio. SCE advocates removal of all such caps, suggesting that otherwise important and useful programs would need to be eliminated and SCE would not be able to achieve Commission Strategic Plan objectives.

PG&E in comments on the Proposed Decision similarly claims that caps on administrative costs, ME&O costs, EM&V costs and Non-Rebate/Incentive Direct Implementation activities-combined with a 1.5 TRC target ratio-will result in elimination or significant reduction of programs that deliver cost-effective savings. PG&E also argues the 20% Non-Rebate/Incentive Direct Implementation cap would result in reduced support for Strategic Plan Big Bold Initiatives in favor of low-cost, high-turnover activities such as upstream incentives. PG&E contends that it is unrealistic to expect it to deliver the energy savings goals in the decision with local ME&O funding capped at 5% of its budget ($43 million in the Proposed Decision).

SDG&E/SoCalGas in comments on the Proposed Decision contends cost caps impose significant, unnecessary barriers to efficient program implementation and innovative program development, removing flexibility to respond quickly to constantly changing market conditions. As with the other utilities, SDG&E/SoCalGas claims that ME&O and other programs in other states are not comparable to those in California. SDG&E/SoCalGas also contends that the TRC ratios of the portfolios should be adjusted to take into account changes cost caps. If the Commission does approve cost caps, SDG&E/SoCalGas state that it is necessary to clearly define these categories to ensure consistency among the utilities and ensure easy tracking of status, with caps based on historical spending and best practices.

Using this data as a guideline for our programs, we reduce the ME&O budget to 6% of the adopted portfolios, which is a reduction from the proposed levels of around 8%, but still above national trends (excluding Vermont as an outlier). This is not a hard cap, as with administrative costs, but a budget target. This target is reasonable. As discussed in the ME&O section, the centerpiece of our ME&O program-the statewide ME&O branding and outreach program-has a budget of $60 million, with additional funding coming from already approved budgets for the LIEE and Demand Response programs This reduction is also consistent with the direction of D.07-10-032, in which we noted our concerns about the increasing ratepayer costs of ME&O for California's demand-side programs and directed a statewide, integrated approach. Such an approach, which is set for launch later this year or early next year, will not only leverage various demand-side customer programs but also allow overall ME&O cost reductions.

We tentatively set an EM&V cost cap at 4% of the total adopted budget, consistent with the national averages in Table 5 (excluding New Jersey as an outlier). As discussed in Section 7, this level appears to provide sufficient funds to carry out both utility and Energy Division EM&V functions. However, we will consider EM&V tasks in more detail in a follow-up decision, and may reconsider this budget item at that time.

We also set a budget target of 20% on the non-incentives and rebates budgets for program delivery, consistent with the national average in Table 5 below (excluding Vermont as a outlier). Of the four utilities, this measure impacts only PG&E's budget. PG&E's proposed program delivery budget includes non-incentives and non-rebate costs of 35%. With the 20% budget target we set, more of the program costs will be available for incentives and rebates, thus bringing PG&E's costs in line with the other utilities as well as the national average.

Table 5-National Energy Efficiency Budgets

*Program delivery includes direct install labor and materials, sales, technical assistance and quality control. In Vermont, it includes the "Services and Initiatives" category. In New Jersey, it includes "rebate processing".

Sources:

Cape Light: http://www.mass.gov/Eoeea/docs/dpu/electric/0

Efficiency Vermont: http://www.efficiencyvermont.com/stella/filelib/AR20

New Jersey: http://www.njcleanenergy.com/files/file/Library/BPURpt4Q07Master%

Oregon Trust: http://www.energytrust.org/library/financial/2008-09_Budg

Connecticut: http://www.ctsavesenergy.org/files/FINAL%202009%20C&LM%20Electric%2

National Grid: http://www.mass.gov/Eoeea/docs/dpu/electri

NSTAR: http://www.mass.gov/Eoeea/docs/dpu/electric/08-

We also, as discussed below, reduce costs which have been budgeted, but not allocated, and finally, impose some further budget cuts in those areas which have the least impact on direct implementation of programs.

With the reductions in broad budget categories, it appears that it will be possible to reduce the utilities' budgets sufficiently to attain a higher TRC ratio. However, it is not possible to achieve a TRC ratio near 1.5, although PAC ratios are higher by definition than TRC ratios. Nevertheless, we can adopt cost-effective budgets for each utility which provide an appropriate balancing of ratepayer cost protection and quality energy efficiency programs, consistent with the Strategic Plan.

As discussed in detail below, for 2010-2012 PG&E's adopted budget is $1.338 billion, SCE's adopted budget is $1.228 billion, SDG&E's adopted budget is $278 million, and SoCalGas' adopted budget is $285 million. In total, the overall adopted budget level for the four utilities for 2010 through 2012 is $3.129 billion, or $1.043 billion per year. This is approximately 42% higher than the $2.2 billion budgets approved for the 2006-2008 portfolios, and 22% higher than the bridge funding 2009 budget of $857 million. While the adopted budget levels are significantly lower than the utilities' requests, these budgets are still robust and are set at reasonable levels to protect ratepayer interests while at the same time providing a reasonable opportunity for the utilities to achieve the new (lower) adopted energy savings goals levels. As actual experience is gained over the next three years the utilities can request budget augmentations as circumstances warrant if these budget changes cause undue hardship in delivery of programs and savings.

PG&E proposes a budget of $1.633 billion, which it calculates to have a TRC ratio of 1.15. To determine a final budget, we look to achieve a TRC closer to 1.5. In order to achieve a TRC of 1.5, PG&E's budget would have to be reduced to around $1.1 billion, a target reduction of over $500 million.42 Such a large budget reduction would be inadvisable, as PG&E would have to eliminate or scale back a significant number of valuable programs. Instead, we seek to streamline PG&E's budget consistent with the caps and targets discussed above, and in light of other appropriate changes discussed herein.

The PG&E budget includes a $30 million reduction from the Basic CFL budget, as explained in Section 5.2. $11 million is added for Advanced Lighting programs in Section 5.2. $45 million is added for residential retrofit programs in Section 5.1.

We adopt a budget of $1.338 billion. Table 6 summarizes the changes discussed herein.

Table 6-PG&E Budget Adjustment Categories

         

Cost Category

Proposed (Millions)


% of total budget

Adjustment

(Millions)

Approved Budget (Millions)

Administrative G&O

$245

10%

-$110

$ 134

EM&V

$121

4%

-$68

$ 5343

ME&O

$136

6%

-$56

$ 80

Program Delivery,

        

non-rebates and

        

incentives

$336

20%

-$61

$ 275

Unallocated Third Party Funds

  

n/a

-$27

$

Basic CFLs

$60

n/a

-$30

$ 30

Advanced Lighting Increase

    

+$11

  

Residential Retrofit

    

+$46

  

Budget and Changes

$1,633

 

-$295

$1,338

In total, the reductions for administrative costs, EM&V and ME&O categories consistent with the guidance in this section reduce PG&E's costs by $234 million. To consider additional reductions, we turn to non-incentive costs associated with resource programs.

PG&E's budget shows $534 million for "Direct Implementation (Non-incentives and Rebates)." This category (labeled "C.2" in its budget and in Table 3) has the following description:

Activity includes all implementation costs for Emerging Technologies, Codes & Standards, Workforce Education & Training, Lighting Market Transformation, Zero Net Energy Pilots, local and statewide Demand-Side Management integration and On-Bill Financing. Also included are direct implementation non-incentive costs associated with incentive-based programs. These costs include education and training, engineering support, project management, customer support for certain sub-programs (e.g., Energy Audits and Continuous Energy Improvement), market transformation and long term strategic plan support.

These activities are generally consistent with a broad-based energy efficiency program. However, some of these activities are peripheral to the direct delivery of energy efficiency services and may not contribute to the cost-effectiveness of PG&E's portfolio. Of the $534 million associated with this category, we do not touch the $198 million of costs dedicated to specific non-resource programs. We make adjustments to the remainder ($336 million) which appears to be indirect and support activities for resource programs. We reduce resource program indirect and support activities to 20% of the total portfolio. This is the national average of program delivery costs (excluding incentives and rebates) shown in Table 5 above, and is consistent with or higher than the level of costs for SCE, SDG&E and SoCalGas. By reducing these costs to approximately 20% of the adopted budget level, PG&E's indirect and support costs for resource programs are reduced from $336 million to $275 million, a reduction of $61 million.

PG&E's proposed third-party program budget44 is $248 million, including $27 million in "Third-Party Reserve Funds." This latter category appears to consist of unallocated funds with no specific programs or recipients. We eliminate this line item.

With these changes, we will adopt PG&E's total budget at $1.338 billion. Most of the changes do not impact energy savings, but (as PG&E points out in comments on the Proposed Decision), changes to CFL programs, residential retrofit programs and other items do have an impact. It is not possible to determine a definitive TRC ratio for PG&E's portfolio. However, we find by decreasing various costs for administration, ME&O and EM&V line items the overall TRC ratio is likely to be higher than proposed by PG&E.45 At this budget level, we find that PG&E would have a cost-effective portfolio, with a reasonable margin of safety.

      4.5.2.2. SCE Budget Adjustments

Using a similar methodology as for PG&E, we would need to adjust SCE's proposed budget of $1.343 billion46 to a target budget of about $1.1 billion, a reduction of about $240 million, to increase SCE's TRC from its calculated level of 1.25 to a target TRC of 1.5. Such a large budget reduction would be less problematic than for PG&E, as SCE's starting TRC ratio is higher. However, with this reduction, SCE may have to eliminate or scale back a significant number of valuable programs. We will modify SCE's budget consistent with the caps and targets discussed above, and in light of other appropriate changes discussed herein.

SCE's budget is increased by $33 million for residential retrofit programs discussed in Section 5.1. We adopt a budget of $1.228 billion for SCE. Table 7 summarizes the changes discussed herein.

Table 7-SCE Budget Adjustments Categories

         

Cost Category

Proposed (Millions)

% of total budget

Adjustment(Millions)

Approved Budget (Millions)

Administrative G&O

$180

10%

-$58

$ 122

EM&V

$90

4%

-$41

$ 49

ME&O

$106

6%

-$33

$ 73

Program Delivery,

        

non-rebates and

        

incentives

$206

20%

0

$ 206

Unallocated Third Party Funds

n/a

-$53

Local Government Increase

    

+$32

  

Residential Retrofit Programs

Benchmarking program

    

+$33

$4

  

Budget and Changes

$1,344

 

-$116

$1,228

In total, the reductions for administrative costs, EM&V and ME&O categories, reduce SCE's costs by $132 million.

SCE's total third-party budget proposal is $263, including $53 million in `Third-Party Solicitation Programs (Non-Resource and Direct)." This latter category appears to consist of unallocated funds. We eliminate this line item, thus reducing SCE's budget by $53 million. This brings SCE's third-party budget to $210 million which is above our 20% threshold from D.05-01-055. Thus no further adjustments are required for this item.

SCE's budget shows $295 million for "Direct Implementation (Non-incentives and Rebates)." Of the $295 million associated with this category, we do not touch the $89 million of costs dedicated to specific non-resource programs. We make adjustments to the remainder ($206 million) which appears to be indirect and support activities for resource programs. This amount is above 20% of the total portfolio. We will not make any adjustments on this item.

With these changes, we will adopt SCE's total budget at $1.228 billion. Most of the adopted changes do not impact energy savings, but residential retrofit programs and other items do have an impact. We anticipate that residential retrofit programs are likely to have a positive TRC ratio, however we are unable to determine the impact of the additional local governmental programs. Overall, it is not possible to determine a definitive TRC ratio for SCE's portfolio. However, we find that the overall TRC ratio should be higher than proposed by SCE, due to reductions in administrative costs, EM&V and ME&O line items and the addition of the residential retrofit program. At the approved budget level, we find that SCE would have a cost-effective portfolio with a reasonable margin of safety.

      4.5.2.3. SDG&E Budget Adjustments

The situation for SDG&E is somewhat different than for PG&E and SCE. First, we have decreased SDG&E's electricity energy savings goals by an additional 25% as compared to the other utilities, as described in Section 4.2. This reduction will allow SDG&E much more ease in reaching its energy savings goals. Second, as discussed below, SDG&E's proposed budget includes zero participant costs for many measures, distinct from its counterparts.

SDG&E's proposed budget of $499 million has a TRC of 1.24, based on SDG&E's calculations. SDG&E included $45 million in unspent funds in this budget; after review of SDG&E's errata to its supplemental testimony filed August 20, 2009, SDG&E identified $80.1 million in unspent, uncommitted funds. In Section 12, we approve $17.4 million of these funds for use in 2009, leaving approximately $63 million that can be applied to 2010 -2012. In order to normalize SDG&E's budget for consistency with the other utilities, SDG&E's budget is adjusted to $436 million. Further, as discussed below, SDG&E's TRC ratio is affected by the changes to customer incentive levels.

Using a similar methodology as for PG&E and SCE, in order to achieve a cost-effectiveness ratio of 1.50, SDG&E's budget of $436 million would need to be reduced by about $175 million to around $255 million. Such a large budget reduction would be less problematic than for PG&E and SCE, because a significant amount of the reduction comes from reduced customer incentive payment, which do not otherwise change programs. We seek to streamline SDG&E's budget consistent with the caps and targets discussed above, and in light of other appropriate changes discussed herein.

We adopt a budget of $278 million for SDG&E. Table 8 summarizes the changes discussed herein.

SDG&E

        

Cost Category

Proposed

(Millions)

% of total budget

Adjustment (Millions)

Approved Budget (Millions)

Administrative G&O

$66

10%

-$39

$ 27

EM&V

$37

4%

-$25

$ 12

ME&O

$41

6%

-$23

$ 18

Incentive Payments

$276

n/a

-$84

$192

Residential Retrofit Program

    

+$13

  
         

Budget and Changes

$436

 

-$158

$ 278

In total, the reductions for administrative costs, EM&V and ME&O categories, including carryover dollars, reduce SDG&E's costs by $89 million.

Our review of SDG&E's program cost numbers reveals a significant issue in its budget. Unlike PG&E and SCE, SDG&E does not include any customer participation costs in its program costs, instead proposing to pay incentives at 100% of the full incremental costs of the measures. While we have not provided specific guidance in this area in the past, the practice of PG&E and SCE is more appropriate and more consistent with past portfolios. Customers are likely to demand more services when they do not pay for them, even if these services are not valuable. It is common industry practice to include a customer contribution-which is still below the full cost of the energy efficiency service or product-in order to ensure customer "buy-in," minimize ratepayer costs, and to offer incentives to a larger number of customers. Paying 100% incentives is also inconsistent with all past practices of California utilities, including SDG&E.

It appears that SDG&E may have proposed overly high customer incentive levels in order to meet unrealistic energy savings goals. However, we have now adjusted SDG&E's goals downward by 25% to correct an historical anomaly. Therefore, consistent with adjusted energy saving goals, we require SDG&E to reduce incentive payments to levels consistent with those provided by SCE and PG&E for similar programs. Based on comparisons with SCE and PG&E incentives we estimate that SDG&E can spend at least $84 million less due to this adjustment.47

Some of the adopted changes do not impact energy savings, but residential retrofit programs and other items do have an impact. In particular, reducing SDG&E's customer incentive payments to reasonable levels lowers SDG&E's energy savings and changes its cost-effectiveness by unknown amounts. It is not possible to determine a definitive TRC ratio for SDG&E's portfolio. Because the changes we make affect SDG&E's cost-effectiveness to a greater degree than for PG&E and SCE, we can find that the SDG&E will have a cost-effective portfolio, but we cannot determine a specific range for the TRC ratio.

4.5.2.4. Southern California Gas Budget Adjustments

The situation for SoCalGas is similar to that of SDG&E, in that SoCalGas' proposed budget includes zero participant costs for many measures, distinct from its other counterparts. While SDG&E may have included this unorthodox proposal in order to attempt to achieve high energy savings goals (which we have now reduced substantially), there is no clear rationale for why SoCalGas also made this proposal.48

SoCalGas' proposed $495 million budget would have an estimated TRC ration of 1.17, by its calculations. The proposed budget needs to be reduced by at least $200 million to below $300 million to achieve a target cost-effectiveness ratio of 1.5, using the same methodology implemented for SDG&E.

We will adopt a budget for SoCalGas of $285 million. Table 9 summarizes the changes discussed herein.

Cost Category

Proposed

% of total budget

Adjustments (Millions)

Approved Budget (Millions)

Administrative G&O

$42

10%

-$14

$ 28

EM&V

$37

4%

-$26

$ 11

ME&O

$19

6%

-$2

$ 17

Unallocated Third Party Funds

$76

n/a

-$40

$ 36

Incentive Payments

$268

n/a

-$135

$ 133

Residential Retrofit Programs

    

+$8

  
         

Budget and Changes

$495

 

-$210

$ 285

In total, the reductions for administrative costs, EM&V and ME&O categories reduce SoCalGas' costs by $42 million. SoCalGas' total third-party budget proposal is $76 million, including $40 million in "IOU Administration." This latter category appears to consist of unallocated funds. We eliminate this line item, thus reducing SoCalGas' budget by $40 million.

Like SDG&E, SoCalGas does not include any customer participation dollars in program costs, instead proposing to pay incentives at 100% of the full incremental costs of programs. It is unclear why SoCal Gas included these higher incentive levels, although this may because of its sister utility relationship with SDG&E. As with SDG&E, for consistency with longstanding practice, we will require SoCalGas to reduce incentive payments to levels consistent with those provided by PG&E for similar gas programs. Based on comparisons with PG&E gas incentives we estimate that SoCalGas can lower its costs by at least $135 million from this adjustment.49

With these changes, we will adopt SoCalGas' total budget at $285 million. Some of the adopted changes do not impact energy savings, but residential retrofit programs and other items do have an impact. In particular, reducing customer incentive payments to reasonable levels lowers SoCalGas' energy savings and changes its cost-effectiveness by unknown amounts. It is not possible to determine a definitive TRC ratio for SoCalGas' portfolio. Because the changes we make affect SoCalGas' cost-effectiveness to a greater degree than for PG&E, we can find that the SoCalGas will have a cost-effective portfolio, but we cannot determine a specific range for the TRC ratio.

4.5.3. Avoided Costs

D.06-06-063 adopted electric and gas avoided cost for use in planning and evaluation of the 2006-2008 energy efficiency utility portfolios. These interim values were not adopted for other uses or future energy efficiency cycles. Thus there are no avoided costs adopted for this program cycle yet. The April 21, 2008 Ruling directed the utilities, for planning purposes, to update the generation cost values and natural gas prices using the updated 2007 values as adopted in the Commission's October 4, 2007 Resolution E-4118 (the updated 2007 Renewable Portfolio Standard market price referent values) for their portfolio cost-effectiveness calculations. Energy Division provided updated electric avoided cost values utilizing these generation costs and updated generation natural gas fuel cost estimates. The utilities used these values in their applications. We adopt these avoided cost values used by the utilities for this portfolio.

In this decision, we revise our definition of Market Transformation, require the development of Program Performance Metrics, and set forth a process for adopting market transformation metrics and tracking systems.

In our decision adopting the Strategic Plan, we discussed our vision of market transformation for energy efficiency:

As early as 1998, the Commission defined market transformation as "Long-lasting sustainable changes in the structure or functioning of a market achieved by reducing barriers to the adoption of energy efficiency measures to the point where further publicly-funded intervention is no longer appropriate in that specific market."50 D.07-10-032, p. 33, directed that "a key element of the Plan would be that it articulates how energy efficiency programs are or will be designed with the goal of transitioning to either the marketplace without ratepayer subsidies, or codes and standards." These statements continue to encompass our definition of market transformation. D.07-10-032 also stated that the forthcoming Plan would incorporate the market transformation goal described above and "develop milestones to measure progress towards that goal," including the development of a "targeted timeframe for such market transition and the process for tracking progress so that it is clear at what point a program has made a successful transition or conversely, is having problems." (D.08-09-040 at 14-15, emphasis added).

D.08-09-040 at 10 also stated that "the Commission will take action by the end of 2009, or when the utility 2009-2011 portfolios are approved, whichever is sooner, on the remaining issues that need to be addressed in market transformation. This includes, at minimum, identifying the process to track progress towards defined end points for program efforts and progress metrics." In this decision we:

_ Amend our definition of "Market Transformation"

_ Adopt a process to develop and apply Program Performance Metrics to the 2010-2012 portfolios and beyond. As part of our regular EM&V process, these metrics will measure and track whether a specific energy efficiency portfolio program - e.g., incentives for high efficiency air conditioners -- is advancing our market transformation goals.

_ Discuss a process to track market conditions in the broader markets - e.g., the air conditioning market in California -- in order to determine whether and what interventions are needed and when the market has been transformed.

_ Clarify how these metrics will be used to evaluate utility programs.

_ Decline to establish a Market Transformation Task Force.

A number of parties commented that the Commission's definition of market transformation should be updated and that an important component of market transformation is to pull new technologies into the marketplace more quickly than is achievable without public or utility program intervention. This is consistent with the Strategic Plan focus on accelerating the adoption of new technologies and building or system designs into the marketplace.

We modify the existing Commission definition of market transformation to state (changes noted in italics):

Market transformation is long-lasting, sustainable changes in the structure or functioning of a market achieved by reducing barriers to the adoption of energy efficiency measures to the point where continuation of the same publicly-funded intervention is no longer appropriate in that specific market. Market transformation includes promoting one set of efficient technologies, processes or building design approaches until they are adopted into codes and standards (or otherwise substantially adopted by the market), while also moving forward to bring the next generation of even more efficient technologies, processes or design solutions to the market.

We also clarify the definition of "defined end points." Previous decisions have employed this terminology in different ways. In D.08-09-040, we stressed the need to develop "a process to track progress towards defined end points for program efforts and progress metrics." In this context "defined end points" refer to the time-bound and quantitative milestones and targets included in the Strategic Plan, specifically the Big Bold Programmatic Initiatives on zero net energy buildings, as well as the other quantitative targets contained in the Strategic Plan.

This concept is also used for specific technologies or practices, i.e., the extent to which each program plan included an `end game' for each technology or practice. An example of the technology approach could be a plan to terminate upstream utility incentives for medium-base CFLs when market penetration reaches a certain level while continuing targeted programs for CFLs in niche market segments that have not yet reached those adoption saturations.

An October 30, 2008 Ruling directed the utilities to "demonstrate that their 2009-2011 energy efficiency programs reflect the short-term steps and milestones laid out in the Strategic Plan for the programmatic initiatives identified in D.07-01-032 and for each sector or cross-cutting action area."51 To this end, the utilities were directed to submit market transformation planning estimates and program logic models in a specified Program Implementation Plan (PIP) format with their re-filed portfolio applications. The purpose of this requirement was to supply data that linked the program logic models to short and long-term Strategic Plan goals. After a June 8, 2009 workshop on this issue, a Ruling solicited additional information from stakeholders for consideration for the 2009-2011 portfolios.

4.6.2.1. Positions of Parties

SDG&E and SoCalGas recommend that simplicity and cost-effectiveness should be considered when identifying appropriate program performance indicators. PG&E states that the metrics included in the current PIPs are preliminary in nature and will be further developed along with program logic models once the Commission adopts the portfolio applications. PG&E points out that program decisions and assessments cannot be based on performance metrics alone as other factors contribute to program performance such as external market conditions. PG&E also suggests that not all programs need metrics if overarching market metrics that can track the success of several programs are more applicable.

SCE suggests that the Commission should carefully consider metrics already provided by the utilities and not entertain another process to determine alternative metrics as proposed in Energy Division's Program Performance Metrics Workshop. TURN/DRA supports the Energy Division's proposed process for developing program performance metrics with the caveat that the utilities should not be the driving entity for developing program performance metrics. They propose that the Commission establish a task force comprised of the utilities, Energy Division staff, and interested stakeholders. Performance metrics would be updated when the Strategic Plan is updated and the utilities would be required to submit and track program performance metrics in a publicly available data base such as the Energy Efficiency Groupware Application (EEGA) used for utility quarterly energy savings reports.

4.6.2.2. Discussion

As PG&E points out, the information submitted by the utilities in response to the October 30, 2008 Ruling is, at best, preliminary. After review of the limited utility response, we recognize that further guidance to the utilities is needed to define our expectations and objectives for the program performance metrics. The utilities are in the best position to develop metrics for their own programs, but input from stakeholders and further Commission review is necessary. We adopt a process for development of targeted program performance indicators and logic models. This required process applies to all statewide programs and sub-programs, as well as pilot projects, as discussed throughout this section and in Section 4.3. In order to adequately develop these indicators, it is important to have a clear definition of what they are and the characteristics they should have.

Program performance metrics are objective, quantitative indicators of the progress of a program toward the short and long-term market transformation goals and objectives in the Strategic Plan. Appendix 2 of this decision includes an Energy Division process for developing program performance metrics that the utilities shall use when developing these metrics.

The proposed performance metrics shall comply with the following principles:

1. The metrics shall be designed for simplicity and cost effectiveness when considering data collection and reporting requirements.

2. Integrated metrics shall be developed for programs that employ more than one technology or approach, such as whole building programs.

3. Program models and logic should be dynamic and change in response to external, e.g., market conditions, and internal conditions.

4. The metrics shall link short-term and long-term strategic planning goals and objectives to identified program logic models.

5. Performance metrics shall be maintained and tracked in the Energy Efficiency Groupware Application database (or a similar database to be determined under the guidance of Energy Division).

We accept PG&E's position that in some cases, overarching market metrics that can track the success of several programs may be more appropriate than program-specific metrics. We have no objection to the application of one set of program metrics to several programs if the metrics are otherwise valid for each program.

The utilities shall request approval for their proposed logic models and metrics via an advice letter filing within 120 days of the effective date of this decision. One joint utility advice letter shall be filed encompassing the proposed performance metrics for each statewide program (and associated sub-programs) and other information as specified in Appendix 2. The utilities will track the program performance metrics using the EEGA or a similar database as DRA/TURN recommend and under the guidance of our Energy Division.

Beyond this program cycle, the utilities shall submit one similar joint advice letter encompassing each statewide program and associate sub-programs for each program cycle as part of their three year energy efficiency portfolio application process.

The utilities shall track Program Performance Metrics via the EEGA or a similar database as DRA / TURN suggest. Under Energy Division oversight, the utilities shall develop and post a standardized Program Performance Metric Reporting Table to the EEGA or a similar database no later than January 29, 2010. The utilities shall use these tables to report progress toward meeting program performance metrics and post this information onto the EEGA or a similar database on a quarterly basis. The utilities shall also work with Energy Division to develop and post onto EEGA or a similar database a standardized Program Performance Metrics Narrative Reporting Template at the same time. This template shall then be used by the utilities to provide narrative description of progress to accompany each quarterly Program Performance Metric Reporting Table submission. This Program Performance Metrics Narrative Reporting Template shall include sections for describing progress toward meeting program metric goals as well as descriptions of changes in metrics used and reasons for the change as well as any program related or economic changes that impact metric results. If the utilities revise their program performance metrics via the Advice Letter process described above, they shall clearly indicate in their EEGA or similar database submissions when this occurs and reasons for any changes as part of their Program Performance Metrics Narrative Report filed on EEGA Narrative description. All historical Program Performance Metric submissions shall be maintained in EEGA or a similar database, as determined by Energy Division.

4.6.3. Market Transformation Metrics

In order to track market transformation, it is necessary to track market conditions. The results of the program performance metrics can then be compared with the market data to determine the relative success of the programs. We set forth principles and a process for developing and implementing market tracking systems.

        4.6.3.1. Positions of Parties

DRA/TURN, SCE, SDG&E and SoCalGas all agree with Energy Division's general approach on market indicators, specifically the merits of using both "ultimate" and "proximate" metrics as indicators of market change. Several parties provided suggestions on the best indicators of technology and sector-based market transformation. DRA/TURN consider market share and measure adoption and saturation rates to be key indicators. NRDC finds sales, market share, saturation and the prevalence of a practice or technology to be the most important indicators. WEM stresses evaluated net-to-gross ratios as the key market transformation indicator.

PG&E contends that utility program strategies must be based on an understanding of the factors that drive market penetration into each significant submarket and the opportunities to influence them rather than pre-identified model curves. SDG&E, SoCalGas and SCE all focus on incremental measure cost (meaning that as the incremental cost of a high-efficiency measure or device declines toward zero, this is an indicator the market is being transformed) as a key market transformation indicator, as well as sales, building stock penetration rates, customer satisfaction and the disappearance from the market of less efficient options.

On process issues, DRA/TURN and CCSF recommend that Energy Division develop detailed recommendations for market transformation indicators and measurement approaches starting with the Big Bold Programmatic Initiatives from D.07-10-032. SCE disagrees, stating that the identification of appropriate market transformation metrics and reasonable goals based on those metrics must be established by a broader group. PG&E agrees with TURN/DRA's recommendation that the Energy Division lead the process, PG&E believes that the basic indicators shaping market transformation efforts should be adopted by the Commission to ensure they align with long-term policies developed by the CEC and CARB.

It is evident from the discussion at the Market Transformation workshop and party comments that it would be premature to adopt metrics in this decision. Therefore, in this decision we set forth the principles and the process for the development of a system to measure and monitor market transformation efforts.

        4.6.3.2. Principles for Developing a Market Transformation Monitoring System

We agree with DRA/TURN, SCE, SDG&E and SoCalGas, who supported Energy Division's general approach to developing market transformation indicators, specifically that both "ultimate" and "proximate" metrics as indicators of market change are warranted. Ultimate indicators are defined as indicators of structural changes in the patterns of adoption of the technology or behavior change, which should relate closely to key barriers that need to be overcome. Examples of ultimate indicators are: market share and sales; saturation and prevalence of practices; changes in codes & standards; and, adoption of technology or practice as common practice. Proximate indicators are indicators that are necessary preconditions for increases in ultimate indicators. Examples of proximate indicators include: awareness and knowledge; attitudes/beliefs/acceptance; availability; trade ally promotional efforts; and, incremental cost. These indicators shall form the basis of the market transformation metrics.

        4.6.3.3. Process for Developing Market Transformation Metrics

The market transformation metrics require the identification of indicators to track, the identification of data sources, and agreement on the frequency of data collection, analysis and use. DRA/TURN and CCSF suggest the most practical process to identify key market transformation: Energy Division should develop detailed recommendations for market transformation indicators and measurement and present their recommendations in a workshop followed by a public comment period. Further, we concur with PG&E that it is appropriate that such indicators are ultimately adopted by the Commission in order to ensure their alignment with not only the Strategic Plan, but also the work of other California agencies, such as the CEC and the CARB.

Although we decline to adopt SCE's recommendation that market transformation metrics be developed by a broader group that includes multiple energy efficiency program administrators and key industry stakeholders, the insights and suggestions of such entities are key to the success of the Strategic Plan and its market transformation goals. Therefore, we direct Energy Division to ensure appropriate involvement and input of market actors during their development of recommendations for market transformation indicators.

Energy Division should provide initial recommendations on specific market transformation ultimate and proximate indicators, as well as data collection and tracking processes, for a subset of portfolio programs or measures that have the most impact in terms of their importance, such as the Big Bold Programmatic Initiatives, their savings potential or dollars spent. Staff may also consider qualitative factors as necessary and appropriate.

It is both necessary and possible to begin the work of gathering baseline data, as CCSF, PG&E, DRA/TURN and others have noted. We therefore direct the utilities to include key data sources and indicators for which to begin collecting market transformation baseline data in their Advice Letters on Utility Program Performance Metrics.

We will address the market conditions data tracking process in R.06-04-010, the umbrella energy efficiency rulemaking proceeding, or its successor. In that proceeding, we will also consider the appropriate timing for the commencement of the system of market transformation metrics.

      4.6.3.4. Use of Program Performance Metric and Market Conditions Data

SCE argues that the proposed metrics should not be used to measure program performance during the program cycle since program performance is already measured by the energy savings and demand reductions achieved by the program. DRA recommends that the Commission devise a specific long-term market transformation plan for each energy efficiency strategy and require utilities to intervene in the market where they have control over strategies to target and educate consumers. DRA/TURN contends that all ratepayer-rebated measures should be on trajectory for phase out, with milestones indicating progress towards this goal, and elimination of ratepayer-funded market interventions once the technologies reach more than 51% market segment participation. Further, DRA/TURN argue that the utilities should be required to present rationales and supporting material for each portfolio measure strategy that it believes has not yet achieved market transformation under the established.

In general, we agree with DRA/TURN's recommendations, but decline to adopt a bright line rule such as the 51% market participation rate. While we do not rule out the possibility of adopting specific market segment participation rates as targets for phase out of ratepayer funded programs on a case-by-case basis, we have no basis for adopting a single rule for all programs and markets.

We agree with TURN that the market transformation data and metrics should not only serve to define end points for programs and measures but also to improve existing programs. Program Performance Metrics and market conditions data shall serve the following purposes:

· To track California's progress towards achievement of the Strategic Plan objectives, specifically the Big Bold Programmatic Initiatives and other key Plan goals and objectives.

· To inform portfolio development and necessary modifications in future portfolio decisions, including improving program design or eliminating non-performing programs.

· To target the next generation of improvements and thus continue the cycle of market transformation.

Once approved, we will use these program performance metrics to track the progress of each program towards our market transformation goals. We clarify that these metrics are not a "pass/fail" test such that a failure to achieve a specific metric indicates the failure of the program or of utility performance. These metrics will allow the Commission to evaluate progress toward market transformation and to as a factor in determining whether the programs should be continued, modified or eliminated in future portfolios.

In future portfolio applications, the utilities shall provide rationale for continuing the measure and supporting material for each significant portfolio-level efficiency measure that they believe has not yet achieved market transformation, as suggested by DRA/TURN. For any program that the utilities propose to continue but which has failed to achieve established benchmarks for market transformation in previous cycles, the utilities must provide additional rationale for continuing these programs despite this non-performance. The utilities shall work with the Energy Division to agree on the format by which such information shall be provided.

A number of parties recommended the establishment of a Market Transformation Task Force or Collaborative, including DRA/TURN, CCSF, NRDC, PG&E and SCE. However, parties differ on proposals for the governance structure and work to be undertaken by such a group.

In this decision, we have outlined process to develop and to adopt market transformation indicators and a market transformation tracking framework that will enable the Commission to track progress on implementation of the Strategic Plan and for specific technologies and measures. However, we recommend that Energy Division's Strategic Action Plan Progress Report (referenced in Section 12) include as applicable progress on:

· further defining and characterizing markets;

· refining measure and market segment and sub-segment baseline information;

· sharing information on and refining market transformation program objectives, strategies and tactics and program tracking systems; and

· coordinating concurrent implementation of programs, program tracking, and program metrics systems.

Under the 2009 Federal American Recovery and Reinvestment Act (ARRA), California expects to receive funding for four areas of energy efficiency programs. These areas are:

This Commission has participated in several activities to ensure effective coordination and leverage of these federal funds, including holding a public workshop in March 2009, participation in a State interagency task force convened by the Governor's Office and staff discussions with the CEC.

Guidelines from the U.S. Department of Energy (DOE) identify as one objective for the federal funds to leverage additional investment and additional energy savings activity beyond the levels that otherwise would have occurred. Specifically, US DOE has established a target for the minimum additional energy savings expected per dollar of ARRA funding, measured against a baseline of state-level efficiency activity. Several participants in the March workshop stated that ratepayer-funded programs' technical assistance and incentive payments can facilitate the use of ARRA funds on expanded efficiency activities. However, it was acknowledged that there is a need for ARRA-funded activities to support services or functions that are not supported by utility ratepayer programs.

In D.09-05-037 we declined to alter policy rules governing crediting of energy efficiency savings to utilities in the case of multiple sources of customer motivations to take action. In a June 9, 2009 Ruling, parties were asked: "How should ratepayer funding for energy efficiency programs best be combined and leveraged with energy efficiency funding from the American Recovery and Reinvestment Act (federal economic stimulus program or ARRA) to support the energy efficiency activities of local governments? What principles or guidelines should the CPUC use in this combining and/or leveraging?" Parties' comments were received on June 29, 2009.

CCSF argues that the Commission should not establish or change any utility rules or requirements in response to ARRA and that the Commission should support local governments using ARRA funds to supplement ratepayer funded programs. CCSF proposes four guidelines for leveraging of ARRA and ratepayer funds towards energy efficiency: a) Recognize that local governments are accountable for how ARRA funds are spent; b) Respect the rules and criteria for ARRA spending by not adding further tracking and reporting requirements for ratepayer funded projects; c) Refrain from changing the existing Commission rules on shareholder credit for savings as a result of the ARRA; and d) Avoid penalizing projects for complying with ARRA requirements.

CCSF notes that local governments will be required by US DOE to track, records and report all activities related to ARRA spending including those that receive ratepayer dollars and demonstrate that the combination of ARRA funds and all other leveraged sources do not constitute "double dipping" and do not exceed total project cost. CCSF requests that where ratepayer funded incentives are available for particular measures, there should be no barriers imposed by the CPUC regarding how local governments use stimulus money to provide funds to cover the local government's share of project costs, or to fund additional measures in a proposed project such that the number and scope of projects can be increased. It also states that utilities should only claim savings from measures receiving ratepayer funds but should not be permitted to claim savings for Commission energy savings goals from any projects that do not receive ratepayer funded incentive dollars. NRDC agrees. CCSF notes that local governments should only report savings to US DOE from measures funded solely by stimulus money as savings additional to the savings reported for ratepayer funded programs. LGSEC's comments also generally agree with those of CCSF.

TURN and DRA also generally agree with the CCSF comments but disagree with the CCSF recommendation against adjusting cost-effectiveness determinations TRC estimate) for ARRA-funded projects, arguing instead that all energy efficiency costs should be included in the calculation of TRC and other performance metrics in order to produce accurate information. WEM requests that the Commission ensure that energy savings resulting from federally funded programs alone are clearly separated from accomplishments attributed to utilities from ratepayer funded programs or measures and notes that the Commission will need to be aware of all additional energy efficiency programs resulting from the ARRA.

SCE argues against prescribing new and different rules for crediting savings from combining ratepayer program funds with federal stimulus funds, noting that ARRA funds should be leveraged and combined just as any other source of funding would be. SCE explains that it is already working directly with local governments to ensure decision makers are aware of opportunities to leverage stimulus funds to promote energy efficiency and renewables in their communities, and stresses the need to maintain flexibility as much as possible given the short time frame for disbursement of ARRA funds.

PG&E disagrees with this approach, arguing that to encourage continued coordination and leveraging of utility funds with ARRA funds, the Commission should explicitly confirm that utilities will receive full energy savings credit when ARRA funds are used for the customer's share of costs to participate in utility energy efficiency programs. It also states that the Commission should not treat projects funded by ARRA any differently than projects that are not funded by ARRA. SDG&E and SoCalGas agree with PG&E that the Commission should encourage leveraging by not discounting utility savings attributions in any way in these collaborations.

4.7.2. Discussion

We largely agree that no changes to our rules or procedures are warranted at this time. As stated by CCSF and SCE, current Commission rules are sufficient to encourage coordination and leveraging of ratepayer and ARRA funds and to avoid duplicate attribution of savings. However, we clarify that that utilities should only claim savings to the Commission from measures receiving ratepayer funds, and should not claim savings from any non-resource program or project that does not receive ratepayer funded incentive dollars. Where there are projects or programs that receive both ratepayer and ARRA funding, the utilities (or the third party) should where possible track sources of costs and savings, and must ensure against double counting savings. We will review this as needed when the DOE releases final ARRA guidelines.

We direct Energy Division staff to work closely with the CEC to ensure that all savings from ratepayer funded programs are included in the state baseline provided to DOE and to inform DOE representatives of the results of this decision. If rules or conditions change such that a potential for double counting arises, we direct the Energy Division to bring the issues to the attention of the Assigned Commissioner and ALJ for further consideration and action.

As TURN/DRA state, accurate reporting of project costs where ARRA funds are combined with ratepayer funds should be reflected in record-keeping regarding project cost-effectiveness or other performance metrics.

Finally, we see no need, as requested by PG&E, SDG&E and SoCalGas, to state a-priori that utilities will receive full energy savings credit if ARRA funds are used in conjunction with ratepayer funds in a particular program. As identified above, existing Commission policies are sufficient to motivate coordination, leveraging, tracking and appropriate attribution of savings.

5. Statewide Programs

We adopt and fund twelve statewide programs, with some modifications specified below to be consistent with the Strategic Plan:

The initial utility applications in July 2008 included well over 200 distinct programs. These programs often overlapped within utilities, and failed to coordinate similar programs among utilities. One of our goals is to simplify the existing maze of programs into fewer, clearer and more coordinated programs so that customers, particularly those in multiple jurisdictions, can more easily access and understand the availability of ratepayer-funded programs.

The October 30, 2008 Ruling directing the utilities to re-file their applications stated: "(W)e must reduce very significantly the overall number of programs. We envision no more than 10 core statewide programs and perhaps another 20-30 for the entire suite of utility portfolios (not including third party programs)."53

In their March 2, 2009 re-filed applications and in the July 2, 2009 supplements, the number of utility programs was reduced to 12 statewide programs, plus a number of subprograms (some for only one utility). While this is not quite the minimal level sought by the October 2008 Ruling, it is a far more streamlined and integrated approach than in the initial applications. We find that the applications are consistent with our guidance in this area.

We consider each of the 12 statewide program areas below. Because of the high number of individual proposed programs within some of the statewide program areas, we do not discuss each subprogram. We discuss below major issues in each statewide program area and particular subprograms requiring our guidance.

Overall, the utility proposals are generally consistent with our previous decisions (including the Strategic Plan), and the guidance provided in rulings in this proceeding and R.06-04-010. All utility proposed programs are approved, except for those specifically modified or denied in this decision. The specific programs and program elements which we find need modifications are discussed in detail herein.

We approve the utilities' proposed programs and direct them to include a Prescriptive Whole House Retrofit program.

The Strategic Plan at 9 sets forth the Commission's vision for the residential sector: "Residential energy use will be transformed to ultra-high levels of energy efficiency resulting in zero net energy new buildings by 2020. All cost-effective potential for energy efficiency, demand response and clean energy production will be routinely realized on a fully integrated, site-specific basis."

The Strategic Plan goals for the residential sector are:

· Home buyers, owners and renovators will implement a whole-house approach to energy consumption that will guide their purchase and use of existing homes, home equipment (e.g., HVAC systems), household appliances, lighting, and "plug load" amenities.

· Plug loads will be managed by developing consumer electronics and appliances that use less energy and provide tools to enable customers to understand and manage their energy demand.

· The residential lighting industry will undergo substantial transformation through the deployment of high-efficiency and high performance lighting technologies, supported by state and national codes and standards.

The target outcome for these goals is an average 40% reduction in energy purchases by all homes by 2020.

Table 10 contains the utility proposed budgets for all programs within the residential portfolio.

Table 10-Residential Program Budget and Savings

Residential Statewide Programs

 

 

Budgets

kWh

KW

Therms

 

PG&E

$269,652050

1,460,488,865

266,519

-22,343,368

 

SCE

$227,166,000

1,642,062,213

291,095

0

 

SDG&E

$80,290,528

314,275,201

58,739

-1,435,200

 

SCG

$116,556,144

4,748,956

2,577

12,945,965

 

Total

$693,664,723

3,421,575,235

618,930

(10,832,603)

 

 

 

 

 

 

Residential Third Party Programs

 

PG&E

$9,285,172

3,426,324,191

621,507

2,113,362

 

SCE

$20,597,000

34,875,620

13,572

0

 

SDG&E

$22,658,455

1,187,201

1,691

17,443

 

SCG

$32,852,136

510,564

751

2,750,109

 

Total

$85,392,763

3,462,897,576

637,521

4,880,914

 

 

 

 

 

 

Residential Local Utility Programs

 

PG&E

$0

0

0

0

 

SCE

$1,360,000

0

0

0

 

SDG&E

$9,817,080

2,178,839

1,362

61,554

 

SCG

$11,889,010

650,562

469

947,167

 

Total

$23,066,090

2,829,401

1,831

1,008,721

 

 

 

 

 

 

Total Sector Budgets/ Savings

$802,123,576

6,887,302,212

1,258,282

(4,942,968)

The utilities' proposed residential portfolio includes the following programs:

· PG&E, SCE, SDG&E Statewide Residential Program: Home Energy Efficiency Survey Program, Residential Lighting Incentive Program for Basic CFLs, Advanced Consumer Lighting Program, Home Energy Efficiency Rebate Program, Appliance Recycling Program, Business and Consumer Electronics Program, Multifamily Energy Efficiency Rebate Program.

· SoCalGas Statewide Residential Program: Multifamily Energy Efficiency Rebates, Home Energy Efficiency Rebates, Home Efficiency Energy Survey.

· PG&E Local Utility and Third Party Programs: Enhance Time Delay Relay, ENERGY STAR Manufactured Homes, Direct Install for Manufactured and Mobile Homes, Whole House Performance Program.

· SCE Local Utility and Third Party Programs: Local Island Program, Whole House Performance, Efficient Affordable Housing, Comprehensive Mobile Home, Community Language Efficiency Outreach, On-Line Buyer's Guide.

· SDG&E Local Utility and Third Party Programs: Micro-Grid Pilot Program, Whole House Performance, Residential HVAC Tune-up/Quality Installation, Comprehensive Mobile Home (SW), K-12 Energy Efficiency Education, CHEERS Training.

· SoCalGas Local Utility and Third Party Programs: Whole House Performance Program, On Demand Efficiency, HERS Rater Training Advancement, Multifamily Home Tune-Up, Multifamily Solar Pool Heating, Community Language Efficiency Outreach, Multifamily Direct Therm Savings, LivingWiseTM, Manufactured Mobile Home, Upstream High Efficiency Gas Water Heater, and Energy Efficient Ethnic Outreach.

Pursuant to our direction, the residential section in the utility portfolios contains a single statewide residential program. Beginning January 2010, the California residential energy efficiency efforts shall be known as the California Statewide Program for Residential Energy Efficiency55 (SPREE), which will promote a comprehensive set of energy solutions within the residential market sector. The California SPREE will be comprised of seven subprograms and offer statewide consistency for measure availability, incentive levels, and marketing and outreach materials across the California utilities. The California SPREE portfolio will employ various strategies and tactics to overcome past market barriers and to deliver programs and services aligned to support the Strategic Plan's three existing residential sector goals listed above by encouraging adoption of economically viable energy efficiency technologies, practices, and services.56

The remainder of the utilities' proposed residential portfolio is comprised of Local Utility and Third Party residential programs. In their July 2, 2009 re-filed applications, the utilities proposed 26 Local Utility and Third Party programs. In general, these proposed programs either support the statewide residential program by addressing local issues unique to a utility service territory, or are programs with less statewide application such as innovative small-scale programs, and programs that address market characteristics specific to that territory.

Improving the energy efficiency of all households is necessary to achieve the target outcome for the 2020 existing residential Strategic Plan goals. Both renters and owners are represented in the 13 million home figure cited within the Strategic Plan although the majority are owners. Because renters and owners have different levels of control over the structures they live in and the appliances which influence energy consumption, the range of applicable energy efficiency programs differs. Both segments of the residential sector are well covered by the programs proposed by utilities in this program cycle and both must receive comprehensive energy efficiency upgrades.

Both types of households can also be characterized by income level. We have already adopted a Low Income Energy Efficiency (LIEE) portfolio for households at or below 200% of the federal poverty guidelines. We recognize that those households who are lower income but do not qualify for assistance are underserved and will require greater focus from the state's many energy efficiency resources.57

As noted above, the new California SPREE will consist of seven major subprograms. We discuss three of the subprograms below.58

The Home Energy Efficiency Survey (HEES) Program will offer statewide innovative initiatives to reverse the growth of plug loads and other energy consumption through behavioral solutions and, as warranted, DSM integration opportunities through energy surveys. The HEES Program will be used to reach out to customers in multiple languages through different delivery channels to perform a variety of energy surveys. The program will provide survey results to enable participants to understand how their energy use varies throughout the year and how their household compares with similar households. The HEES program will be available to both homeowners and renters. A multi-language approach will enhance the program's ability to reach California's diverse culture and provides efficiency recommendations based on a whole-house system approach. Additionally, HEES will provide information and referrals to other energy efficiency programs, water conservation efforts, demand response and low-income programs, as applicable.

A second subprogram in SPREE will be the Home Energy Efficiency Rebate (HEER) Program. HEER will help residents pay for the costs of comprehensive energy efficiency measures, including whole house solutions, plug load efficiency, performance standards, and integration opportunities with local government and DSM. HEER will offer consumers rebates for energy-efficient choices when purchasing and installing household appliances and equipment. It will offer customers educational materials on energy efficiency options, rebates, and other incentive offerings, the correct use of products, and guide customers toward exploring other DSM opportunities. In addition to a statewide on-line rebate application process, the program will offer immediate point-of-sale rebates for many measures at the retailer's cash register.

A third non-lighting subprogram in California SPREE will be the on-going Appliance Recycling Program (ARP). ARP picks up operable but inefficient appliances from residential dwellings and businesses and prevents their continued operation by recycling them in an environmentally safe manner. In accordance with the Strategic Plan, this program advances plug load efficiency, and effective decision making to increase demand for high efficiency products.

Each utility plans to begin a local comprehensive Whole House Performance Program (WHPP). WHPP will provide incentives, marketing, contractor field support, and quality assurance to demonstrate the practicality of building the infrastructure and market for comprehensive home retrofits. Utilities propose to refine and expand this offering to yield substantial new long-term home energy savings and eliminate lost opportunities in existing homes to the maximum extent possible. WHPP will include close coordination with program activities outside of traditional utility programs including a streamlined interface with municipal financing options (AB 811, Mello Roos, PACE Bonds or other) and home efficiency retrofit efforts funded by ARRA (federal stimulus) monies.

Also among the Local Utility and Third Party Programs is SCE's proposed On-line Buyer's Guide (OBG). Its goal is to provide SCE's residential customers with one web-based resource for information and tools to overcome market barriers that inhibit the purchase of energy efficient products and program participation. The guide will provide an overview on products by category including appliances, HVAC, lighting, refrigerators. The guide will link with other online energy efficiency resources including customer rebate options.

NRDC and LGSEC state that the statewide HEES program must clearly inform customers which surveys are available to them, as well as cross-market survey results with the various statewide and third party programs available. SCE responded by clarifying that on-line and mail in surveys will be universally available while the availability of phone and in-person surveys would be unique in each service territory. SCE further clarified that survey results from the HEES program would direct participants to statewide incentive programs such as the WHPP.

TURN proposes ending the long-running ARP. It argues that EM&V results indicate that most refrigerators being replaced are early retirements of primary appliances and not the secondary "dinosaur fridges" described in the program logic. TURN also argues that utilities overstate expected savings from the program and that major market participants such as Lowe's, Home Depot, and Sears currently provide free pickup when delivering new models, sometimes with the same contractor as the utilities' ARP program. SCE cites numerous evaluation studies to demonstrate that the program is operating effectively.

The June 9, 2009 Ruling sought additional party input regarding the utilities' residential portfolio. The Ruling asked parties if the scope of utility-proposed residential programs should be expanded beyond the small-scale "home performance" programs that each utility proposes to offer as a local utility program to also include a "prescriptive whole house retrofit" program. Specifically, parties were asked about an Energy Division "Straw Proposal" at a workshop held June 11, 200959 for a "prescriptive program" to be added to the utilities proposed Statewide Residential Program. The Straw Proposal assumes rapid changes in the residential market since the design of the utility statewide residential program in December 2008 (for example, the addition of millions of federal dollars to local governments for energy projects and efforts to develop regional financing programs through AB 811 or Mello-Roos authorizing legislation) could be leveraged to enhance residential programs.

The Straw Proposal suggests the addition of a prescriptive "whole house" program modeled after the proposed U.S. DOE Retrofit for Energy and Environmental Performance (REEP) program design within H.R. 2454, The American Clean Energy and Security Act of 2009, (Waxman/Markey) currently being considered in Congress. The Straw Proposal also asks questions about how many homes to target during this program cycle, the proper role for utilities in facilitating the comprehensive retrofit market, and the appropriateness of the TRC test for approving and evaluating market transformation programs.

NRDC supports the concept, stating that comprehensive residential retrofits of all of California's homes are necessary to address the energy and climate challenges California faces. NRDC suggests that a prescriptive utility program should utilize existing rating and labeling systems such as Home Performance with ENERGY STAR and California Home Energy Rating System (HERS II).

CBPCA comments that a prescriptive approach is an important and necessary addition to the utilities' WHPP in order to transform the market and bring contractors into the industry. CBPCA suggests that the addition of ARRA funds and AB 811 financing districts to the market could help greatly to facilitate the Strategic Plan targets. CBPCA offers that with these market additions, the remaining roles are to perform the actual delivery, quality assurance, and verification of savings, which are roles already familiar to utilities. Also, given the Strategic Plan target of retrofitting 13 million homes by 2020, CBPCA suggests an interim milestone of retrofitting 1% of California homes by 2011.

SCE, SDG&E, and SoCalGas do not support the Straw Proposal, and assert that the proposed utility Statewide Residential Program already "...provides a thoughtful approach to developing the market and consumer awareness for comprehensive measures."60 Additionally, SCE states that, "(i)n the event that CHPP (proposed Whole House Performance Program) achieves more traction in the next program cycle, SCE will have the opportunity to shift funds into CHPP from lesser-performing programs."61

PG&E does not indicate support or opposition to the Straw Proposal, but offers comments that "(a) well-designed, properly staged prescriptive approach can start moving customers and contractors toward a more holistic systems approach to residential retrofit projects." PG&E indicates a willingness to incorporate a prescriptive element as suggested in the Straw Proposal to its Residential portfolio. Furthermore, PG&E offers to organize and host the first of a series of comprehensive home performance stakeholder meetings.

5.1.2. Discussion

The residential energy efficiency market has traditionally been difficult to penetrate deeply. The Strategic Plan endorses strategies to achieve deeper savings and to achieve specific targets in the residential sector; i.e., a 40% reduction in energy purchases from all homes by 2020. This target can only be achieved by moving toward comprehensive whole house retrofits, which is a significant departure from relying on massive single measure rebate programs such as a few light bulbs now, new high-efficiency windows later, a new high-efficiency refrigerator some other year, and a high-efficiency clothes or dish washer yet another year, with each incremental measure the subject of separate marketing, delivery, and program administrative costs. We expect the utilities in this the 2010 - 2012 program cycle to transition from reliance on single measure incentive programs to implementation of an approach which incentivizes comprehensive savings and leverages creative financing.

We recognize and commend the effort utilities have expended to comply with our directives by balancing projected savings achievements with support for the market transformation targets of the Strategic Plan in their proposed Statewide Residential Program. However, the current design is a program offering a comprehensive menu of efficiency measure rebates, without a strong incentive for customers to participate in a comprehensive manner. There must be offered a strong reason for customers (other than a few early adopters) to participate in deep and comprehensive levels of efficiency while reducing the expenses of multiple program offerings and participation over many years if we are to achieve the Strategic Plan targets and to realize our other energy and climate goals.

We see evidence of an unprecedented opportunity to quickly re-shape key portions of the proposed statewide Residential portfolio to support the comprehensive approach we find is needed. We also see the opportunity to leverage this approach to market transformation with the CEC.62 We applaud the good judgment of the CEC in focusing the majority of SEP funding on building retrofit efforts. Together, our two agencies can realize our shared goals for market transformation in the residential sector by addressing the market structure, financing, outreach, and education in a coordinated manner with a diverse pool of resources. We thus approve the California Statewide Program for Residential Energy Efficiency (SPREE) and the local utility and third party programs as proposed with the modifications indicated below.

We direct utilities to provide a tiered suite of home retrofit options. This will include inserting a Prescriptive Whole House Retrofit Program (Prescriptive Program) in the California SPREE and small adjustments to the proposed local utility Whole House Performance Program (WHPP) including appropriate expansion. We agree with the many parties who identify coordination of the Prescriptive Program63 with the WHPP as critical to market transformation. To develop details for this prescriptive program addition and to make minor adjustments to the WHPP program design or size to maximize coordination we direct the utilities to organize and jointly host stakeholder meetings that includes Energy Division staff and consultants, the CEC, local governments and appropriate trade associations.64

This discussion shall assist the utilities to develop the design and implementation details for a statewide Prescriptive Program and, coordinate adjustments to each utility's Whole House Performance Program or other residential subprograms. Based on the stakeholder group efforts, the utilities shall jointly submit a program implementation plan by advice letter no later than December 15, 2009. Funding for the Prescriptive Program addition and expanding the WHPP is authorized at $100 million statewide. This approved subprogram budget shall include all administrative, marketing, workforce education, and EM&V expenditures associated with the subprogram. Funding will be allocated among utilities based on the ratios EM&V invoices are paid: PG&E: 46% SCE: 33% SDG&E: 13% SoCalGas: 8%.

Following approval of the advice letter, the utilities shall continue to convene stakeholder meetings no less than twice a year at different locations around the state to review implementation progress on SPREE, WHPP, the Prescriptive Program and other elements of the residential sector retrofit effort that are key to implementation of the Strategic Plan, and to identify program improvements or enhancements.

As recommended by parties, we will require the utilities' suite of retrofit programs including the new Prescriptive Whole House Retrofit program and their Whole House Performance Program (the Whole House Programs) to embrace the following structural elements and direct that the advice letter address each of these items. The Whole House Programs shall seek to drive the market to retrofit at least 1% of California homes in the utility service areas to at least 20% annual savings by the end of this program cycle (i.e., December 2012). The utilities shall provide a more attractive incentive level for the Whole House Performance Program than for the Prescriptive Whole House Retrofit Program in a consistent incentive structure. The Whole House Programs shall leverage ARRA funding (State Energy Program funds, federal efficiency tax credits, and additional appliance rebates), shall be designed to be compatible with municipal financing options (AB 811, Mello Roos, PACE Bonds or other), and shall fulfill the role of delivering energy consumption reductions in coordination with the CEC's anticipated ARRA-funded California Comprehensive Residential Building Retrofit Program. The Whole House Programs shall support pre installation assessments and post installation verification consistent with the California HERS Program.  The Whole House Programs shall establish approaches to coordinate with the CEC HERS Providers regarding training and certification of HERS raters and quality assurance. The Whole House Programs shall establish measures to insure that installers are well qualified, that building permits are pulled on every job that receives incentives, and that installing contractors comply with state contracting laws. We are concerned that there could be some consumer confusion in understanding the unequal precision and degree of home-specific analysis and recommendations associated with the spectrum of efficiency potential identification services that will be available in the residential sector. For this reason, we direct utilities to eliminate the provision of on-site residential "audits" within the HEES (survey) program. Commercial or industrial on-site audits are not affected by this direction. Most of the utilities already opt for phone, mail, or on-line interactions to provide home energy use survey information due to their lower cost. To enable consumers to better understand these distinctions, we clarify that these remote interactions shall not be referred to as "audits."65 Audits typically refer to a robust on-site diagnostic study of the unique efficiency opportunities of a building and are expected to be performed by a highly-trained and perhaps certified practitioner. Moreover, given the expense of such on-site analyses, these should be clearly named and distinguished from "surveys" and reserved for programs targeting more comprehensive levels of energy improvements. The HEES program should be structured to convey its survey findings in a way that directs participants toward applicable residential efficiency retrofit, solar, and demand response programs that facilitate consumers taking the more comprehensive actions we seek.

Turning now to other elements in the Residential portion of the utilities' proposed portfolios, we commend SCE in their development of the innovative On-line Buyer's Guide (OBG) program. We approve the implementation plan and budget request with several modifications. SCE shall:

· Include information about the California Solar Initiative and other DSM options on the OBG website.

· Co-brand with the new energy efficiency brand and link to the new energy efficiency web portal once both are operational.

· Provide a link to the Low Income Energy Efficiency webpage.

· Link the On-line Buyer's Guide to the statewide Marketing and Outreach website.

We direct all utilities to implement an on-line buyer's guide using SCE's program as a model. Each utility shall have a working on-line buyer's guide by end of this program cycle in anticipation of its rollout as a statewide program in the post 2012 program cycle.

Regarding the Appliance Recycling Program (ARP), DRA/TURN and SCE disagree about whether the market for used appliances has been transformed such that utility incentives are not needed in their current form. We find the evidence inconclusive. We rely on the Energy Division and its contractors to perform EM&V studies and for the utilities to use the studies' findings in program administration and funding decisions. We will continue to support the removal and destruction of less efficient major appliances until EM&V studies indicate they are no longer needed or need to be modified. Preliminary EM&V results for the 2006-2008 Appliance Recycling Program will become available before January 2010. Once available, we direct the utilities to review closely the findings and file an advice letter within ninety days of availability of the preliminary evaluation report to propose any changes to the ARP program.

We approve the proposed Lighting Programs with some modifications described below. Most significantly, we require that the utilities reduce funding levels for the Basic CFL Program, and in PG&E's require greater funding for the Advanced Lighting Program.

Table 11-Proposed and Approved Lighting Program Budgets

Basic CFL Program Funding

Utility

Proposed - July 2009 ($ millions)

Authorized ($ millions)

Reduction (%)

Reduction ($ millions)

PG&E

$60

$30

50%

$30

SCE

$32

$32

0%

$0

SDG&E

$16

$16

0%

$0

TOTAL

$108

$78

28%

$30

Advanced Lighting Program Funding

Utility

Proposed - July 2009 ($ millions)

Authorized ($ millions)

Increase (%)

Increase ($ millions)

PG&E

$22

$33

50%

$11

SCE

$45

$45

0%

$0

SDG&E

$11

$11

0%

$0

TOTAL

$78

$89

14%

$11

The Strategic Plan at 11 sets forth the Commission's vision for the lighting market and future utility lighting programs: "The residential lighting industry will undergo a substantial transformation through the deployment of high-efficiency and high-performance lighting technologies supported by state and national codes and standards. Utilities will begin to phase traditional mass market CFL bulb promotions and giveaways out of program portfolios and shift focus toward new lighting technologies and other innovative programs that focus on lasting energy savings and improved consumer uptake."

The utilities' lighting programs represent some of the longest running and most extensive energy efficiency efforts in the country. Relatively low-cost and easy-to-capture lighting savings have tended to constitute the majority share of utility portfolio spending and savings achievements over past program cycles. The backdrop for standard utility lighting programs, however, has shifted significantly in recent years. Recent studies show that, both in California and nationwide, Compact Florescent Light (CFL) availability has been widely expanded, bulb quality has improved, costs have declined, and sales have increased dramatically.66

State and national legislation addressing lighting efficiency further contributes to a changed context for ratepayer-funded lighting programs. The California Lighting Efficiency and Toxics Reduction Act of 2007 (Huffman, AB 1109) sets stringent standards for general purpose lighting sold in California, applying to indoor residential, indoor commercial and outdoor lighting technologies. Specifically the bill directs the CEC to adopt minimum energy efficiency standards for all general purpose lights in order to reduce average indoor residential lighting energy by not less than 50%, relative to 2007 levels. The 2008 Title 20 standards adopted by the CEC, under which AB 1109's general purpose lighting standards will be implemented, specify that the general service lighting standards will be fully phased-in by January 1, 2013, coinciding with the completion of the 2010-2012 program cycle.67 At the national level, federal lighting standards under the 2007 Energy Independence and Security Act (H.R. 6) mirror those in AB 1109, but lag one year behind the schedule set in California.

The Commission, the utilities, and other parties recognized these trends in the Strategic Plan process. D.07-10-032 at 22 discusses market transformation as it pertains to the lighting market, stating: "Short-term programs such as the replacement of incandescent light bulbs with compact fluorescent light bulbs must be accompanied by programs to encourage new technologies in lighting, consumer education on the benefits of energy efficient lighting and conservation, and advocacy for higher codes and standards for lighting." The Strategic Plan articulates a number of strategies to advance high performance residential lighting, including a coordinated phase out of utility incentives for basic CFLs.

In this section, we review the proposed residential lighting programs and the degree to which they respond to direction in the Strategic Plan and recent trends exhibited within the market for CFLs and other forms of efficient lighting.

5.2.1. Utility Proposals

Each utility's proposed effort in residential lighting has separate budgets for a Residential Lighting Incentive Program for Basic CFLs, a Residential Advanced Consumer Lighting Program, and the Statewide Lighting Market Transformation Program.

The proposed Residential Lighting Incentive Program for Basic CFLs (Basic CFL Program) is an upstream discounting program for Energy Star-labeled lamps of single brightness up to 30 watts. The utility proposal reflects basic continuity with the 2006 -2008 portfolio, utilizing a manufacturer wholesale buy-down mechanism and incentive levels identical to those offered since 2006. According to the Program Implementation Plans submitted by the utilities, the proposed per bulb incentives for the Basic CFL Program are as follows:

Lighting Product

Incandescent Equivalent

Incentive

Basic CFL - 0 to 799 Lumens (up to 15 W)

40 W, 60W

$1

Basic CFL - 800 to 1,099 Lumens (15 to 25 W)

75 W

$1.25

Basic CFL - 1,100 to 1,599 Lumens (25 to 30 W)

100 W

$1.75

Basic CFL - 1,600 Lumens or greater (above 30W)

150+ W

$2

The utilities propose to distribute basic CFLs to over 370 retailers at more than 2,700 store locations, targeting their efforts towards independent retailers, deep discount stores, and small chains, which exhibit the lowest rates of free-ridership. SCE proposes to fund the Basic CFL Program at $32 million, PG&E proposes $60 million and SDG&E proposes $16 million.

The Advanced Consumer Lighting Program aims to shift consumer behavior toward the use of high efficiency specialty products and away from incandescent specialty products. This program targets lighting products other than standard, screw-in CFLs of less than 30 watts, including dimmable, three-way, and specialty CFLs, so-called "super" CFLs, light emitting diodes (LEDs), halogen, and other lighting products.

The Advanced Consumer Lighting Program proposes the same incentive levels as the 2006-2008 budget cycle (with the exception of certain LED incentives, which are set to increase). As with the basic CFL program, the program employs upstream rebates (for simple-to-install products), though also utilizes midstream rebates for products typically purchased by lighting contractors. According to the Program Implementation Plans submitted byt the utilities, the proposed per bulb incentives for the Basic CFL program are as follows:

Lighting Product

Incentive

Specialty CFL Screw-in - 1 to 799 Lumens (pre-incentive adder)

$1

Specialty CFL Screw-in - 800 to 1,099 Lumens (pre-incentive adder)

$1.25

Specialty CFL Screw-in - 1,100 to 1,599 Lumens (pre-incentive adder)

$1.75

Specialty CFL Screw-in - 1,600 Lumens or greater (pre-incentive adder)

$2

Specialty CFL with Incentive Adder - Incentive Above plus:

$1.50

Interior Hardwired Fluorescent or LED Fixture - < 1,100 Lumens

$5

Interior Hardwired Fluorescent or LED Fixture - 1,100 Lumens or greater

$10

Exterior Hardwired CFL or LED Fixture - < 1,100 Lumens

$5

Exterior Hardwired CFL or LED Fixture - 1,100 Lumens or greater

$10

LED Screw-in - 800 to 1,099 Lumens

$5

LED Screw-in - 1,100 Lumens or greater

$10

Fluorescent Torchiere Floor Lamp

$10

Fluorescent or LED Table, Desk or Floor Lamp

$5

LED Night Light

$0.50

Electroluminescent, Fluorescent or Neon Night Light

$0.30

LED Holiday Lights per LED

$0.05

LED Task or Accent Light

$1

Other variations of fluorescent lighting (ex. cold cathode and induction)

Unspecified

Screw-in Halogen Lamps

Unspecified

The proposed Advanced Consumer Lighting Program includes several subprograms, such as the Advanced LED Ambient Lighting subprogram. According to the utilities' proposals, quality assurance of LED ambient lighting will abide by guidance put forth by DOE and the EPA.

SCE proposes to fund this program at $45 million, PG&E proposes $22.1 million and SDG&E proposes $11 million. Total spending for the Advanced Lighting program totals $78 million across the utilities over three years.

The proposed Statewide Lighting Market Transformation (LMT) Program would establish a statewide, integrated process for the development and testing of market transformation strategies for various lighting technologies. Program activities would include market research, coordination, and educational outreach designed to inform market actors about lighting technology options. Total funding for the program is proposed at $1,512,473. The program is designated as a non-resource program.

The Statewide LMT Program is proposed to be carried out through three subprograms: a Lighting Technology Advancement Subprogram; a Lighting Education and Information Subprogram; and a Lighting Market Transformation Subprogram. The Lighting Technology Advancement Subprogram would entail coordination and leveraging with other lighting activities and programs at the federal, state and local level. The Lighting Education and Information Subprogram would offer information to market actors on product choices, installation practices and lighting disposal methods. The Lighting Market Transformation Subprogram would establish technology roadmaps and processes to define how and when to introduce and phase out various lighting technologies.

Under the proposal, utility staff would lead many of the tasks specified in the proposed Statewide LMT Program. Of these tasks, the utilities propose undertaking the task of clearly defining "market transformation" by reviewing research and other data. Also, the Statewide LMT Program proposal includes the development of "appropriate metrics and guidelines for determining when market transformation has occurred and publicly-funded intervention is no longer appropriate, so as to define an end-point for strategies and set the course for new programs and goals."68

Table 12 -- Statewide Lighting Market Transformation Program

Utility

Total Administrative Cost

Total Direct Implementation Cost

Total Budget

PG&E

$308,473

$150,000

$458,473

SCE

$1,054,000

$0

$1,054,000

SDG&E

$0**

$0**

$0**

TOTAL

$1,362,473

$150,000

$1,512,473

** Included as part of Statewide Residential Program

The Statewide LMT Program would be carried out in coordination with the residential lighting programs mentioned above. According to PG&E's proposal, the above costs do not reflect other program budgets that would be leveraged with this program, including the Emerging Technologies Program and Codes & Standards.

5.2.2. Party Comments

There has been extensive comment and record development on the utilities' proposed portfolio of residential lighting programs. Party comments on lighting entail a range of interrelated concerns described below.

Some parties argue that funding for basic CFLs should be dramatically scaled back for this program cycle, or at the extreme, eliminated. In a white paper submitted as part of its April 23, 2009 comments to the utilities' March 2, 2009 Revised Filings, TURN outlined several arguments to support its view that the heavy reliance on basic CFLs exhibited by utilities' portfolios represents an increasingly unproductive use of ratepayer funding.69 In particular, TURN asserts that utility reliance on CFLs whose gross savings decay quickly and exhibit high levels of free-ridership renders it nearly impossible to grow energy efficiency savings over time. TURN shows that utilities intend to hold relatively steady with lighting-dominated portfolios, with lighting elements comprising 54% of total net GWh savings and 46% total net MW savings.

TURN argues that the utilities can and should move beyond CFLs in their portfolios. Citing data from recent surveys by KEMA, TURN argues that the potential identified for CFLs has been largely captured over past program cycles and trends in market transformation. TURN also argues that unwarranted subsidies create market distortions, and presents information that California consumers pay more for utility-subsidized CFLs than customers in comparable national retail stores which do not rely on utility subsidies.70 Furthermore, TURN claims that pending standards at the state and federal levels will ensure that remaining CFL potential will be captured irrespective of ratepayer funding.

TURN argues that rather than funding CFLs at levels comparable to the past program cycle, the utilities should focus on other high-efficiency lighting and other key end-uses such as HVAC, refrigeration, motors, and thermal integrity improvements. To that end, they argue that the utilities should pursue an exit strategy for the current program which would entail a near-term phase-out of subsidies for basic CFLs. TURN recommends, based on current levels of CFL penetration and remaining high use sockets to which CFLs are applicable, that CFLs covered in the next round of upstream incentives should not exceed 28 million bulbs. This 28 million is 10 million less than the 38 million CFLs PGE proposed to rebate in 2009-2011, and only about one third of the three year amount proposed by the three electric utilities.71

DRA agrees that the utilities are misguided in their strategy to further ramp-up sales of subsidized basic CFLs in a transformed market. DRA's supporting arguments echo those of TURN's described above, and they present additional analysis to support their points. Noting that approximately 42 million basic CFLs purchased through utility programs are currently in storage in CA residences,72 DRA suggests that the remaining sockets occupied by incandescent bulbs face barriers to CFL saturation unlikely to be addressed by a program fundamentally designed to address price barriers and little else. Therefore, DRA asserts that upstream CFL programs focused solely on price barriers to CFL uptake represent an increasingly poor use of ratepayer funding.73

DRA also warns that the continued sale of subsidized CFLs in a transformed market may result in market distortions ultimately damaging to the energy efficiency cause, including unwarranted support of inefficient or low quality producers, and increasing the real price of bulbs faced by California ratepayers. DRA suggests redirecting Basic CFL Program funding toward the Advanced Lighting Program. To address CFL potential yet untapped, DRA encourages greater emphasis on understanding customer behavior and remaining barriers to uptake.

LGSEC and WEM also agree that fewer resources should be devoted to basic CFLs.

NRDC maintains that basic CFL incentive programs should continue. It argues that subsidies are justified so long as cost-effective savings are achieved. NRDC also argues that the basic CFL market has not yet been transformed. Citing the same data as DRA and TURN, NRDC points out that that only 21% of California residential sockets have CFLs. NRDC also touts the success of prior utility lighting programs, citing the significant increase in CFL use in the past decade. NRDC suggests, however, a reassessment of the current incentive structure and questions the vast differences between the utilities' proposed budgets, including why the spending ratio among the residential lighting programs varies so greatly among utilities.

In reply comments, the utilities agree with NRDC that the market for basic CFLs has not yet been transformed, as evidenced by remaining potential and demand for their programs. The utilities plan to rely on market data from manufacturers and retailers to determine when subsidization is no longer needed. Additionally, they cite past program success in upstream lighting programs and remaining market potential to justify a relatively unchanged approach for basic CFLs in this program cycle. Also, the utilities claim that incentives are needed to prepare California for the enactment of new lighting codes set forth in AB 1109. Under their interpretation of the Strategic Plan, basic CFL phase out begins in 2009 and continues through 2020.

Despite differences in positions regarding the degree of market transformation which has occurred within the market for basic CFLs, parties unanimously recognize the limitations of current CFLs and support the objectives of the Advanced Consumer Lighting Program as a vehicle to spur further market transformation in the lighting sector.

In its "Next Generation Lighting" submission, TURN discusses several new technologies in the lighting industry and their market availability. Increasingly available through large retailers, non-standard CFLs are dimmable and offer better lighting and lower mercury content. LEDs are highly efficient, do not require mercury, and are often viewed as "a more likely future successor to incandescent bulbs than CFLs."74 TURN also states that the market for T-8 lamps and high intensity discharge lighting is growing. TURN urges the utilities to work with manufacturers to advance the availability and affordability of advanced lighting products.

NRDC recommends further expanding the Advanced Lighting Programs, yet cautions that certain lighting products are not ready for widespread use. Citing past experience with CFLs, NRDC warns that there may be risks associated with bringing a product to market too soon. In addition to emergent "Super CFLs" and LEDs, NRDC suggests the utilities expand incentives to existing specialty products that are less efficient than CFLs yet more efficient than the traditional incandescent lamp, including next generation incandescent lamps and halogen bulbs. These alternative advanced lighting products may spur increased customer use by addressing concerns held by would-be CFL users, including light quality, performance and mercury content, all of which have been documented barriers to further uptake of basic CFLs in many applications.

The utilities indicate a willingness to scale up the advanced lighting program, contingent upon innovation and product readiness.

Parties also offered comments on aspects of program design relating to the utilities' lighting efforts. DRA suggests that the upstream lighting program model utilized over past program cycles for basic CFLs be modified prior to its use in promoting specialty lighting products and advanced lighting technologies. DRA urges the utilities to exercise greater control over the upstream lighting program strategy (rather than the CFL approach of almost complete deference to manufacturers), specifically in the areas of direct sales and marketing, retailer selection, recycling programs and program design. DRA recommends further that the utilities investigate the use of an auction, by which subsidies would be awarded to optimal bidders. Such a model, DRA suggests, would leverage market signals from manufacturers and retailers to determine optimal quantities and pricing for a specific product.

Both DRA and TURN recommend tighter utility control over bulb quality and better efforts to target certain customer segments, with a special focus on hard-to-reach customers.

NRDC supports the current upstream lighting program design, believing it affords utilities with the ability to respond to market data and adjust programs accordingly. According to NRDC, the program fosters competition and innovation while enabling the utilities to respond to market changes accordingly. NRDC does suggest targeting specific customers, such as those who are not CFL users. Additionally, NRDC recommends including consumer labels with energy efficiency information on lighting products sold through utility programs.

DRA recommends that the proposed Statewide LMT Program be reconceived in the context of the larger lighting market and that parties other than the utilities take on roles in carrying out the Statewide LMT Program. DRA suggests that the Strategic Plan's objectives for market transformation would be better achieved by a broader entity than the utilities themselves. Similarly, TURN suggests more information is needed on how the utilities' Statewide LMT Program relates to other utility lighting program efforts and budget. In particular, TURN states that a marketing and implementation budget break-down is needed.

Finally, both DRA and TURN suggest the utility approach to realizing lighting efficiency gains is lacking a systems-based approach, which would advance deeper energy savings by encouraging fixture replacements and lighting system retrofit improvements.

A number of parties commented on CFL mercury content and related disposal and recycling concerns. Both the Basic CFL Program and the Advanced Consumer Lighting Program include efforts to support customer awareness for proper CFL disposal. To comply with the environmental safety goals on CFLs outlined in the Strategic Plan, the utilities set forth plans to work with the California Environmental Protection Agency's Department of Toxic Substances Control to expand CFL disposal infrastructure and educate consumers about proper disposal methods.

As TURN and DRA point out, the 5 mg. per CFL limit proposed by the utilities for the basic CFL program is the same as that required in AB 1109. According to TURN, "The utilities' role in this market is too important for them to endorse what is soon to become the status quo, the AB 1109 mercury limit."75 For this reason, TURN and DRA suggests the adoption of a 3 mg. limit for CFLs that receive ratepayer subsidies, in line with the utilities' Super CFL Program and current market trends.

Additionally, DRA and TURN recommend that the utilities share the cost of CFL recycling and disposal. Specifically, TURN recommends that manufacturers and retailers who participate in ratepayer-funded CFL programs must agree to partake in recycling and bulb disposal programs. CCSF and LGSEC support these recommendations, decrying the current system which holds local governments to be ultimately responsible for bulb disposal and waste.

While NRDC agrees that bulbs with lower mercury content levels should be incentivized preferentially, NRDC does not support the view that the cost of CFL disposal should be rolled into the utilities' programs. Instead, utilities should contribute to education and bulb disposal costs, with lighting manufacturers bearing the majority of such costs and producing bulbs with lower mercury content levels.

5.2.3. Discussion

While opinions vary widely on the appropriate program scope and strategies to address lighting within the utility portfolios, there are distinct points of agreement and common facts to form the basis of our decision.

Lighting efficiency offers a vast, low-cost energy resource for California. There are many opportunities yet untapped, but only if California can craft a comprehensive and innovative approach to unlocking them. It appears quite clear, from rising free-ridership values and the data on household CFL saturation, that much of the low-hanging fruit has been captured over prior program cycles.

Market data suggests that the CFL market today is significantly progressed beyond where it was at the time of the last round of utility portfolio approvals by this Commission. In contrast to market circumstances only a few years ago, CFLs are now both widely available in retail stores and reasonably priced. Available data indicate that relatively high levels of CFL sales are being recorded throughout the U.S., even in the absence of the high levels of utility-ratepayer subsidies characteristic to California.

In addition we cannot ignore that impending standards which will take hold over the course of this program cycle are likely to serve as a backstop to many lighting savings achieved to date and help to realize remaining potential at no direct ratepayer cost.

The utilities cite past program success in upstream lighting programs and remaining market potential to justify a relatively unchanged approach for basic CFLs within this program cycle. In terms of incentive levels and overall funding, the proposed program is by and large a continuation of what the utilities have implemented over 2006 -2008.

While past efforts by our utilities are to be credited for much of this favorable market movement, it does not follow that programs should continue unchanged as the market moves. We agree with DRA, TURN and NRDC that, in concert, the federal stimulus funding, impending standards, and other market forces warrant an adapted response to capturing further lighting potential. The need to achieve major incremental efficiency gains is too urgent and the costs too great to continue to sink ratepayer dollars into outdated programs. California utilities should continue leading the effort to push the frontier of efficiency opportunity and program execution.

Several other regions with leading edge efficiency programs have also recognized this fact and are similarly shifting utility ratepayer funds out of basic CFL programs to other lighting and non-lighting energy efficiency activities. This shift is motivated by the fact that ratepayer dollars are better spent on products that align with energy efficiency goals yet have not achieved widespread recognition.

The Connecticut Department of Public Utility Control is shifting incentives towards specialty bulbs and planning to eliminate upstream incentives for common CFLs by 2010. The Northwest Energy Efficiency Alliance (NEEA) has dedicated less effort to the CFL market in light of the success of its previous work in the area. Similarly, the Northeast Efficiency Partnership (NEEP) recently recognized that its strategy regarding CFL lighting has to change, due to the success of its programs and changes in the market. California utilities should continue leading the effort to push the frontier of efficiency opportunity and program execution.

In addition, we agree with the concern raised by some parties that unwarranted price supports hinder market transformation. Keeping the market price for program CFLs artificially low represents a sink on ratepayer resources and can impair important competitive forces which help to improve lighting technologies over the near and long term.

To ensure their continued impact on California's lighting market, utility lighting programs must spur the availability of new and improved lighting products. With a new generation of lighting products on the rise, utility support is needed to capitalize on potential efficiency gains.

With standard CFLs fast becoming accepted in the market, the advent of new lighting standards makes the upcoming budget cycle an opportune time to initiate a phased reduction in basic CFL subsidies and scale up utility efforts on advanced lighting products.

5.2.3.1. Lighting Incentive Program Funding Levels

For the reasons set forth above, we find that the upcoming budget cycle should entail a strategic shift toward more advanced lighting technologies. To the greatest extent possible, basic CFL program dollars shall instead be geared toward the Advanced Consumer Lighting Program. We recognize that in the July 2009 filings, the utilities made some effort towards doing this and adjusted their budgets, reducing overall funding for the Basic CFL Program and increasing overall funding for the Advanced Lighting Consumer Program. We recognize and commend the effort the utilities have expended to comply with our directives.

Table 14-Proposed Funding Split between Basic CFLs and Specialty Lighting Products

UTILITY

PROGRAM

July 2009 filing ($ millions)

%

PG&E

Basic CFLs

$60 M

73%

Advanced Lighting

$22 M

27%

SCE

Basic CFLs

$32 M

42%

Advanced Lighting

$45 M

58%

SDG&E

Basic CFLs

$16 M

59%

Advanced Lighting

$11 M

41%

TOTAL

Basic CFLs

$104 M

57%

 

Advanced Lighting

$78 M

43%

Funding at the levels proposed stands in contrast to levels that parties advocate is warranted given the degree of market progress exhibited over the past several years. While much evidence suggests that funding levels for basic CFLs should be reduced significantly, a reasonable level of program support is needed during this program cycle in order to smooth the transition away from CFL-dominated portfolios.

Overall we are satisfied with the allocation of lighting dollars proposed among basic and advanced lighting technologies. However, in PG&E's case, we believe further adjustment is warranted to ensure adequate investment in next-generation lighting technologies and responsiveness to market progress in basic CFLs. For this reason, we require that PG&E reduce funding levels for the Basic CFL Program by 50%, and commensurately increase its funding for the Advanced Lighting Program by 50%.

The approved Basic CFL and Advanced Lighting Program budgets are shown below:

Table 15-Basic CFL Program Funding

Utility

Proposed - July 2009 ($ millions)

Authorized
($ millions)

Reduction (%)

Reduction
($ millions)

PG&E

$60

$30

50%

$30

SCE

$32

$25

0%

$0

SDG&E

$16

$16

0%

$0

TOTAL

$108

$78

28%

$30

Advanced Lighting Program Funding

Utility

Proposed - July 2009 ($ millions)

Authorized
($ millions)

Increase (%)

Increase
($ millions)

PG&E

$22

$33

50%

$11

SCE

$45

$45

0%

$0

SDG&E

$11

$11

0%

$0

TOTAL

$78

$89

14%

$11

While it remains within the utilities' discretion to optimize incentive levels and bulb quantities as necessary, we agree with NRDC that the utilities should reconsider relative incentive levels. A review of the utilities detailed filings, demonstrates that incentives for basic CFLs are set above the $1.00 level specified in the utilities' submitted Program Implementation Plans.76 Relative to national price data, the utilities planned incentives appear notably high. Given the state of the CFL market, we expect that program bulb sales would not be dramatically impacted if these incentive levels were to be reduced. We encourage the utilities to explore reductions to per bulb incentives for basic CFLs as a means of freeing up budget for more pressing needs and accommodating budget adjustments. We encourage the utilities to coordinate with other regions which have initiated careful and successful efforts to shift ratepayer funding out of basic CFLs.77

We recognize that over the past program cycle fund-shifting allowed that the utilities ultimate investment in lighting was nearly double what was anticipated at the time of portfolio approval. In order to achieve the overarching objectives of this decision, we will not permit fund shifting into the Basic CFL program during the 2010 to 2012 period, and we will allow the utilities to direct any amount of Basic CFL Program funding into Advanced Consumer Lighting Programs. We impose these fund-shifting rules notwithstanding any other fund-shifting rules required by this decision for 2010-2012.

We agree with NRDC that certain customer concerns regarding basic CFLs may be resolved through the promotion of next generation halogen and incandescent bulbs. However, current program proposals do not specify incentive levels for these lamp types, unlike other advanced lighting products. Utilities are hereby authorized to explore the incorporation of next generation halogen and incandescent bulbs in their programs and to use authorized program funds to subsidize these lamp types at incentive levels deemed appropriate in the context of the overall lighting programs.

We agree with DRA, that the utilities should incorporate lessons learned from the upstream lighting program model utilized over past program cycles for basic CFLs into their design of the same model with the Advanced Lighting Program. We expect that the utilities will exercise greater control over the upstream lighting program strategy, specifically in the areas of quality specification, incentive level design, marketing and display.

We are concerned about the relatively low installation rates associated with upstream lighting programs. Furthermore, we believe there is an opportunity to expand socket penetration leveraging significant number of bulbs which the Residential Metering Study finds remain in storage. Outreach and education efforts associated with the lighting program should focus on ensuring bulbs funded through upstream programs are installed reliably such that they generate new savings consistent with the intent of our public-purpose program. We direct the utilities to submit in their compliance filing an outreach campaign focused on getting these bulbs out of storage and into sockets.

We wholeheartedly agree with those parties who have suggested that the quality of bulbs promoted through utility programs is essential to the long-term success of CFLs in the marketplace. While we do not have enough information on record to direct in this decision specific quality standards for utility lighting programs, we expect this to be an area of focus in the Lighting Market Transformation activities described below.

5.2.3.2. Statewide Lighting Market Transformation (LMT) Program

We approve the utilities proposed budget for the Statewide LMT Program, unchanged.

We support the overall goal of promoting lighting market transformation, as set forth in the utility proposals for the Statewide Lighting Market Transformation (LMT) Program. However, the proposal requires more clarity as to the specific goals and milestones which will be accomplished. For these reasons, we direct that the utilities submit, at a minimum, the following information on an annual basis:

· Annual plans for lighting solutions to be implemented in each key market segment (residential, commercial, industrial, agriculture and exterior lighting).

· A prioritized list of key lighting technologies, systems and strategies that require LMT pipeline plans.

· New or revised LMT pipeline plans for key lighting technologies, with plans based on market data. LMT pipeline plans will identify funding, partnerships and needed coordination with the following Commission efforts: Workforce Education and Training, Codes and Standards, DSM Coordination and Integration, Marketing, Education and Outreach, Research and Technology and Local Governments.

· Status update on the design and development of at least one LMT pilot project for each market segment (residential, commercial, industrial, agriculture and exterior lighting). Each pilot should be used as a vehicle to test new technology and program delivery mechanisms. Status update should include information on each pilot and collaboration with other utility programs and public and private partnerships.

The utilities shall submit the above Statewide LMT Program information in a Report by June 1 of each year (beginning in 2010). The Statewide LMT Program information shall be submitted to the Energy Division and the service list.

We agree with DRA that a broad group of stakeholders should play a role in carrying out the activities specified in the Statewide LMT Program and related lighting market transformation efforts. Currently, various entities are undertaking the challenge of advancing California's lighting market, including Energy Star®, the Consortium for Energy Efficiency, the Program for Evaluation and Analysis of Residential Lighting (PEARL), the California Lighting Technology Center (CLTC), and the Energy Commission.

To create a vision for California's transformed lighting market in 2020, we direct Energy Division, as feasible, to create a Strategic Lighting Plan (SLP). The SLP will serve as an addendum to the Strategic Plan, and will include specific goals, strategies and milestones. Energy Division should seek to engage key actors and secure industry perspectives as necessary, through any combination or series of meetings and public workshops. We direct Energy Division to include lighting in the Strategic Action Plan Progress Report as discussed in section 12.

We expect that the Statewide LMT Program will work closely with Energy Division. We also expect the Statewide LMT program to offer periodic opportunities for expert, government agency and public input on plans, including pilot projects. Stakeholders engaged in the SLP discussions should be invited to participate in such meetings. The Statewide LMT Program, led by the utilities, should not serve as a venue for determining when market transformation has been achieved for a given technology, as this is a Commission responsibility.

      5.2.3.3. CFL Mercury Content and Recycling

With regard to CFL Mercury Content and Recycling, we reject DRA and TURN's recommendation to require that utilities lighting programs contribute to state CFL recycling and disposal efforts. There are a number of processes underway to consider and develop an effective and coordinated response to the problem of CFL recycling. We expect that the utilities will be engaged in designing an efficient outcome, and leverage their position in the marketplace to facilitate proper CFL handling and disposal. However, we find little value added in prejudging the outcome of those processes by requiring in this decision that such programs be funded through EE program budges.

Several major retailers have imposed limits on the mercury content of their CFL bulbs. In May 2007, WalMart announced that its suppliers had committed to mercury content that is substantially below the 5 mg. standard set by the National Electrical Manufacturers Association in early 2007. Similarly Ikea has imposed a 3 mg. mercury limit on the CFLs it sells, and several manufacturers make CFLs that contain less than 3 mg. of mercury.

As TURN and DRA point out, the 5 mg. per CFL limit proposed by the utilities for the basic CFL program is the same as that required in AB 1109. SCE, Ecology Action and NRDC raise concerns related to the quality of CFLs that have a 3 mg. mercury maximum, especially in relation to advanced lighting technologies which are the ones that need more market penetration. NRDC points out those potentially low quality bulbs could undermine the efficient lighting market. Both SCE and Ecology Action support the 3 mg. limit on bulbs with small to medium wattage. To the extent that utilities have a continuing role in affecting the market for basic CFLs, they should be striving to set the bar for quality and moving the market in a progressive direction. For this reason, we adopt a 3 mg. limit for basic medium screw base CFLs of 25 watts or less and a 5 mg. limit for bulbs of 25 watts or more that receive ratepayer subsidies.

We approve the utilities' proposed statewide commercial programs and the commercial subprograms with some modifications, discussed below. Most significantly, we require PG&E and SCE to increase their building benchmarking efforts and, to do so, we increase SCE's budget by $4.0 million.

Commercial buildings represent a significant energy efficiency savings opportunity: they account for 38 percent of the state's electricity use and over 25 percent of natural gas consumption.

The Strategic Plan at 30 sets forth the following vision for the commercial sector:

Commercial buildings will be put on a path to zero net energy (ZNE) by 2030 for all new and a substantial proportion of existing buildings. Innovative technologies and enhanced building design and operation practices will dramatically grow in use in the coming years through a combination of technology development, market pull, professional education, targeted financing and incentives, and codes and standards.

Achieving this vision will require increased use of innovative technologies, enhanced building design and operation practices through an integration of technology development, market pull, professional education, targeted financing and incentives, and codes and standards.78 The proposed commercial program implementation plans incorporate many Strategic Plan objectives while also presenting cost-effective sector portfolios. The implementation of the proposed commercial programs will provide the needed direction to drive forward commercial sector work on the Strategic Plan milestones, and reach proposed energy savings for existing commercial buildings in the 2010-2012 program cycle.

The following table contains the utility proposed budgets for all programs within the commercial portfolio.

Table 16-Proposed Commercial Program Budget and Savings

Commercial Statewide Programs

 

 

Budgets

kWh

KW

Therms

PG&E

$188,195,450

752,369,598

145,219

5,612,111

SCE

$231,606,000

919,105,562

182,951

0

SDG&E

$91,693,985

203,364,563

49,710

886,721

SCG

$26,156,661

0

0

17,806,497

Total

$537,652,096

1,874,839,722

377,880

24,305,329

 

Commercial Third Party Programs

 

 

Budgets

kWh

KW

Therms

PG&E

$137,025,667

333,270,751

58,443

3,922,145

SCE*

$105,621,486

228,550,209

45,478

0

SDG&E

$22,100,984

9,354,817

0

879,565

SCG

$55,603,764

0

0

453,180

Total

$320,351,900

571,175,777

103,921

5,254,890

 

Commercial Local Programs

 

 

Budgets

kWh

KW

Therms

PG&E

$0

0

0

0

SCE

$0

0

0

0

SDG&E

$67,235,094

141,461,679

31,082

5,725,284

SCG

$9,928,302

0

0

1,309,959

Total

$77,163,396

141,461,679

31,082

7,035,243

 

Total Sector Budgets/ Savings

$935,167,392

2,587,477,178

512,882

36,595,461

*Note: SCE's Sustainable Communities third party is located in the ZNE section.

The utility-proposed Commercial Energy Efficiency Program (CEEP) for existing commercial buildings is an integrated set of sub-programs that lays out a plan to both overcome traditional market barriers and achieve optimal energy management for existing commercial buildings. The CEEP includes three resource sub-programs (Calculated Incentives, Deemed Incentives, and Direct Install), and two non-resource subprograms (Continuous Energy Improvement (CEI) and Non-Residential Audits). All five sub-programs contain continued and new program components. The statewide program will be available to all commercial customers in the designated utility territory and will provide strategic energy planning, technical energy services such as audits, and financial services through rebates and incentives. The CEEP also targets integrated energy solutions required by the Strategic Plan, including: energy efficiency, distributed generation, and demand response.

SCE and PG&E have included three additional core sub programs in their application for statewide implementation: Energy Efficiency for Entertainment Centers, Private Schools and Colleges Program, and California Preschools Program. These sectors were identified based on the evaluation of the 2006-2008 commercial programs as areas with untapped savings potential. SDG&E/SoCalGas do not propose to offer these programs.

The utilities propose three key innovations within their proposed commercial sector programs: a) a robust, statewide, adaptive management structure; b) a new program element aimed at improving business commitment to energy efficiency as a business strategy (the Continuous Energy Improvement (CEI) sub-program); and c) increased emphasis on target markets as a program strategy.

5.3.1.1. Positions of Parties

In the June 9, 2009 Ruling, parties were asked to comment on the Energy Division proposal that "all IOU commercial building programs, including government partnership programs, should integrate the use of benchmarking tools and information into their functioning during the 2009-2011 period." The June 29, 2009 comments reflect a consensus among the parties with respect to benchmarking. SCE, CCSF, and PG&E agree the Energy Division proposal is justified and that baseline information is necessary to work towards the ZNE goals in the Strategic Plan and D-07-10-032. SCE notes benchmarking is an integral part of their Continuous Energy Improvement (CEI) sub program, and plans on focusing on government agencies because of their large building portfolios and energy loads. PG&E states that it has unique Automated Benchmarking software to help assess building energy performance. PG&E will continue to use the Pacific Energy Center and other local Building Owners and Managers Association (BOMA) facilities to provide free benchmarking training for commercial building owners and operators. This training will also be valuable for implementation of Assembly Bill (AB) 1103.79

SDG&E agrees with the other IOUs, and points out that the passage of AB 1103 will push benchmarking to become the standard if it is available to building operators via the U.S. Environmental Protection Agency (EPA) and utility interfaces. However, both SDG&E and LGSEC voice concern about resources to perform benchmarking coordination. NRDC also supports benchmarking and proposes integration between the benchmarking asset-value approach (calculated benchmarking of process and plug loads) and the operational approach (measured ratings of how the building is being used). Asset-value ratings currently do not exist for commercial buildings, but are being discussed as part of AB 1103 implementation. DRA and TURN concur with the overarching ED proposal on benchmarking but note that commercial buildings should be focusing on energy efficient retrofits.

5.3.1.2. Discussion

We approve the utilities' proposed statewide Commercial Program (CEEP) and subprograms. The proposed subprograms are existing programs that have been revised from the previous program cycle to be consistent across all four utilities, presenting a truly integrated statewide program. These programs incorporate key elements of the Strategic Plan such as Integrated DSM, work force training, and linkages to codes and standards programs.

While statewide programs further the goals of the Strategic Plan, there are two areas where program modification is needed in the forthcoming program cycle. The first area is the Direct Install subprogram in the statewide CEEP. Direct Install delivers free energy efficiency hardware retrofits, through third-party contractors, to reduce peak demand and energy savings for commercial customers with monthly demand under 100 kW. Third party contractors provide audits, install measures, and follow up with verification protocols. This contact between the third party contractor and customer presents an opportunity to offer and install more comprehensive measures than are currently offered.

The Direct Install measure is usually triggered by a high level audit, in which certain energy savings opportunities are provided at no cost to the customer. However, the audit may also reveal additional savings opportunities that are covered by another program, such as the On-Bill Financing Program and/or the Calculated and Deemed Savings commercial sub programs. Linkages between various sub-programs must be included in program planning, because success in one subprogram can lead to uptake of another subprogram and increased energy savings.

With many interacting programs, it is necessary to ensure that proper evaluation efforts and management structures are in place so that these opportunities are not lost, thereby maximizing the use of ratepayer funds. We direct the utilities to include in their updated Program Performance Metrics Advice Letter a description of the integrated program evaluation and management structures put in place to ensure linkages between subprograms to minimize lost opportunities.

Second, we require modifications to the utility commercial sector program to include benchmarking. Benchmarking "...is a beginning step in managing a building's energy cost, one that should motivate the building's owner or manager to take actions to improve the building's energy profile." Benchmarking is also mentioned in the CEI sub program implementation plan as a necessary first step in comparing progress between commercial buildings and against industry standards. Utilities have noted this data will be collected as part of the AB 1103 requirement to generate a benchmarking score for disclosure at point of sale/lease for building owners, as well as serve as a filter to inform their CEI sub program component of their statewide Commercial Program. Both SCE and PG&E will use U.S. EPA's ENERGY STAR Portfolio Manager as the main driver behind their benchmarking initiative.

While we recognize the utilities are working toward integration of benchmarking into their commercial programs, this component should be expanded to cover more buildings that are "touched" by the CEEP subprograms. We require the IOUs to benchmark all facilities that enter any of the CEEP sub-programs for services, similar to the directive in the local government partnerships section of this decision. In particular, the nonresidential audit sub program shall incorporate benchmarking, which is a complementary action for a building that is already in the process of accounting for its energy usage and remaining efficiency opportunities.

Increasing benchmarking activity does not appear to be a significant cost concern. In response to a July 2009 ED staff data request, the utilities report proposed benchmarking budgets for 2010-2012 of $1. 3 million for PG&E, $800,000 for SCE and $315,000 for SDG&E. PG&E reports that they have already benchmarked some 1,750 buildings in their service territory, and that they expect that with their budget they can achieve benchmarking of some 20,000-50,000 buildings during the 2010-2012 program period. PG&E has benchmarking software programs-the Automated Benchmarking Service Tool-in place already. SCE is further behind in applying updated software programs to its benchmarking work, but does report a goal of some 3,500 buildings for the 2010-2012 period. SCE reported in its data request a budget need of approximately $9.3 million to benchmark approximately 85,600 buildings in its service territory. SDG&E reports that they have already benchmarked some 350 buildings with a similar Automated Benchmarking Tool, and that they can achieve 5,000 - 20,000 buildings during the 2010-2012 program period.

We applaud PG&E for making progress on benchmarking and encourage both PG&E and SCE to set a benchmark goal of 50,000 commercial and institutional buildings for the next program cycle. SCE is directed to model PG&E's cost-effective approach on benchmarking and to benchmark 50,000 buildings at a per unit cost that approaches that of PG&E during the 2010-2012 program cycle. SDG&E is directed to benchmark 20,000 commercial buildings in the 2010-2012 program period. For these efforts, we approve PG&E's benchmarking budget at a total of $1.3 million, and direct SCE to increase its benchmarking budget to from $800,000 to $4.8 million, a $4.0 million increase to provide for benchmarking for all commercial, institutional and government buildings included in the 50,000 building target. We approve SDG&E's benchmarking budget for $315,000. We direct all utilities to collaborate on the use of automated benchmarking tools to achieve economies of scale and consistent benchmarking services statewide. We expect any cost savings to be applied to benchmarking more buildings.

We are aware that EPA's Portfolio Manager addresses perhaps half of the common commercial building types in California. We direct the utilities to use the updated benchmarking guidelines as developed by the California Energy Commission under their activities to implement AB 1103. The Energy Commission is developing a California Specific Benchmarking Energy Rating which includes broader building types and the ability to compare buildings with similar energy codes, legislation, and climate conditions. This should allow for a larger range of building to be benchmarked in a meaningful way.

5.3.2. Local Programs

Commercial sector local programs are designed to enhance statewide programs while utilizing local avenues for implementation and innovation. Local utility programs in the commercial sector focus on: innovative financing tools, Integrated Demand Side Management, energy efficiency measure adoption, and energy efficiency audits. Financing assistance is a large focus of utility local programs, and provides a unique opportunity to stimulate higher levels of customer participation by enabling access to funds for energy efficiency projects by offering zero-interest installation. Local financing programs include PG&E and SDG&E, and SoCalGas On-Bill Financing programs (OBF), and SCE's Financial Solutions program. SCE's Financial Solutions program includes the following components: non-residential on-bill financing; non-residential third-party energy efficiency loan programs; AB 811 energy efficiency for cities and counties; and, a financial services working group. The OBF programs and SCE's Financial Solutions program are discussed in the Section 6.2 of this decision.

The remaining two local commercial programs are the SDG&E and SoCalGas Local Non-Residential BID and Local Strategic Development & Integration programs. These local commercial programs address demand-side management integration, audits, energy efficient measures, and strategic planning. The BID program is a two-part, continuing program, and customizes incentives to cater to the needs of diverse non-residential market segments. One component of this program allows customers to propose specified incentive levels for measures associated with an energy efficiency project. Another component of this program addresses upfront cost barriers for large, long-lived energy efficient equipment in non-residential markets.

The Local Strategic Development & Integration program is a new program which focuses on aligning utility programs with the Strategic Plan. This program is led by an internal utility group, whose main purpose is to collaboratively work with internal and external participants and stakeholders to ensure current program and program planning support the Strategic Plan.80

Both of these local programs enhance the statewide programs described earlier in the commercial section, and aid the existing efforts to make progress on the Strategic Plan. These local programs promote IDSM and focus implementation on the unique needs of the local customers. We approve these programs with a few modifications to enhance program impact. First, we direct that all local utility programs adopt the benchmarking recommendation included in the commercial statewide program.81

Second, SDG&E and SoCalGas should include in their updated Program Performance Metrics a description of an integrated internal management and evaluation structure that will ensure increased coordination and information sharing between these local and the statewide commercial programs, both within utility and between utilities. This integrated management structure should involve the use of real-time data to inform management, improve current programs, and enhance the design of future programs.

5.3.3. Third Party Programs

The utility applications include 58 third-party commercial sector programs across the four utilities. Third party programs are an opportunity for utilities to utilize third party contractors to help implement local and statewide program components, and to target unique programs that focus on deep energy savings in niche markets. Successful third party programs that attain deep energy savings will either be continued as third party programs in the following programs cycle, or components and lessons learned from these programs will be transitioned into statewide programs. A list of third-party programs per utility can be found in Appendix 1.

There were no party comments filed for commercial third party programs. With a few specific programs modifications outlined below, we approve the utility commercial third party programs.

        5.3.3.1. SCE Automatic Energy Review for Schools

The SCE Automatic Energy Review for Schools (AERS) program is designed to increase the energy performance of new and modernized school buildings by utilizing the Division of State Architects (DSA) review and approval process.82 The program will work with DSA staff to flag and refer projects that just marginally exceed the state energy code. In many instances, AERS is trying to have influence in a process, where the design is hardened, and efficiency opportunities are limited.

This program can fill a gap in public sector energy efficiency work. We approve this program, and direct SCE to ensure appropriate evaluation work to track progress and problems solved by this program. The data that is tracked should also be used to inform the design process so that problems can be cost-effectively addressed early, before the DSA gets involved. In addition, the number of projects that choose AERS as suitable instead of SBD and CHPS should be collected. Obtaining data on the AERS program will capture important lessons on program usage and help inform program design to ensure that the AERS can be phased out. This data should be analyzed by SCE at the end of this program cycle to determine if this program will continue.

5.3.3.2. SCE Sustainable Portfolios

The SCE Sustainable Portfolios program targets significant energy, water, waste and greenhouse gas (GHG) reductions in the difficult market of leased commercial office space. This program seeks a sustainability commitment from a variety of actors including real estate owners, investors, and tenants, and will focus on leased buildings with floor space larger than 100,000 sq. ft. Sustainable Portfolios incorporates audits, sustainable implementation plans with budgets/schedules, technical assistance, verification of performance, financial incentives from utility programs, other financing options to cover the remaining costs, and assistance in purchasing equipment to achieve sustainable practices. Additional program components include an array of standard measures, a desire to incorporate the "Go Green" marketing practice, incorporation of a Green Leasing kit, and a variety of less common approaches to incorporate broader sustainability strategies.

Sustainable Portfolios is an innovative program as leased building space programs face notoriously difficult "split incentive barrier" between the owner of a building and tenants that make energy efficiency more difficult. SCE has designed both this program and the Management Affiliates Program, to increase diversification of implementation efforts, and create lessons learned and best practices.

This program has ambitious sustainability goals, with assistance at the technical, financial, and implementation level, but is lacking a clear strategy to achieve its program related outcomes. We are concerned that the program as designed, could lead to an unsuccessful effort as it attempts to addresses too many areas. We approve the Sustainable Portfolios program as a pilot program only. We believe the program is innovative and focuses on an important market subsegment, but we recommend that it take a more defined approach, similar to the SCE Management Affiliates Program.

As a pilot project, we will require SCE to submit via advice letter additional information on the Sustainable Portfolios program as required of all pilot projects and as outlined in Section 4.3 above. The advice letter should include Program Performance Metrics to track progress within this program such as: 1) the number of whole building projects for which the pilot achieves deep energy savings investments; and, 2) the number of standard construction projects with an Energy Star score of 90+. This advice letter should be filed within 120 days of the adoption of this Decision.

We approve the utilities' proposed residential and commercial construction programs with modifications. For residential new construction, we reduce SCE, SDG&E and SoCalGas' budgets to reflect the severe downturn in the new residential construction market, and require SDG&E to include a manufactured home program in its portfolio. For commercial new construction, we require the utilities to add a benchmarking component to their Savings by Design program.

5.4.1. Residential New Construction

D.07-10-032 set a target that all residential new construction in California should be zero net energy83 by 2020. The Strategic Plan elaborated on the tactics and coordination efforts necessary to improve state building code to zero net energy levels by 2020. The CEC endorsed the goal of incorporating ZNE in state-wide buildings codes by 2020 in its 2007 Integrated Energy Policy Report.

The Strategic Plan contains an interim milestone for 2011 that 50% of new homes exceed 2005 Title 24 standards by 35%, and 10% of new homes exceed 2005 Title 24 standards by 55%. The Strategic Plan makes clear that these interim milestones for residential new construction are purposefully aggressive "...to capture the imagination and spark the enthusiasm of all who participate in transforming residential new construction to ultra-high levels of energy efficiency." The Strategic Plan identifies many of the strategic partnerships and actions the utilities should immediately pursue to achieve the next set of interim milestones in 2015 such as advancing technological innovation through collaboration with the Energy Commission, PIER, the Emerging Technologies Programs, Lawrence Berkeley National Laboratory (LBNL), National Renewable Energy Laboratory (NREL), California Building Industry Association (CBIA), and other appropriate organizations.

The utilities filed a single statewide New Construction program which encompassed both Commercial and Residential New Construction (RNC). This program is designed with the goal of achieving the interim milestones in the Strategic Plan. Within RNC, two subprograms were proposed; the California Advanced Home Program (CAHP) and the ENERGY STAR® Manufactured Homes (ESMH) program.

Table 17-Residential New Construction Program Budget and Savings

Residential New Construction Statewide Programs

 

Budgets

kWh

KW

Therms

PG&E

$28,450,244

11,956,748

14,111

1,273,504

SCE

$28,410,000

6,418,460

5,929

0

SDG&E

$8,068,590

870,546

1,045

110,040

SoCalGas

$12,242,980

16,752,120

18,427

837,606

Total

$77,171,814

35,997,874

39,512

2,221,150

         

The programs, by utility, characterized in the table above include:

· PG&E,84 SCE, SoCalGas: California Advanced Home Program, Energy Star Manufactured Home Program.

· SDG&E: California Advanced Homes Program.

CAHP encourages single and multi-family builders of all production volumes to construct homes that exceed California's 2008 Title 24 energy efficiency standards by a minimum of 15 percent. In this program, multi-family, single-family, and low-income projects are approached identically. CAHP is proposed as a redesigned program continuation from 2006-2008 and attempts to address some key barriers identified by internal program evaluations. Specifically, the CAHP program proposes to improve the demand for high efficiency homes by assisting builders with marketing efforts and leveraging consumer awareness of "green" products rather than re-educate in terms of efficiency. Further, the CAHP aligns its participant entry point (15% above code) with that of the New Solar Homes Program, administered by the California Energy Commission.

A major innovation in the residential program proposal is to use the calculated incentive structure used by the "Savings by Design" Commercial New Construction program. The incentive structure sets an incentive rate per unit of energy ($/kW, $/kWh or $/Therm) as a function of the percentage by which the project exceeds code. In this way, each kWh at 35% better-than-code is offered a greater incentive than each kWh at 15% better-than-code. This incentive structure is designed to drive builders to find the least cost methods to achieve the highest levels above code. The incentive amounts are designed to cover approximately 50% or more of the incremental cost of building above code.85

Finally, the CAHP program is designed to achieve the aggressive interim milestone of half of all homes built in 2011 reaching 35% above the 2005 state building code, Title 24.

In each service territory except SDG&E, the Energy Star Manufactured Homes subprogram will be implemented, representing less than 5% of the RNC budget or $5.5 million. This is an upstream program that provides incentives to manufactured home builders to improve efficiency at the design stage to meet Energy Star standards.

The June 9, 2009 Ruling asked: "Given that the number of permits for new home construction is at its lowest level in 10 years, and that the Strategic Plan sets an interim milestone of 50% market penetration of above-code homes for 2011, should the utilities scale back funding parallel to the market or, could increasing incentive levels (while keeping the same proposed budget) be the least cost path to achieving the Strategic Plan target?"

TURN and DRA recommended that the Commission reduce the proposed budget for all of New Construction given the economic climate and housing downturn. TURN suggested that during this program cycle, the utilities develop an integrated demand side management new construction program incorporating demand response, energy efficiency, and distributed generation programs.86

NRDC recommends that the financial incentive for builders to achieve 30% above 2008 Title 24 be raised above $3,000 in order to attract a higher level of penetration to more likely meet the Strategic Plan interim milestone of 50% market penetration for Tier II homes by 2011. Bacchus suggests that in this depressed housing market, there is a major opportunity to intervene and alter building practices. He recommends that the utility budget be kept the same and that higher incentive levels be used to achieve the efficiency targets.

CBIA states that the Construction Industry Research Board (CIRB) predicts new single family housing starts in 2009 to be 23,600 homes-the lowest number of housing starts since 1980 by a factor of two. Further, they claim that an industry review of the 2009-2011 residential new construction March 2 program filing estimated the proposed incentive cost coverage for above code energy efficiency features at less than 30%. CBIA states that they are confident utility incentives will not change market behavior until the incentive levels covered exceed at least 70% and recommended that the utilities increase incentive payments accordingly in order to achieve the Strategic Plan goals.87

Schweitzer contends that reduced program funding would result in lower market penetration, alluding that this action was counterproductive during a cycle where the Strategic Plan interim milestone targets expanded penetration. They recommend that the utilities increase incentive levels for their residential new construction program based on this logic.

SDG&E and SoCalGas disagree with TURN and suggest that abandoning the new construction market during a down period would create major lost opportunities because builders are looking to differentiate themselves by marketing their product as green. SCE states that the economic climate did not change their goals or the interim Strategic Plan milestones, and thus they cannot reduce their attention to the market during this slowdown. SCE and SDG&E/SoCalGas present an analysis which used a housing start forecast from Moody's which projects over 44,000 new home starts in 2009 and over 90,000 in 2011. Based on the Moody's forecast, SCE and SDG&E/SoCalGas contend that the program budget is correctly sized and that neither increased incentives nor a reduced budget is appropriate.

In its July 2, 2009 filing, PG&E reduced its funding proposal by 58%, from $64 million to $27 million for 2009-2011. PG&E cites the recently published Residential New Construction Market Effects Phase I Final Report that did not recommend increasing incentive levels, but rather increased marketing.

CBIA supports the proposed structure but suggested a step up at the New Solar Homes Partnership Tier 2 level (30% above 2008 Title 24) to a significantly greater calculated incentive. CBIA states that this step increase in the incentive offered "...would greatly facilitate moving participants toward better (energy efficiency) building practices (and) moving the market toward this level as a standard." CBIA argues that this bonus level should cover 85% of the incremental cost of building to the NSHP Tier 2 level.88

We find that the program plans for the residential portion of the statewide new construction program provide a strong plan to move the market with incentives, design assistance, and added marketing. We approve the utility plans for the Energy Star Manufactured Homes program and the California Advanced Home Program with the modifications below. With these modifications, the utilities' budgets would be modified as shown in Table 18.

Table 18-Modified Residential New Construction Budgets

RNC Programs

Proposed Budget (Millions)

Modification

Approved Budget (Millions)

SCE

      

CAHP

$24.9

($ 7.47)

$17.43

ESMH

$3.5

  

$3.5

PG&E

      

CAHP

$27.0

  

$27.0

ESMH

$1.4

  

$2.0

SoCalGas

      

CAHP

$12.2

($3.9)

$9.1

SDG&E

      

CAHP

$8.1

($3)

$9.7

ESMH

0

$0.41

$0.41

RNC Totals

$77.2

$13.96

$63.24

The Big Bold Programmatic Initiative target for zero net energy residential new construction in 2020 catalyzed the industry by generating discussion and aligning planning resources. Since California's adoption of the ZNE goals, Massachusetts has set a similar target for all commercial and residential buildings and new construction by 2030.89 As noted above, the CEC shares the goal of zero net energy residential new construction for Title 24 in 2020. Title 24 code update cycles typically occur every three years and build upon the progress within the market for new practices and building materials. As described in detail in the Residential chapter in the Strategic Plan, only three code update cycles exist between 2009 and 2020 during which utility programs and other market forces are to raise awareness among builders and push adoption of more efficient building practices. Achievement of such a challenge will require a strong start during this program cycle. With each code update we commit to revising the reference used to describe the goals of the Strategic Plan. We do so here by re-defining the interim milestones based upon current 2008 Title 24 building code90 such that the interim milestones for 2011 are:

· 50% of new homes exceed 2008 Title 24 standards by 20%

· 10% of new homes exceed 2008 Title 24 standards by 40%

We agree with TURN that the current housing market provides considerable uncertainty. This is evidenced by the significantly different housing start estimates cited in the record, ranging from 23,600 to 44,000 housing starts in 2009. Given this substantial uncertainty, the utility budgets should be decreased to prevent unnecessary collection of ratepayer funds in the event that housing starts remain at low levels. Accordingly, the utilities (other than PG&E) shall reduce the size of their CAHP program budgets from their July 2, 2009 filing by 30%. The utilities may submit mid-cycle budget augmentation requests for the CAHP if the market demand outstrips available program funding.

Financial incentives, although not a panacea, do act in concert with outreach and education to bring increased program participation. In their filing, the incentive levels proposed for CAHP were stated to be designed to cover approximately 50% or more of the incremental cost of above code construction. We agree with multiple parties that the decreased volume in this historically low market offers a unique opportunity to partner with production builders. We direct utilities to support transformation of the residential new construction market using a diverse set of program outreach and retention tools, including attractive incentive levels. We support utility proposed per-unit (kWh, kW, therm) incentive levels at 50% of the incremental measure cost and we direct utilities to ensure that incentives meet this level for projects at 20% and above for Title 24 2008. The threshold for participation may remain at Tier 1, or 15% above code.

The utility CAHP proposal also included a series of "performance bonuses" for specific actions rather than design efficiency. We agree with CBIA that to achieve efficiency gains of the scope described by the Strategic Plan, utility programs must not only blanket the market for incremental improvements, but also sow the seeds of significantly advanced construction improvements that will become widespread in the 2012-2014 program cycle. We direct utilities to offer a performance bonus (in addition to the sliding scale incentive determined under the calculated incentive structure) to be offered for participants who design homes to surpass Title 24 at the New Solar Home Partnership Tier 2 level of 30% above the 2008 Title 24 standards. We direct the performance bonus to be set at $1,000 per unit and authorize the utilities to review this level in 2011 in consideration of market conditions, cost-effectiveness, and equity. The utilities shall coordinate their CAHP performance bonus for solar hot water with the Energy Division's proposed CSI Thermal Energy program, authorized by AB 1470.

The CAHP program proposed that achievement of the Strategic Plan interim milestone for RNC, e.g. half of all homes built in 2011 reaching 35% above 2005 Title 24, was transferable to achievement of a fixed level of savings. The utilities argued that 100% of the market at 15% better than 2005 code is the equivalent of 50% of the market being 35% better than 2005 code. We disagree. The purpose of the interim milestone is to set the stage for proportionately higher levels of efficiency in each successive Title 24 update in order to meet the 2020 goal, not to achieve a specified number of kWh savings. The 35% level of efficiency sets a reasonable baseline for the next interim milestone, whereas, a 15% milestone will make the achievement of the next interim milestone correspondingly more difficult. Therefore, making 50% of new homes achieve 35% above code does more to advance the goal of reaching ZNE in codes by 2020 than making 100% of homes 15% more efficient.

The ESMH program addresses a segment of the residential market that has historically been a lost opportunity. As proposed by SCE and PG&E, this program provides relatively comprehensive savings. SDG&E failed to provide justification for omitting the statewide Energy Star Manufactured Homes program offered by SCE and PG&E. We find that this program would be a benefit to the ratepayers of SDG&E and direct SDG&E to include the ESMH program in its 2010-2012 portfolio. PG&E's ESMH budget is approximately 5% of its CAHP, therefore, we approve an equivalent budget of $410,000 for SDG&E.

5.4.2. Commercial New Construction

We approve the utilities' statewide commercial new construction programs with a modification discussed below. We also direct the utilities to participate in a "Path to Zero" series of workshops, facilitated by Energy Division.

Commercial new construction is one of the three Big Bold Programmatic Initiatives, outlined in the Strategic Plan's ZNE goals. As directed in D-07-10-032, "100% of newly constructed commercial buildings will be zero net energy by 2030."91 To assist in this effort, utility programs must incorporate integrated design that reduces market barriers and results in high performance buildings.

The utilities' Commercial New Construction program employs the existing Savings by Design (SBD) program for commercial buildings. SBD encourages use of a whole-building design approach and a systems approach to achieve energy efficiency and green building practices significantly better than Title 24 code. SBD is implemented through strong coordination among the utilities, and with the Sacramento Municipal Utility District. The utility SBD proposals include: feasibility studies, pilot projects, training, peak load reduction incentives, integrated design incentives for the design team, sustainability incentives (linked to various green programs), commissioning and monitoring of energy performance at the individual building level. Since SBD is an ongoing state-wide program, it has brand name recognition, effective management, a mechanism for working with chains/franchises, and good leverage with partners beyond the utilities. The SBD program has addressed utility coordination and IDSM through interaction with California Lighting Technology Center, using the Office of The Future Project to advance demand response and integration of photovoltaic systems in the whole building approach.

Table 19-Commercial New Construction Program Budget and Savings

New Construction Programs - Savings by Design

 

 

Budgets

kWh

KW

Therms

PG&E

$24,720,178

46,169,377

14,339

119,190

SCE

$49,245,000

124,324,393

25,908

0

SDG&E

$16,397,205

18,974,772

6,849

856,647

SCG

$7,737,262

34,648,380

3,811

1,732,419

Total

$98,099,645

224,116,922

50,908

2,708,256

 

In the June 9, 2009 Ruling, parties were asked to provide feedback on a "Path to Zero" Task Force for commercial buildings as called upon in the Strategic Plan. Party comments favor the Energy Division proposal of a "Path to Zero" Task Force for commercial buildings. PG&E notes that in order to have a success ZNE Pilot Program, all relevant stakeholders must be engaged including: "publicly owned and investor owned utilities; developers, architects, builders, municipalities, and redevelopment agencies; the CEC PIER program; the U.S. Department of Energy (DOE) National Laboratories (National Renewable Energy Laboratory, Lawrence Berkeley National Laboratory, etc.); professional building and trade associations; research institutions; state, federal, regional and local agencies; and the CPUC" (p.19).

NRDC also supports the "Path to Zero" Task Force proposed by the Energy Division, but notes collaboration with the Energy Commission is vital for successful ZNE outcomes given the size and energy usage of commercial buildings. NRDC suggests this task force should begin by identifying a "workable definition of zero-net energy commercial buildings," and include a directive for the task force to "evaluate all cost-effective energy efficiency measures before integrating electricity generation into building design" (p. 10).

SCE also believes a "Path to Zero" Task Force is needed, but cautions that the utilities already have a general statewide task force for commercial new construction and duplication of efforts should be avoided. SDG&E concurs with SCE on the need to assess existing efforts and strongly recommends identifying the gaps between the SBD and ZNE objectives before moving ahead with a "Path to Zero" Task Force. DRA/TURN are supportive of a "Path to Zero" Task Force and envision this as a worthy long term strategy, but state efforts should be focusing more towards existing buildings which are larger in scope than new building in the current commercial real estate market.

The June 9, 2009, Ruling also asked for comments on the proposal to integrate benchmarking92 tools for all commercial buildings. Reply comments filed on June 29, 2009 demonstrated party acceptance of benchmarking for both commercial existing and new construction buildings and the value it brings to understanding a buildings energy performance. Without accurate data on how a building is performing it is difficult to track progress on the goals the CPUC has set forth in D-07-10-032. Achieving 100% of ZNE new construction commercial building by 2030 will be challenging without data to monitor and report on progress.

The SBD program is an innovative program with the necessary components to assist California in achieving maximum energy savings in commercial new construction. SBD presents a holistic approach to support the Strategic Plan and ZNE goals through innovative tools, integrated design, training, and code assistance.

While SBD has key innovations, we find two areas where modification in the proposed 2009-2011 energy efficiency program cycle is needed. One area, which is both consistent with both party comments and commercial statewide programs is benchmarking.

We direct the utilities to benchmark all new SBD programs and to use the updated benchmarking guidelines as developed by the California Energy Commission under their activities to implement AB 1103. We are aware that EPA's Portfolio Manager addresses perhaps half of the common commercial building types in California. The CEC is developing a California Specific Benchmarking Energy Rating which includes broader building types and the ability to compare buildings with similar energy codes, legislation, and climate conditions. This should allow for a larger range of building to be benchmarked in a meaningful way.

Utilities should submit annual reports on their benchmarking data to the Commission and make these reports available to the public. These reports will be used by the Commission to understand how the utilities are making progress on their new construction and benchmarking goals. In addition, utilities will be able to use these reports to market their energy efficiency programs, as well as convey the benefits of benchmarking buildings as a way to compare and increase energy performance.

Once SBD projects are benchmarked and energy use indices are accessible, energy modeling outputs should be used to inform the SBD program and ensure that the current program strategies are effective in impacting operations and occupant choices on energy use. Poor performing buildings should be reviewed and directed towards commissioning services.

            5.4.2.2.2. Path to Zero

Party comments strongly favor the establishment of a "Path to Zero" or Zero Energy Pathway (ZEP) Task Force and agree that such an effort could play a critical role in achieving utility, agency and private sector engagement in the Strategic Plan's zero energy goals for the commercial building sector. We therefore direct the Energy Division to collaborate with the utilities and a broad range of non-utility actors to initiate a statewide "Path to Zero" workshop process for commercial buildings, following the party suggestions presented above, by the end of calendar year 2009. Specifically, the utilities, Energy Division and other agencies and stakeholders in this process should focus on prioritizing Strategic Plan milestones, identifying the key actions required to achieve those milestones and building broad industry support necessary to realize the larger Strategic Plan vision and goals. Energy Division should include Path to Zero in the Strategic Action Plan Progress Report and updates described in Section 12.

Energy Division will also use lessons learned from the "Path to Zero" process to inform ZNE initiatives in the Residential sector, as many of the policy, research, education, and technical areas will be transferable. Coordinating on zero net energy will provide California and the utilities with the leadership and expertise to advance Strategic Plan goals on commercial, residential and integrated DSM.

We approve PG&E's Zero Net Energy Pilot at the budget level of $25 million on a pilot basis. We approve SCE's ZNE Test Center at $2.4 million and require SCE to hold stakeholder workshops to discuss and take input on this project. We approve SCE, SDG&E and SoCalGas Sustainable Communities programs on a pilot project basis only, at the levels of $14 million, $960,000 and $800,000 respectively. We do not approve PG&E's Zero Energy Lab or Demonstration Home, budgeted as a capital costs for the 2010-2012 period at $640,000.

In D.07-10-032 and D. 08-09-040 we adopted ambitious ZNE goals as part of our Big Bold Programmatic Initiatives and the California Long Term Energy Efficiency Strategic Plan. Achieving ZNE in all new residential construction by 2020, and all new commercial by 2030 will be challenging and require increased collaboration with industry, government and utilities. The utilities have presented a variety of approaches to reach these goals through research, demonstration and integration of ZNE principles and activities into their current portfolio. They have allocated resources for ZNE projects in their Emerging Technology statewide program, as well as local, and third party programs. The utilities propose to advance technical expertise and lessons learned through implementation of ZNE field based projects.

Table 20-Zero Net Energy Program Budget and Savings

Zero Net Energy Programs

 

 

Budgets

kWh

KW

Therms

PG&E: Zero Net Energy Lab/Demo Home (capital cost)

$638,848

0

0

0

PG&E: Zero Net Energy Pilot

$30,697,168

0

0

0

SCE: Technology Test Centers

$2,437,000

0

0

0

SCE: Sustainable Communities

$14,254,000

0

0

0

SDG&E: Sustainable Communities

$964,081

0

0

0

SCG: Sustainable Communities

$828,450

0

0

0

Total

$49,180,699

0

0

0

 

PG&E proposes two program initiatives to advance ZNE concepts and build ZNE homes. One of these initiatives is a ZNE Lab and Demo Home, which PG&E placed in their Emerging Technology statewide program. The other is a PG&E Local Zero Net Energy Pilot Program. Both initiatives are described below.

            5.4.3.1.1. PG&E ZNE Laboratory/ Demonstration Home

PG&E proposes to create a ZNE laboratory to be operational by 2011 to test ZNE measures and their integration within buildings. The proposed lab would provide independent verification of the performance and energy savings of technologies with potential to help meet ZNE goals, and would support appropriate design of ZNE codes and standards. PG&E also proposes to build a ZNE Demonstration home to allow integrated ZNE technology evaluation, training, and educational visits. The proposed ZNE Demonstration home would be operational by 2011. An operational budget to manage the ZNE Demonstration home was included in PG&E's proposed local ZNE Pilot Program, discussed below.

The proposed ZNE Laboratory/Demonstration Home are both proposed as capital costs. We do not believe that this is the appropriate way to fund the proposed activities and we decline to approve these capital costs. Capital costs are discussed further in section 6.3.

          5.4.3.1.2. PG&E Local Zero Net Energy Pilot Program

PG&E proposes a ZNE Pilot Program to conduct building research, development, and demonstration (RD&D) projects. The proposed pilot aligns with the Strategic Plan implementation plan and timeline, aiming to "push" the development of long-term (2016 - 2030) cost-effective technologies to the market while "pulling" customers towards the adoption of long-term advanced energy efficiency technologies and practices.

The pilot proposes to engage in whole building research, development, and demonstration projects that meet the California Energy Commission's New Home Tier II requirements and that include on-site clean distributed generation. PG&E proposes that the pilot build on foundations laid in the statewide CAHP and SBD programs93 to provide a clear linkage to mid-term (2012-2015) and long-term (2016-2030) Strategic Plan milestones. The purpose of the proposed pilot is to advance understanding of the linkages between ZNE buildings and land-use planning issues like building orientation, compact planning, transit oriented development, advanced and efficient district heating and cooling systems. The ZNE pilot program will also target low and moderate-income communities. The proposed PG&E ZNE Pilot Program consists of four subprograms.

Table 21-Summary of PG&E ZNE Pilot Program components

Subprogram

Total Budget

1. ZNE Communities

$ 10,221,314

2. ZNE Demonstration Showcase

$ 6,451,232

3. ZNE Technology Advancement

$ 7,674,291

4. ZNE Design Integration

$ 6,350,331

Program Total

$ 30,697,168

Note: Allocation of the ZNE Pilot subprograms was decreased

incrementally from the March 2, 2009 filing to $30 M.

PG&E proposes $30 million for the Zero Net Energy Pilot Program not including the capital costs discussed above (totaling $639,000 and placed in PG&E's statewide Emerging Technology program budget). Below is a description of the four ZNE Subprogram components: ZNE Communities, ZNE Demonstration Showcase, ZNE Technology Advancement, and ZNE Design Integration.

The PG&E ZNE Communities Subprogram will offer design assistance and technical support to teams considering commercial or residential projects. It will target mixed-use complexes, multi-family complexes, advanced residential new construction, advanced commercial new construction, compact development, and transit-oriented development at the early stages of the entitlement and design process, helping to capture energy and resource savings that would normally fall outside of the scope of a typical project.

The Communities Subprogram will provide cost-sharing for commissioning to achieve ZNE status; recommend operations and maintenance procedures to maintain buildings at a ZNE level; assist with the development of ZNE building owners' manuals; and, prepare and publish case studies. The program will offer developers the opportunity to participate in scaled field placements of ZNE technologies developed within the Emerging Technologies statewide program. The subprogram will coordinate with utility codes and standards programs on methods to achieve ZNE levels within California's Title 24 building code.

The PG&E ZNE Program Demonstration Showcase Subprogram has three key elements: 1) the administration and operation of the proposed ZNE Demonstration Home and Laboratory; 2) a series of commercial and residential demonstration projects; and 3) case studies and performance monitoring and assessment of existing passive, low energy, and ZNE buildings. As discussed above, the ZNE Showcase Subprogram includes an operational budget to operate the proposed ZNE Demonstration Home. The ZNE Demonstration Showcase Subprogram would initiate a series of third-party demonstration residential and commercial projects. PG&E proposes to provide detailed technical assistance, design assistance, and cost sharing of advanced energy efficiency measures for developers and design teams interested in building cutting edge homes and commercial buildings. In exchange for this assistance, after the design and construction is complete, each home and building would be made available for visitation by the public, published as a case study, and subjected to performance verification and assessment.

The PG&E ZNE Technology Advancement Subprogram will deliver information, insights, analytical tools, and resources to accelerate and expand the commercialization of innovative technologies as stated in the Strategic Plan.

The PG&E ZNE Design Integration Subprogram will develop and disseminate information on best practices for the design of ZNE communities, buildings, and homes by engaging relevant organizations and offering assistance to planning and code officials who are in the process of reviewing proposed ZNE buildings and development. This subprogram will produce best practice guidelines and software tools to design and evaluate "beyond-code" projects.

PG&E's proposed ZNE Pilot Program subprograms directly address needs identified within the Strategic Plan for accelerating California's progress towards the 2020/2030 ZNE goals. However, as with other pilot programs we found that the application did not provide sufficient discussion of the methods by which the pilot will be evaluated and lessons learned would be disseminated to core utility programs as well as other key actors on ZNE within California. In particular, any ZNE program should consider how the best practices and technologies will be translated to benefit the existing buildings markets. In addition, key milestones, timelines and an end date for the pilot was not identified. We also declined to approve the ZNE Demonstration Home capital costs, and therefore an operational budget for such a home is not needed.

Therefore, we conditionally approve PG&E's ZNE Pilot Project at the level of $25 million on a pilot project basis only, a $6 million decrease from the requested budget. As a pilot project, we require PG&E to submit via advice letter additional information on the ZNE Pilot Program as outlined in Section 4.3 above. The advice letter should be filed within 90 days of the adoption of this Decision.

SCE proposes two program initiatives to advance ZNE concepts and experience. One is the SCE Technology Test Center (TTC); the budget for this initiative was placed in SCE's Emerging Technology statewide program budget. SCE's second ZNE initiative is the non-residential third party program, Sustainable Communities. Both programs are described below.

The SCE Technology Test Center is comprised of three test facilities focused on distinct end uses: Refrigeration, Air Conditioning, and Lighting. For the 2009-2011 program cycle, SCE proposed to add a fourth test facility to advance ZNE residential and to a lesser degree commercial ZNE goals, funded at the level of $2.4 million. This facility, a ZNE Test Center, will be used to investigate the viability of integrated energy efficiency, demand response, smart meters, and on-site renewable generation in ways that meet builder and occupant needs. It will be designed as a flexible facility to accommodate a range of different envelope, space conditioning, lighting, plug-load, and renewable technologies. The ZNE Test Center will provide the opportunity to examine these technologies on a system level.

We approve the SCE Technology Test Center. The center meets several of our Strategic Plan goals by acting as an educational and research facility that will also be used to contribute to proposed codes and standard test procedures. We further direct SCE to hold public stakeholder workshops that include invitations to investor owned and public utilities, Energy Division, local governments and other interested parties, to receive information on and provide input into the strategic decisions surrounding ZNE technology testing within the facility. We direct SCE, with insights gained at these workshops, to produce a plan to disseminate best practices and lessons learned at the facility, and to provide this plan to Energy Division by June 2010.

            5.4.3.2.2. SCE Sustainable Communities

The Sustainable Communities program is a non-resource program that includes early stage design assistance and community-scale development. The proposed budget for this program is $14.3 million, with approximately 75% to be used to fund consultants to provide design assistance.

The Sustainable Communities Program focuses on sustainable design interventions and notes the importance of tracking influence of the program on measures SCE cannot claim energy savings on, such as: water conservation, reduction in vehicle miles traveled, secondary energy benefits, on-site water retention, and waste diversion. The program proposal states that these non-resource benefits are important sustainability indicators, and that it is useful to track program impacts on them to guide future program design. As a pilot project, lessons learned should inform integrated progress towards the statewide ZNE commercial and residential goals.

As proposed, the SCE Sustainable Communities program did not fully explain the methodology it will use to advance ZNE and integration concepts within community scale development projects. As described, the outcomes of the program did not clearly link to its stated goals, and the program plan did not appear fully representative of the proposed program scope. The Sustainable Communities program attempts to accomplish a large scope of activities; it may be more successful if the sustainable design components of the proposed program were moved to programs that specialize in these areas such as SBD and CAHP. The program proposal does not provide sufficient information on the selection and oversight mechanisms for the sustainable design consultants. However, the program appears innovative and that it will yield useful information on integrating water/energy/land use decisions in ZNE community scale projects.

We approve the SCE Sustainable Communities on a pilot project basis only, and direct SCE to file an advice letter containing all information requested from pilot projects as outlined in Section 4.3. This advice letter shall also identify clear program targets and indicators such as: the number of LEED buildings it will result in; and the number of individual ZNE sub-projects that it will advance. The advice letter shall also describe SCE methods to ensure dissemination of lessons learned from the pilot to all utility core programs and to other entities statewide.

SDG&E and SoCalGas propose a local residential ZNE Sustainable Communities program to advance ZNE goals. This program will intervene at the community planning stage to ensure the inclusion of ZNE technologies in sustainable communities development projects. Program components include:

· Program training for builders and contractors on sustainable design and construction practices.

· Development of `learning center kiosks' for residential education of sustainable communities.

· Design assistance to engineers and architects to foster the incorporation of sustainable features into projects.

· Development of modeling procedures so that residential builders can demonstrate energy performance improvement of their projects to document participation in the program.

· Development of a comprehensive community modeling tool to track a wide range of sustainable community development impacts, and to share this information through case studies.

The main targets of this program are community developers, with a number of the mechanisms oriented toward building-specific market players.

The goals of this program align with our adopted ZNE goals. However, key information on comprehensive and concrete, measureable objectives and other program criteria are missing. We approve the SDG&E/SoCalGas Sustainable Communities proposal on a pilot project basis only, and direct SDG&E/SoCalGas to file an advice letter containing all information requested from pilot projects as outlined in Section 4.3. This advice letter shall also identify clear program targets and indicators such as: the number of buildings it will result in; specific energy savings or sustainable design features; number of new communities participating in the program and specific performance goals for the individual projects within the community; transportation impacts, water conservation, and other resource elements. The advice letter shall also describe SCE methods to ensure dissemination of lessons learned from the pilot to all utility core programs and to other entities statewide.

5.4.3.4. ZNE and Government Buildings

With the approval of these ZNE pilot projects and programs, we require utilities to consult with, inform and advise local governments and other key entities of activities and opportunities to participate in ZNE pilots, as well as lessons learned. Local government buildings are being retrofitted through local government partnership programs; many have expressed interest in on site generation, solar photovoltaics, benchmarking, and an integrated audit, all of which are important elements of moving along the path toward zero net energy. With ZNE as a prominent theme in the Strategic Plan, and government building retrofits as major program component, 2010-2012 utility programs must begin to leverage local government facility retrofits towards long-term ZNE goals.

We approve the utilities' proposed statewide industrial programs with modifications. Specifically, we require SCE to increase its budget for Continuous Energy Improvement Program from $121,000 to $2 million.

The Strategic Plan at 42 sets forth the following visions for the industrial sector: "California industry will be vibrant, profitable and exceed national benchmarks for energy efficiency and resource management" and "industry has the capacity to significantly improve its overall energy performance and help meet both private-sector and national goals for energy and the environment." The Strategic Plan's industrial sector goals are to: 1) support California industry's adoption of energy efficiency by integrating energy efficiency savings with achievement of GHG goals and other resource management objectives; 2) to build market value of and demand for energy efficiency through branding and certification; and 3) to provide centralized technical and public policy guidance for resource efficiency and workforce training. The Strategic Plan also calls for initiatives in a fourth area -- the development of integrated energy demand side management utility programs to be initiated and tested via pilot programs.

The utilities propose a statewide Industrial Program with the following sub-programs:

· Non-residential audits -- options include remotely analyzed on-paper analysis, on-site inspections, or via a "retro-commissioning" focus on operational optimization.

· Deemed/Express Efficiency -- Rebates for the installation of specific energy efficient measures providing pre-defined incentives with prescribed energy savings.

· Calculated Incentives -- Provides technical assistance and incentives based on calculated savings for retrofit and added load applications. The proposed incentive rate is 15 ¢/kWh for AC and refrigeration loads and 9 ¢/[first year?] kWh for all other end-uses and measures. The proposed incentive for gas savings is $1 per first-year therm.

· Continuous Energy Improvement (CEI) -- A collection of strategic planning tools and resources that lay the groundwork for long-term integrated energy planning and provide a platform for launching other utility and non-utility programs and services. CEI is a non-resource sub-program.

Table 22-Industrial Sector Program Summary

Industrial Statewide Programs

 

 

Budgets

kWh

KW

Therms

PG&E

$98,303,380

310,729,721

38,194

40,726,140

SCE

$101,066,000

528,595,985

88,641

N/A

SDG&E

$41,321,235

48,288,958

8,603

3,886,105

SCG

$110,457,232

N/A

N/A

41,197,541

Total

$351,147,848

887,614,664

135,438

85,809,786

 

Industrial Third Party Programs

 

PG&E94

$85,420,959

243,405,405

29,755

8,371,597

SCE95

$53,743,999

236,580,108

29,811

N/A

SDG&E96

$4,378,775

missing

missing

missing

SCG97

$3,128,716

N/A

N/A

421,408

Total

$146,672,449

479,985,513

59,566

8,793,005

 

Total Sector Budgets/ Savings

$497,820,297

1,367,600,177

195,004

94,602,791

Table Note: for program list, see footnotes

In December, 2008, the CARB adopted a Scoping Plan to implement AB 32, California's Global Warming Solution Act. The Scoping Plan proposes an energy efficiency and co-benefits audit measure that applies to certain industrial facilities. This measure requires such facilities to "conduct an energy efficiency audit and...to determine the potential [GHG] reduction opportunities, including criteria air pollutants and toxic air contaminants." The CARB subsequently issued a proposed rule that would apply to power plants, refineries, oil & gas production/transmission facilities, cement and mineral plants, and industrial gas production facilities, which comprise only a subset of California's industrial facilities. CARB is proposing that the regulation be a general guidance for these facilities to conduct an energy efficiency audit and an assessment of energy efficiency improvement opportunities. CARB will consider this rule in October, 2009, and if adopted, the audit and assessment reports would be required for covered facilities by early 2011.

In a June 9, 2009 Ruling, parties were asked: "Given the potential value for industrial plant energy efficiency certification via a Continuous Energy Improvement (CEI) certification identified in the Strategic Plan, are utility funding levels for this program too low (currently less than 0.5 % of total industrial program funds)? Please describe how the utility CEI programs can be improved and expanded, including the role that utility programs should have in supporting the development of voluntary/mandatory energy reduction targets.

DRA and TURN recommend that since the industrial sector is a high energy use sector, the Commission should re-work the industrial program paradigm to optimize energy savings from industry and to adopt longer term strategies that are consistent with AB 32 implementation, the Strategic Plan and market transformation goals. DRA/TURN recommend that the Commission work closely with the CARB to develop new and forward-thinking approaches for industrial programs, citing programs in countries such as United Kingdom, Sweden and the Netherlands that promote voluntary industrial energy efficiency programs as part of larger national GHG emission reduction strategies.

SCE contends that "the proposed integrated energy audit and continuous improvement program (also) provides customers with concrete advice to move them towards greater long term efficiency by offering education as well as a path to enabling tools like incentives and financing." Without elaborating, SCE suggests "that the budget allocated for the Continuous Energy Improvement (CEI) sub-program provides a sufficient starting point for this offering, given the economic uncertainty that currently exists within the State. If economic conditions improve and demand for this service outstrips funding allocated, SCE can rebalance the portfolio as needed to maximize program results."

SDG&E/SoCalGas filed similar comments and added a description for how CEI will be used as an integrative, organizing framework and platform for launching the other industrial sub-programs and leverage applicable WE&T programs. In response to the question of how CEI can be leveraged to promote market transformation in the industrial sector PG&E stated that the CEI is intended to be a customizable approach used for select and motivated customers and it is not an appropriate method to address technology saturation or transformation questions.

SCE also noted that its Application specifically addresses proposals to integrate AB 32 with SCE's programs. SCE notes that a statewide Industrial Working Group has been established and is expected to continue working collaboratively on program development.

5.5.2. Discussion

We approve the proposed Statewide Industrial Program with certain modifications identified below.

        5.5.2.1. Continuous Energy Improvement Program

As discussed in the Strategic Plan, a national Superior Energy Performance partnership in the industrial sector has developed industrial plant certification standards nationally via the American Standards Institute (ANSI) and is progressing internationally, via the International Standards Organizations. California utilities have the opportunity to shape these energy management standards, and administer programs to promote CEI within the state. While the utilities proposed a CEI subprogram as part of their statewide industrial program, requested funding levels and other resources committed to this program appear insufficient relative to the magnitude of untapped efficiency potential in industry.

As submitted, the directly allocated funding for this subprogram is only $2.8 million. CEI programs primarily involve instigating systems and standards to bring about behavior change in facility-level energy management. We therefore agree with DRA/TURN who call for increased utility attention to programs that target behavior change and focus on long-term savings.98 This recommendation is consistent with the Strategic Plan recommendation to broaden utility industrial program approaches to increase focus on energy management processes.

More broadly, we are not convinced by PG&E's statement that the CEI is intended to be a customizable approach applicable only to select and motivated customers and that it is not an appropriate method to address technology saturation or market transformation questions. We believe that the utility industrial programs must be designed to contribute in a meaningful way to the goals and objectives identified in the Strategic Plan for the industrial sector as a whole, including market transformation objectives for behavioral and process energy management. It is important to make CEI programs and approaches accessible to a broad range of industrial customers in order capture a maximum amount of efficiency potential.

PG&E almost tripled its funds for the CEI program between its March and July 2009 showings, while SCE did not change its proposed budget. We believe that SDG&E and SoCalGas' proposed funding levels for the CEI is largely appropriate for the size of industrial operations in their service territories. In order to ensure consistent funding levels and opportunities for industrial customers across utility territories, we increase SCE's budget for CEI from $121,000 to $2 million for the 2010-2012 period. We further direct the utilities to jointly assess the opportunities of expanding CEI programs to all industrial sector customers, and to consult with Energy Division staff, their consultants, CEC, CARB, and industry stakeholders to develop a more robust set of industrial sector CEI programs.

Table 23-Summary of CEI Program Funding, as Proposed and as Adopted

 

March 2009 Proposed ($ millions)

July 2009 Proposed
($ millions)

Adopted Budgets
($ millions)

PG&E

.569

$1.957

$2

SCE

.121

$.121

$2

SDG&E

.601

$.740

$.750

SCG

$1.53

$1.338

$1.50

Total

$2.821

$4.156

$ 6.25

Secondly, if adopted, CARB's proposed regulation to require audits within the identified industrial sectors could increase energy efficiency opportunities identified and acted upon within those facilities. This presents both an opportunity and a challenge for the utilities' industrial programs. The regulation will identify efficiency opportunities that can be captured through utility programs, while potentially complicating identification of utility program "free-riders." We therefore direct Energy Division evaluation staff to assess the impact of any final adopted CARB industrial facility audit requirements on EM&V efforts in